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

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

         For the fiscal year ended December 31, 2000

         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 333-52664

                             BLACK HILLS CORPORATION

         Incorporated in South Dakota     IRS Identification Number 46-0458824

                                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 February 28, 2001 $843,247,880

     Indicate  the  number of  shares  outstanding  of each of the  Registrant's
classes of common stock, as of the latest practicable date.

            Class                           Outstanding at February 28, 2001
            -----                           --------------------------------
  Common stock, $1.00 par value                     22,951,394 shares

Documents Incorporated by Reference

1.   Definitive  Proxy Statement of the Registrant  filed pursuant to Regulation
     14A for the 2001 Annual Meeting of Stockholders to be held on May 30, 2001,
     is incorporated by reference in Part III.

                           FORWARD-LOOKING STATEMENTS

     This Form 10-K  includes  "forward-looking  statements"  as  defined by the
Securities  and  Exchange  Commission.   These  statements  concern  our  plans,
expectations and objectives for future  operations.  All statements,  other than
statements  of  historical  facts,  included  in this  Form  10-K  that  address
activities, events or developments that we expect, believe or anticipate will or
may occur in the future are  forward-looking  statements.  The words  "believe,"
"plan," "intend,"  "anticipate,"  "estimate,"  "project" and similar expressions
are also intended to identify forward-looking statements.  These forward-looking
statements include, among others, such things as:

     o expansion and growth of our business and operations;

     o future financial performance;

     o future acquisition and development of power plants;

     o future production of coal, oil and natural gas;

     o reserve estimates; and

     o business strategy.

     These forward-looking  statements are based on assumptions which we believe
are reasonable based on current expectations and projections about future events
and industry  conditions  and trends  affecting our business.  However,  whether
actual results and developments will conform to our expectations and predictions
is subject  to a number of risks and  uncertainties  which  could  cause  actual
results  to  differ  materially  from  those  contained  in the  forward-looking
statements, including the following factors:

o    prevailing  governmental  polices and  regulatory  actions  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 retail competition;

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

o    weather conditions;

o    population  growth 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 or capital expenditures;

o    capital market conditions;

o    technological   advances;

o    competition for new energy development opportunities; and

o    legal and  administrative  proceedings  that  influence  our  business  and
     profitability.

                                TABLE OF CONTENTS

                                                                                                                            Page

ITEMS
1 & 2.        BUSINESS AND PROPERTIES.........................................................................................4
                   General....................................................................................................4
                   Holding Company Formation..................................................................................5
                   Industry Overview..........................................................................................5
                   Strategy...................................................................................................6
                   Independent Energy.........................................................................................9
                      Independent Power Plants................................................................................11
                      Fuel Production.........................................................................................16
                      Fuel Marketing..........................................................................................17
                   Electric Utility - Black Hills Power, Inc..................................................................18
                   Communications.............................................................................................21
                   Competition................................................................................................22
                   Risk Management............................................................................................22
                   California Markets.........................................................................................23
                   Regulation.................................................................................................24
                      Energy Regulation.......................................................................................24
                      Environmental Regulation................................................................................25
                      Exploration and Production..............................................................................28
                   Other Properties...........................................................................................29
                   Employees..................................................................................................29

ITEM 3.       LEGAL PROCEEDINGS...............................................................................................29

ITEM 4.       SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.............................................................30

ITEM 5.       MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
              STOCKHOLDER MATTERS.............................................................................................30

ITEM 6.       SELECTED FINANCIAL DATA.........................................................................................31

ITEM 7.       MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
              CONDITION AND RESULTS OF OPERATIONS.............................................................................32
                   RESULTS OF OPERATIONS......................................................................................32
                   LIQUIDITY AND CAPITAL RESOURCES............................................................................38
                   MARKET RISK DISCLOSURES....................................................................................41
                   RATE REGULATION............................................................................................45
                   BUSINESS OUTLOOK STATEMENTS................................................................................46

ITEM 8.       FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.....................................................................49

ITEM 9.       CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
              ON ACCOUNTING AND FINANCIAL DISCLOSURE..........................................................................79

ITEM 10.      DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..............................................................79

ITEM 11.      EXECUTIVE COMPENSATION..........................................................................................80

ITEM 12.      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT..................................................80

ITEM 13.      CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..................................................................80

ITEM 14.      EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.................................................80

              SIGNATURES......................................................................................................83

PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

General

We  are  a  growth  oriented,   diversified  energy  holding  company  operating
principally in the United States. Our regulated and unregulated  businesses have
expanded  significantly in recent years.  Our independent  energy group produces
and  markets  power and fuel.  We produce  and sell  electricity  in a number of
markets,  with a strong emphasis on the western United States.  We produce coal,
natural gas and crude oil primarily in the Rocky Mountain region and market fuel
products  nationwide.  We also own Black Hills Power,  Inc., an electric utility
serving   58,600   customers  in  South   Dakota,   Wyoming  and  Montana.   Our
communications group offers state-of-the-art broadband communication services to
residential  and business  customers in Rapid City and the northern  Black Hills
region of South  Dakota.  Our  predecessor  company was  incorporated  and began
providing  electric  utility  service in 1941 and began  selling  and  marketing
various forms of energy on an unregulated basis in 1956.

As the following table illustrates,  we have experienced significant growth over
the last five years,  primarily as a result of the expansion of our  independent
energy business and increases in wholesale electric sales.

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

                                              2000             1999         1998            1997           1996
- ----------------------------------------------------------------------------------------------------------------------
                                                                                          
Net income (in thousands):
     Electric                              $ 37,105      $ 27,286        $ 24,825        $ 22,106        $ 18,333
     Independent energy                      28,946        11,882          10,014          10,408          11,933
     Communications and other               (13,203)       (2,101)           (226)           (155)            (14)
     Oil and gas write-down                      --            --          (8,805)             --              --
                                          ---------      --------        --------        --------        --------
                                          $  52,848      $ 37,067        $ 25,808        $ 32,359        $ 30,252
                                          =========      ========        ========        ========        ========

Earnings per share                            $2.37         $1.73           $1.60(2)        $1.49           $1.40

Assets (in thousands)                    $1,320,320      $668,492        $559,417        $508,741        $467,354
Capital expenditures (in thousands)        $177,189(1)   $154,609         $27,225         $28,319         $24,388

Electric sales (megawatthours):
     Regulated utility
        Firm electric sales               1,973,066     1,920,005       1,923,331       1,932,347       1,710,571
        Wholesale off-system                684,378       445,712         371,104         279,612         249,100
                                        -----------    ----------      ----------      ----------      ----------
           Total utility                  2,657,444     2,365,717       2,294,435       2,211,959       1,959,671
     Non-regulated sales                    236,279             -               -               -               -
                                        -----------    ----------      ----------      ----------      ----------
           Total electric sales           2,893,723     2,365,717       2,294,435       2,211,959       1,959,671
                                        ===========    ==========      ==========      ==========      ==========

Average daily marketing volumes:
     Natural gas (MMbtus)                   860,800       635,500         524,800         231,000          28,200(3)
     Crude oil (barrels)                     44,300        19,270          19,000          12,600(3)            -
     Coal (tons)                              4,400         4,500           4,400(3)            -               -

Generating capacity (megawatts)
     Utility (owned generation)                 393           353             353             353             353
     Utility (purchased capacity)                70            75              75              75              75
     Independent power                          250            --                              --              --
                                        -----------    ----------      ----------      ----------      ----------
           Total generating capacity            713           428             428             428             428
                                        ===========    ==========      ==========      ==========      ==========

Oil and gas reserves (MMcfe)                 44,882        44,114          30,160          24,022          17,330
- ----------------------------------------------------------------------------------------------------------------------

(1)  Excludes the non-cash acquisition of Indeck Capital, Inc.

(2)  Excludes  impact  of $0.41  per share  non-cash  write-down  of oil and gas
     properties due to historically low oil prices, lower natural gas prices and
     a decline in the value of unevaluated properties.

(3)  Since date of inception of marketing operations.

For additional  information on our business segments see - "ITEM 7. MANAGEMENT'S
DISCUSSION  AND ANALYSIS OF FINANCIAL  CONDITION AND RESULTS OF  OPERATIONS  and
Note 13 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS."

Holding Company Formation

At our  annual  meeting  of  shareholders  on June 20,  2000,  our  shareholders
approved  the  formation  of a  holding  company  structure  through  a "plan of
exchange" between Black Hills  Corporation and Black Hills Holding  Corporation.
The plan of exchange provided that each share of Black Hills Corporation  common
stock would be exchanged for one share of common stock of the holding company.

On December  22,  2000,  articles of exchange  were filed with the South  Dakota
Secretary of State. As a result:

     o    all common shareholders of Black Hills Corporation became shareholders
          of Black Hills Holding Corporation, the holding company;

     o    Black Hills  Corporation  became a  wholly-owned  subsidiary  of Black
          Hills Holding Corporation;

     o    Black Hills Corporation  changed its name to "Black Hills Power, Inc."
          and the holding company changed its name to "Black Hills Corporation."

The  formation of our holding  company  structure  allows us to pursue,  through
separate subsidiaries,  business opportunities in both regulated and unregulated
markets.

Industry Overview

In the last decade,  many U.S.  regulatory  bodies have taken steps to transform
the energy  sectors  which they  regulate to  encourage  competition,  introduce
customer choice and, in some cases,  to improve the  operational  performance of
strategic  energy  assets.  In  particular,   the  electric  power  industry  is
undergoing  substantial  change as a result  of  regulatory  initiatives  at the
federal and state levels. As early as the mid-1990's, new regulatory initiatives
to increase  competition  in the  domestic  power  generation  industry had been
adopted or were being  considered at the federal  level and by many states.  The
primary  focus  of  such  efforts  was  to  increase   competition  through  the
disaggregation of the traditional utility functions of generation, transmission,
distribution   and  marketing  of  electricity  into  competitive  or  partially
regulated  businesses.  This resulted in new investment  opportunities  to enter
previously non-competitive or closed markets.

In 1992,  the Federal  Energy  Regulatory  Commission  (FERC)  issued Order 636,
followed by Order 888 in 1996,  to  increase  competition  by easing  entry into
natural gas and electricity  markets.  These orders require owners and operators
of  natural  gas and power  transmission  systems to make  transmission  service
available on a non-discriminatory  basis to energy suppliers. In order to better
assure  competitive access to the transmission  network on a  non-discriminatory
basis,  FERC  issued  Order 2000 in December  1999,  which  encourages  electric
utilities  with  power   transmission   assets  to  voluntarily   form  regional
transmission  organizations  to  provide  regional  management  and  control  of
transmission assets independent of firms that sell electricity.

The electric  power  industry has also  witnessed  growing  consumer  demand and
increasingly  frequent  regional  shortages of  electricity  over the past three
years.  The summers of 1998,  1999 and 2000 and the winter of 2000-2001 have all
been  characterized  by very high peak  prices  for  electricity  in a number of
recently  created  wholesale  electricity  markets.  We believe that substantial
amounts  of new  electric  generating  capacity  need  to be  built  to  relieve
shortages of electricity and to replace inefficient and obsolete facilities.

The oil and gas industry has experienced  strong  increases in commodity  prices
since the  historically  low levels  experienced in 1998.  These price increases
have been driven in part by several years of modest drilling  activity  combined
with strong  growth in demand for energy  commodities.  Continued  growth of the
Internet and other high  technology  industries  is  contributing  to increasing
demand for power.  Demand for natural  gas is  expected  to remain  strong as an
increasing number of gas-fired power plants are brought into service.

The  telecommunications  industry is  currently  undergoing  widespread  changes
brought about by, among other things,  the  Telecommunications  Act of 1996, the
decisions of federal and state  regulators to open the monopoly local  telephone
and cable  television  markets to  competition  and the need for  higher  speed,
higher  capacity  networks to meet the increasing  consumer  demand for expanded
telecommunications services, including broader video choices and high speed data
and  Internet  services.  The  convergence  of  these  trends  and the  inherent
limitations of most existing  networks have created  opportunities for new types
of communications  companies  capable of providing a wide range of voice,  video
and  data  services   through  new  and  advanced  high  speed,   high  capacity
telecommunications networks.

As a  result  of  historical  and  anticipated  regulatory  initiatives  and the
increasing demand for electricity, fuel and broadband services, we believe there
are significant  opportunities for the development and growth of our independent
energy businesses, our regulated utility and our communications business.

Strategy

Our  strategy  is  to  build  long-term   shareholder  value  by  deploying  our
development,  operating  and  marketing  expertise  in the  deregulating  energy
industry.  We  plan to  operate  a mix of  unregulated  independent  energy  and
regulated utility businesses,  with emphasis on the independent power generation
and fuel production  segments.  We expect our independent  energy  businesses to
operate nationwide,  with an integrated regional emphasis on the western half of
the United States. Our utility and communications  businesses intend to continue
focusing their retail operations primarily on the northern Black Hills region of
South Dakota,  with wholesale  power sales  concentrated  primarily in the Rocky
Mountain and West Coast regions.

Our strategy includes the following key elements:

     o    grow our  independent  power unit by developing  and  acquiring  power
          projects nationwide,  focusing primarily in the western United States,
          where demand is currently strong and expected to grow;

     o    expand  the  generating  capacity  of our  existing  sites  through  a
          strategy known as "brownfield development;"

     o    sell a large  percentage of the  production  from our newly  developed
          projects  through  long-term  contracts in order to secure  attractive
          investment returns;

     o    increase our reserves of natural gas and crude oil and expand our fuel
          production;

     o    exploit  our fuel cost  advantages  and our  operating  and  marketing
          expertise to remain a low-cost power producer;

     o    manage the risks inherent in energy  marketing by  maintaining  strict
          position  limits that  minimize  price risk exposure and by conducting
          business with a  diversified  group of  counterparties  of high credit
          quality;

     o    build  and  maintain  strong   relationships   with  wholesale  energy
          customers; and

     o    capitalize on our utility's established market presence, relationships
          and  customer  loyalty.  We  aim  to  expand  our  independent  energy
          businesses   and  to  increase  our   communications   group's  market
          penetration in our local service territory.

Grow our  Independent  Power Unit by  Developing  and Acquiring  Power  Projects
Nationwide,  Focusing  Primarily in the Western United  States,  Where Demand is
Currently  Strong and Expected to Grow. Our aim is to tailor the  development of
power  plants  in  regional  markets  based  on  prevailing  supply  and  demand
fundamentals  and our  existing  fuel  assets  and  fuel  and  energy  marketing
capabilities  in order to capitalize  on market  growth while  managing our fuel
procurement  needs. We believe the following  trends will provide us with growth
opportunities in the future:

     o    Demand  for  electricity  will  continue  to  outpace  new  generation
          capacity  over the  next  several  years,  particularly  in the  Rocky
          Mountain  and  West  Coast  regions,  resulting  in  continued  strong
          electricity pricing.

     o    New electric generation construction will be predominantly  gas-fired,
          which may  create  further  competitive  cost  advantages  for new and
          existing coal-fired generation assets.

     o    Significant  expansion of gas-fired  generation  anticipated  over the
          next  several  years  will favor a balanced  portfolio  of  generation
          assets, including coal-fired and hydroelectric generation.

     o    Transmission   construction  will  significantly  lag  new  generation
          development,  favoring  new  development  located near load centers or
          existing, unconstrained transmission locations.

     o    Disaggregation  of the electric  utility  industry from  traditionally
          vertically    integrated    utilities   into   separate    generation,
          transmission,  distribution  and  marketing  entities  will  continue,
          thereby creating opportunities for acquisitions and joint ventures.

Over the next few years,  we intend to grow through a combination of disciplined
acquisitions and development of new power generation facilities primarily in the
Rocky Mountain region where we believe we have the detailed  knowledge of market
fundamentals and competitive advantage to maintain profitable operations.

Expand the Generating Capacity of our Existing Sites Through a Strategy Known as
"Brownfield  Development." We believe that existing sites with opportunities for
brownfield  expansion  generally  offer the potential  for greater  returns than
development  of new sites  through a  "greenfield"  strategy.  Brownfield  sites
typically offer several  competitive  advantages  over  greenfield  development,
including:

     o    proximity to existing transmission systems;

     o    operating cost advantages  related to ownership of shared  facilities;
          and

     o    a less costly and time consuming permitting process.

We are currently expanding our capacity with brownfield  development underway at
our Arapahoe, Valmont and Wyodak sites, and believe that our Fountain Valley and
Wyodak sites in  particular  provide  further  opportunities  for a  significant
expansion of our gas- and coal-fired  generating  capacity over the next several
years.

Sell a Large  Percentage of the  Production  From our Newly  Developed  Projects
Through Long-Term  Contracts in Order to Secure Attractive  Investment  Returns.
Recent extreme price volatility in the short-term power markets are resulting in
greater  demand  among our  wholesale  customers  for mid- and  long-term  power
purchase  agreements.  By selling the majority of our energy and capacity  under
mid- and long-term contracts, we believe that we can satisfy the requirements of
our customers  while earning more stable  revenues and greater  returns over the
long  term than we could by  selling  our  energy  into the more  volatile  spot
markets.

We also  believe  that the  anticipated  trend  toward  expansion  of  gas-fired
generation over the next few years will favor gas-fired  generation  assets that
are tied to tolling  agreements or other arrangements where fuel cost and output
prices are effectively secured. In recent months, we have entered into long-term
tolling agreements  covering nearly all of the gas-fired energy and capacity our
independent  power unit is adding through  brownfield  expansion of the Arapahoe
and Valmont sites and from the Fountain Valley project. See "--Independent Power
Plants."

Increase  our  Reserves  of  Natural  Gas and  Crude  Oil and  Expand  our  Fuel
Production.  We aim to support the fuel requirements of our growing portfolio of
power  plants  as well as power  plants  owned by  others.  Our  strategy  is to
continue  increasing  natural gas, coal and oil production  levels while growing
our reserve base for natural gas and oil. We expect to emphasize natural gas and
coal  production  for  potential  direct or  indirect  use in the  overall  fuel
strategy for our power  plants.  Our  objective is to maintain  coal reserves to
serve our mine-mouth  coal-fired  generation  plants  directly,  and to maintain
sufficient  natural gas production  either to directly serve or indirectly hedge
the fuel cost exposure of our gas-fired generation plants. Specifically, we plan
to:

     o    target an oil and gas  reserve  replacement  ratio of 125  percent and
          minimize  exploration  risk by focusing on lower-risk  exploration and
          development  drilling  as well as  acquisitions  of  proven  producing
          properties;

     o    exploit  our belief  that the  long-term  demand for  natural gas will
          remain strong by emphasizing natural gas, rather than oil, exploration
          and development drilling activities;

     o    add  natural  gas  reserves  and  increase  production  by focusing on
          various shallow gas plays in the northern Rocky Mountain region, where
          the added  production can be integrated with our fuel marketing and/or
          power generation activities;

     o    increase coal  production and sales from our Wyodak mine by continuing
          to promote and develop additional  mine-mouth generating facilities at
          the  site,  including  the  Wygen I  plant,  which  is  scheduled  for
          completion in Spring 2003; and

     o    pursue  future  sales of coal  from  the  Wyodak  mine to  rail-served
          customers by reducing the moisture  content of our coal so that we can
          ship it greater distances.

Exploit our Fuel Cost  Advantage and our  Operating  and Marketing  Expertise to
Remain a Low-Cost  Power  Producer.  We expect to expand our  portfolio of power
plants  having  relatively  low marginal  costs of producing  energy and related
products  and  services.  We  intend  to  utilize a  low-cost  power  production
strategy,  together with access to coal and natural gas reserves, to protect our
revenue  stream as an  increasing  number of gas-fired  power plants are brought
into  operation.  Low  marginal  production  costs can result  from a variety of
factors,  including low fuel costs,  efficiency in converting  fuel into energy,
and low per unit operation and maintenance  costs. We have aggressively  managed
each of these factors to achieve very low  production  costs,  especially at our
coal-fired and hydroelectric generating facilities.

Our primary  competitive  advantage is our coal mine,  which is located in close
proximity to our retail service  territory.  We are  exploiting the  competitive
advantage  of  this  native  fuel  source  by  building  additional   mine-mouth
coal-fired  generating  capacity.  This  strengthens  our position as a low-cost
producer since transportation costs often represent the largest component of the
delivered cost of coal.

Manage the Risks  Inherent in Energy  Marketing by Maintaining  Strict  Position
Limits that  Minimize  Price Risk  Exposure and by  Conducting  Business  with a
Diversified Group of  Counterparties of High Credit Quality.  Our fuel marketing
operations require effective  management of price,  counterparty and operational
risks. To mitigate these risks, we have implemented risk management policies and
procedures  for  each  of our  marketing  companies  that  prohibit  speculative
strategies and establish price risk exposure levels,  counterparty credit limits
and committees to monitor  compliance with our policies.  We also limit exposure
to energy marketing risks by maintaining  separate credit facilities for each of
our  marketing  companies  and  by  avoiding  the  issuance  of  parent  company
performance guarantees to counterparties of our marketing companies.

Build and Maintain Strong Relationships with Wholesale Energy Customers. We seek
to sell a majority of our power under  contracts  with terms ranging from one to
10 or more  years.  Therefore,  we strive  to build  strong  relationships  with
utilities, municipalities and other wholesale customers, including the companies
that sell us their power plants. We believe that these entities will continue to
be the primary  providers of  electricity  to retail  customers in a deregulated
environment  and that they will need  products,  such as  capacity,  in order to
serve  their  customers  reliably.  By  providing  these  products  to meet  our
customers'  energy needs,  we believe that we can earn more stable  revenues and
greater returns over the long term than we could by selling energy into the more
volatile spot markets.

We have been successful in entering into a variety of wholesale  contracts based
on the specific needs of our  customers.  For example,  in 1999,  Public Service
Company of Colorado approached us to take over ownership and construction of the
120 megawatt Arapahoe and Valmont facilities in Colorado. Public Service Company
of Colorado was subject to regulatory  constraints that restricted their ability
to own the facilities and needed the plants completed in an efficient and timely
manner to meet the rapid  growth in demand.  We  completed  construction  of the
facilities  on  schedule,  and signed  tolling  agreements  with Public  Service
Company of Colorado for the capacity and energy.  In 2000, we signed  agreements
to expand the Arapahoe and Valmont  facilities by 90 megawatts with 40 megawatts
to be in service in 2001 and 50 megawatts to be in service in 2002. In addition,
we recently acquired 240 megawatts at the Fountain Valley site in Colorado which
we expect to be in service  in 2001.  We have  signed  tolling  agreements  with
Public Service Company of Colorado for the expanded  facilities and the Fountain
Valley site.

Capitalize On Our  Utility's  Established  Market  Presence,  Relationships  and
Customer  Loyalty.  We aim to expand our  independent  energy  businesses and to
increase our  communications  group's  market  penetration  in our local service
territory.  As a result of its firmly established market presence,  our electric
utility has built  solid brand  recognition  and  customer  loyalty in the Black
Hills region.  By ensuring a reliable supply of power to retail customers in our
South  Dakota and Wyoming  service  territory at rates  substantially  below the
national average, we have also developed a strong,  supportive relationship with
our utility regulators.

Our utility  provides a solid  foundation  of support for the  expansion  of our
independent  energy  and  communications  businesses.  In  addition,   industry,
technical  and market  expertise  from our  utility  supports  the growth of our
independent  energy businesses,  and our strong brand recognition  assists us in
achieving rapid customer  acceptance of our bundled  communications  services in
our Black Hills service territory.

Independent Energy

Our  independent  energy group  engages in the  production  and sale of electric
power through  ownership of a diversified  portfolio of generating  plants,  the
production of coal,  natural gas and crude oil  primarily in the Rocky  Mountain
region,  and the marketing of fuel products  nationwide.  The independent energy
group was our primary  source of revenue  and net income  growth in 2000 and the
net income from the  independent  energy  group is expected to exceed net income
from our  regulated  utility  beginning in 2001.  The  independent  energy group
consists of three units: independent power production,  fuel production and fuel
marketing.

Independent Power Production. Our independent power production segment acquires,
develops and expands  unregulated  power plants.  We currently operate under two
business units - Black Hills Generation and Black Hills Energy Capital. In 1999,
Black Hills Generation  entered into a Construction  Agency Agreement with Wygen
Funding,  L.P.  (Funding) to act as Funding's agent in the construction of Wygen
I,  a 90  megawatt  mine-mouth  coal-fired  plant.  In the  Construction  Agency
Agreement,  Black Hills  Generation  agreed to enter into an Agreement for Lease
and Lease for the Wygen I plant. The plant is expected to be completed in spring
2003.  Black Hills Energy  Capital was formed as a result of our  acquisition of
Indeck  Capital Inc. in July 2000. The Indeck  Capital  acquisition  provided us
varying interests in operating independent power plants in California, New York,
Massachusetts and Colorado with a total net ownership of 210 megawatts,  as well
as  minority  interests  in several  power-related  funds  with a net  ownership
interest of 40 megawatts.

In February  2001, we signed a definitive  agreement  with Enron  Corporation to
purchase 100 percent of an  independent  power project under  construction  near
Colorado Springs, Colorado, known as the "Fountain Valley" project. We expect to
close this  transaction  on or about March 31,  2001.  This site will  initially
house 240  megawatts of gas-fired  peaking  facilities.  The energy and capacity
generated by the Fountain  Valley project will be sold to Public Service Company
of Colorado under a tolling contract  expiring in July 2012 pursuant to which we
assume no fuel  cost or  electricity  market  risk.  We  expect  the plant to be
completed in  phases beginning  in June 2001  and ending in  July 2001  with the
total cost expected to  approximate  $175 million.  In  addition  to the current
project, we believe that  the Fountain Valley  site provides us with  attractive
expansion  and  integration opportunities and is  well-situated  to serve  other
markets in the Rocky Mountain and southwest regions.

In addition to Wygen I and the Fountain Valley development, other projects under
construction include:

     o    Arapahoe CC5, a 50 megawatt  combined cycle expansion of our gas-fired
          turbines at the Arapahoe site located in the Front Range of Colorado;

     o    Valmont  Unit  8, a 40  megawatt  gas-fired  turbine  addition  to our
          Valmont site located in the Front Range of Colorado;

     o    Black Hills Generation  Gillette CT, a 40 megawatt  gas-fired facility
          located at the same site as our Wygen I plant; and

     o    Harbor Expansion,  a 30 megawatt (10 megawatt net ownership  interest)
          expansion of our Harbor  Cogeneration  facility located in Wilmington,
          California.

In March 2001,  we purchased a 40 megawatt  turbine that will be located  either
adjacent  to our Wygen I and Black  Hills  Generation  Gillette  CT plants  near
Gillette,  Wyoming,  or adjacent to our transmission system in Rapid City, South
Dakota.  The  power  plant to be  constructed  is  currently  known as the Lange
project.

We strive to maintain  diversification and balance in our portfolio of regulated
and  unregulated  power  plants.  Our  portfolio   (including  plants  currently
operating and those under  construction) is diversified in terms of fuel mix and
geographic  location,   with  79  percent  of  net  unregulated  capacity  being
gas-fired,  13  percent  coal-fired,   and  the  remainder  hydroelectric.   Our
independent  power  plants are located in  California,  Wyoming,  South  Dakota,
Colorado, New York and Massachusetts. In contrast, our electric utility capacity
is  approximately  53 percent  coal-fired,  33 percent oil or gas-fired,  and 14
percent under purchased power contracts, with plants located in South Dakota and
Wyoming.

We also have a diversified mix of revenue  sources.  We typically sell two types
of products: energy and capacity,  including ancillary services.  Although these
are separate  products,  both are typically sold together.  Energy refers to the
actual  electricity  generated by our facilities for ultimate  transmission  and
distribution to consumers of electricity. Energy is the only one of our products
that is subsequently  distributed to consumers.  Capacity refers to the physical
capability of a facility to produce  energy.  Ancillary  services  generally are
capacity support products used to ensure the safe and reliable  operation of the
electric power supply system. Examples of ancillary services include:

     o    automatic  generation control,  which is used to balance energy supply
          with  energy  demand,  referred  to in our  industry  as  "load," on a
          real-time basis; and

     o    operating  reserves,  which are used on an  hourly  or daily  basis to
          generate  additional energy if demand increases or if major generating
          resources   go  off-line   or  if   transmission   facilities   become
          unavailable.

Our output is sold under  contracts  of varying  length and  subject to merchant
pricing,  thereby  allowing  us to take  advantage  of current  favorable  price
trends,  while  hedging  the  impact of a  potential  downturn  in prices in the
future.  We currently sell energy and capacity under a combination of short- and
long-term  contracts as well as direct sales into the merchant  energy  markets.
Currently,  we sell 70  percent  to 80  percent  of our  unregulated  generating
capacity in operation under contracts greater than one year in duration. We sell
the remainder of this capacity under  short-term  contracts or directly into the
merchant markets.  The energy and capacity generated by our Arapahoe and Valmont
projects,  and the additional energy and capacity expected at these sites and at
our  Fountain  Valley  project  upon its  completion,  are subject to  long-term
tolling  agreements  with Public  Service  Company of Colorado.  Similarly,  the
electricity  generated by the Adirondack Hydro facilities in New York is under a
combination of short- and long-term agreements with Niagara Mohawk.

How We Develop and Acquire Power Plants.  We plan to actively pursue power plant
acquisitions and development  opportunities in areas we view as attractive.  Our
recent emphasis has been in the North American  Reliability Council region known
as the Western Systems  Coordinating  Council, or "WSCC." However, we anticipate
that future  acquisition and development  activities will take place  throughout
North  America.  Among those  factors we consider  critical  in  evaluating  the
relative attractiveness of new generation opportunities are the following:

     o    electric demand growth potential in the targeted region;

     o    requirements for permitting and siting;

     o    proximity  of  the  proposed  site  to  high   transmission   capacity
          corridors;

     o    fuel supply reliability and pricing;

     o    the local regulatory environment; and

     o    the potential for geographic  concentration of new generation with our
          existing power plant portfolio.

We intend to target both acquisition and development opportunities which provide
a minimum  expected  return on equity of 12 to 13 percent.  We plan to emphasize
development  projects over  acquisitions,  since we believe they generally offer
opportunities for higher rates of return.

Our goal is to sell approximately 80 percent of the independent power generation
portfolio under long term contracts,  while leaving the remainder  available for
merchant,  or "spot" sales. We aim to secure  long-term power sales contracts in
conjunction with non-recourse plant financing.  This enables us to design a debt
repayment  schedule to closely match the term of the power sales  contracts,  so
that at the end of the  contract  term,  there is  little  or no debt left to be
serviced.

Independent Power Plants

General. Power facilities are often classified by cost of production. Facilities
that have the lowest costs of  production  relative to other power plants in the
region are usually the facilities that are first used to provide  energy.  These
facilities are known as "baseload"  utilities and typically operate more than 60
percent of the time they are available. Our hydroelectric assets in New York and
our coal-fired plants in Wyoming are examples of low-cost, baseload plants.

As demand for  electricity  rises during the year or even during the course of a
day,  power plants that have higher costs of production are dispatched to supply
additional energy.  Facilities that regularly provide additional energy during a
day are known as "intermediate" facilities. Facilities which are used between 10
percent and 60 percent of the time they are available  are typically  considered
to be intermediate facilities.

Power plants with the highest costs of production  are called upon only in times
of exceptionally high demand and are known as "peaking units." Peaking units are
generally dispatched less than 10 percent of the time they are available.

Rocky Mountain and West Coast Facilities.  We own approximately 151 megawatts of
generating  capacity in the WSCC states of California  and Colorado,  and are in
the process of  constructing  or acquiring  another 470 megawatts in the region.
All of these  facilities  in operation  are  gas-fired,  with all but our Harbor
Cogeneration  facility in California operating under long-term power purchase or
tolling  agreements.  The Harbor  Cogeneration  facility,  our primary operating
facility in California,  operates as a merchant peaking plant selling  ancillary
services and energy into the California market.

We are currently  implementing an extensive  expansion and development effort in
the region.  In February  2001,  we entered  into an agreement to purchase a 240
megawatt gas-fired facility near Colorado Springs,  Colorado, which is scheduled
to be completed in phases beginning in May 2001. We have also begun construction
on the  expansion  of our  Arapahoe and Valmont  facilities  in  Colorado,  with
long-term  tolling  contracts  already  in place  for the sale of  capacity  and
energy. An additional 130 megawatts of generating capacity is under construction
adjacent to our coal mine in Gillette,  Wyoming. See "--WSSC Facilities," below.
We are  expanding  our Harbor  Cogeneration  facility  by adding  two  efficient
exhaust heat  turbines,  which will add 30 megawatts (10 megawatts net ownership
interest) of generation capacity.  We have entered into an agreement to sell the
summer peaking capacity of this facility under a three-year arrangement with the
California  Independent  System  Operator,  or  "CAISO."  We  expect to sell the
remaining capacity and all of the energy on a merchant basis into the California
market.

WSCC Facilities

                                                        Total                      Net
                                 Fuel                 Capacity                  Capacity    Start
Power Plant                      Type        State      (MWs)      Interest       (MWs)     Date
- -----------                      ----        -----    --------     --------     --------    -----
                                                                           
In Operation:
   Arapahoe Unit 5               Gas          CO         40.0        100%           40.0     2000
   Arapahoe Unit 6               Gas          CO         40.0        100%           40.0     2000
   Valmont Unit 7                Gas          CO         40.0        100%           40.0     2000
   Ontario                       Gas          CA         12.0         50%            6.0     1984
   Harbor                        Gas          CA         80.0       31.8%           25.4     1989
                                                      -------                     ------
    Total in Operation                                  212.0                      151.4

Under Construction:
- ------------------
   Fountain Valley               Gas          CO        240.0        100%          240.0     2001
   Arapahoe CC5                  Gas          CO         50.0        100%           50.0     2002
   Valmont Unit 8                Gas          CO         40.0        100%           40.0     2001
   Wygen #1                      Coal         WY         90.0        100%           90.0     2003
   BHG Gillette CT               Gas          WY         40.0        100%           40.0     2001
   Harbor Expansion              Gas          CA         30.0       31.8%            9.5     2001
                                                       ------                    -------
     Total in Construction                              490.0                      469.5
    Total WSCC                                          702.0                      620.9
                                                        =====                      =====

Arapahoe, Valmont and Fountain Valley Facilities

In Operation: Our Arapahoe and Valmont plants are wholly-owned gas-fired peaking
facilities  in the  Front  Range  of  Colorado,  with a  total  capacity  of 120
megawatts. The projects were acquired from Public Service Company of Colorado in
January  2000  jointly by the former  Indeck  Capital  and us, and were put into
service on June 1, 2000.  We sell all of the output from these  plants to Public
Service Company of Colorado under tolling contracts  expiring in May 2012. These
contracts  also cover the Fountain  Valley  project and the Arapahoe and Valmont
expansion projects described below.

Under  Construction:  We expect to increase  our capacity by 40 megawatts at the
Valmont  project by May 2001 and by 50 megawatts  at the  Arapahoe  plant by May
2002.

The first  phase of our 240  megawatt  gas-fired  Fountain  Valley  facility  is
scheduled for completion in May 2001, with final  completion  scheduled for July
2001.  The  Fountain  Valley site,  located in Colorado  has ample  capacity for
subsequent expansion if market conditions prove to be attractive.

Wygen I Facility

The Wygen I facility will be a leased  mine-month  coal-fired plant with a total
capacity of 90 megawatts,  which is expected to be completed by spring 2003. The
Wygen  I  plant  will be  substantially  identical  in  design  to our  electric
utility's Neil Simpson II facility,  completed in 1995. The two plants will both
run on pulverized low-sulfur coal fed by conveyor from our adjacent Wyodak mine.
The plant will burn  approximately  500,000 tons of coal per year,  and will use
the latest available  environmental  control  technology.  We intend to sell the
majority of the power from the facility under long-term unit contingent capacity
and  energy  sales  contracts,  under  which  delivery  is not  required  during
unplanned plant outages. We have entered into a contract to sell 60 megawatts of
unit  contingent  capacity  from this plant to  Cheyenne  Light,  Fuel and Power
Company with a term of 10 years from the date the plant becomes operational.  We
have  also  signed  a  contract  to  sell an  additional  20  megawatts  of unit
contingent  capacity and energy to the Municipal Electric Agency of Nebraska for
a term of 10 years.

Black Hills Generation Gillette CT

The Black Hills Generation Gillette CT facility,  a gas-fired combustion turbine
facility located at the same site as our Wygen I facility,  has a total capacity
of 40 megawatts and is scheduled to be completed in May 2001. We plan to utilize
this facility as a merchant  plant through  summer 2001.  Beginning in September
2001, we will sell the energy and capacity from this facility to Cheyenne Light,
Fuel and Power Company under a 10-year unit contingent tolling agreement.

Ontario Cogeneration Facility

Ontario Cogeneration Company is a 12 megawatt, gas-fired power plant in Ontario,
California,  which is currently being operated as a baseload plant.  The project
is selling all of this  electrical  facility's  steam to Sunkist  Growers,  Inc.
Output from the plant is also subject to a 25-year power purchase agreement with
Southern  California  Edison  expiring in January  2010.  For a  description  of
certain  issues  relating to our operation of this plant and our agreement  with
Sunkist Growers,  Inc., see  "--Regulation--Environmental  Regulation--Clean Air
Act."

Harbor Cogeneration Facility

In Operation:  Harbor  Cogeneration,  a gas-fired  plant located in  Wilmington,
California,  is currently  being  operated as a merchant  peaking  plant selling
ancillary  services and energy into the CAISO market. It formerly operated under
a 30-year power purchase agreement with Edison Mission Energy. This contract was
terminated  in  February  1999  under  a  settlement   agreement  with  Southern
California Edison. Under the buyout agreement,  Harbor Cogeneration will receive
payments  pursuant to a termination  payment schedule for an amount equal to the
total payment under the original  contract due for the 11-year period  beginning
April 1, 1997 and  ending on  October 1, 2008.  The  facility  currently  has no
long-term debt outstanding.

Under Construction/Expansion: We are currently expanding the Harbor Cogeneration
plant by an additional 30 megawatts (10 megawatt net ownership interest), with a
targeted  completion  date of May 2001.  The summer  peaking  capacity from this
plant will be made  available  to CAISO  beginning in May 2001 and ending in May
2003.  We plan to sell the  remaining  capacity  and all of the energy from this
plant in the California market on a merchant basis.

Lange Project

In March 2001,  we purchased a 40 megawatt  gas-fired  combustion  turbine which
will be  located  either  adjacent  to our  Wygen I and Black  Hills  Generation
Gillette  CT plants near  Gillette,  Wyoming,  or at a new site  adjacent to our
transmission  system in Rapid City,  South  Dakota,  where we have  received all
necessary  permits for the  construction of two 40 megawatt  combustion  turbine
facilities.

Northeast  Facilities.  We  currently  own  approximately  58 net  megawatts  of
generation  capacity in eight plants in the Northeast  region,  all of which are
located in New York and Massachusetts.  Sixty-seven  percent of  this generation
is  "run-of-river"  hydroelectric,  with the remainder being  gas-fired  peaking
capacity.  We currently do not have any plans for repowering or expanding any of
these facilities.

The Massachusetts  plant sells energy and capacity under annual contracts.  Four
of our New York plants will begin selling all or a significant portion of energy
and capacity  competitively into the New York Power Pool shortly upon expiration
of their existing five-year power sales contracts.  The remaining three New York
plants,  Hudson  Falls,  South  Glens  Falls and  Middle  Falls,  are  currently
operating under long-term power purchase agreements with Niagara Mohawk.

                                                            Total                    Net
                                      Fuel                 Capacity                Capacity     Start
         Power Plant                  Type     State        (MWs)       Interest    (MWs)       Date
         -----------                 -------   -----        -----     --------     --------     -----
                                                                              
   Northeast
     New York State Dam              Hydro      NY           11.4         100%        11.4       1990
     Middle Falls                    Hydro      NY            2.3          50%         1.2       1989
     Sissonville                     Hydro      NY            3.0         100%         3.0       1990
     Warrensburg                     Hydro      NY            2.9         100%         2.9       1988
     Hudson Falls                    Hydro      NY           41.9        30.2%        12.7       1995
     South Glens Falls               Hydro      NY           13.9        30.2%         4.2       1994
     Fourth Branch                   Hydro      NY            3.4         100%         3.4       1988
     Pepperell                       Gas        MA           40.0        48.7%        19.5       1990
                                                           ------                     -----
            Total (Northeast)                               118.8                     58.3

Adirondack Hydro Development

     The seven "run-of-river" hydroelectric plant interests acquired as a result
of our acquisition of Indeck Capital are:

     o    New York State Dam, an 11.4  megawatt  plant  located in Waterford and
          Cohoes, New York;

     o    Middle Falls, a 2.3 megawatt plant located in Easton, New York;

     o    Sissonville, a 3.0 megawatt plant located in Potsdam, New York;

     o    Warrensburg, a 2.9 megawatt plant located in Warrensburg, New York;

     o    Hudson Falls, a 41.9 megawatt plant located in Moreau, New York;

     o    South Glens Falls, a 13.9 megawatt plant located in South Glens Falls,
          New York; and

     o    Fourth Branch, a 3.4 megawatt plant located in Waterford, New York.

We  acquired  approximately  10 percent  of the Hudson  Falls and the South Glen
Falls plants as part of the Indeck  Capital  acquisition  and an  additional  20
percent of these plants in December 2000.  These projects run at a high capacity
factor  because the Hudson River is  regulated  for power  generation  and flood
control.

The seven projects were initially covered by long-term power purchase  contracts
with Niagara Mohawk for all or most of their output.  Currently,  three projects
have been  restructured  to allow the power purchase  contracts to be bought out
and for us  eventually  to sell  power  into  the New  York  Independent  System
Operator  (NY-ISO).  The New York  State  Dam,  Sissonville,  Fourth  Branch and
Warrensburg  facilities  are currently  subject to short-term  transition  power
sales agreements expiring over the next two to three years, at which point these
plants will sell directly into the market on a merchant basis.

Pepperell Facility

The Pepperell facility is a 40 megawatt gas-fired  combined-cycle  plant located
in  Pepperell,  Massachusetts.  The  plant is  currently  subject  to a  tolling
agreement  with Enron Power and Trading for the sale of a majority of its energy
for the year 2001, and a steam sales  agreement with the Pepperell Paper Company
expiring in November 2001.

Power Funds. In addition to our ownership of the power plants  described  above,
we hold various  indirect  interests in power plants  through our  investment in
energy and energy-related  funds, both domestic and international,  as described
below:

                                               Left to
                                     Total        be        Number         Total                         Net
                                     Amount     Funded        of         Capacity                      Capacity
            Fund Name                ($MM)      ($MM)       Plants         (MWs)       Interest         (MWs)
   -----------------------         ----------  -------      ------       --------      ---------      --------
                                                                           
   Energy Investors Fund I            $159.5       $0          7          136.0           12.6%          17.1
   Energy Investors Fund II           $115.0       $0          6          130.0            6.9%           9.0
   Project Finance Fund III           $101.0       $0          7          239.0            5.3%          12.7
   Caribbean Basin                     $75.0      $60          1           34.0            3.7%           1.2
                                                                          -----                          ----
       Total Fund Interests                                               539.0                          40.0

Financing of our  Independent  Power  Projects.  We have  financed our principal
independent power generation facilities primarily with non-recourse debt that is
repaid solely from the project's revenues. This type of financing is referred to
as "project  financing." These financings  generally are secured by the physical
assets,  major project  contracts and agreements,  cash accounts and, in certain
cases, our ownership interest, in the related project. True project financing is
not  available  for  all  projects,  including  some  assets  purchased  out  of
bankruptcy,  some merchant plants and some purchases of minority stock positions
in publicly-traded companies. Even in those instances,  however, we may still be
able to finance a smaller portion of the total cost with project financing, with
the  remainder  financed  with debt that is either  raised or  supported  at the
corporate rather than the project level.

Project financing  transactions generally are structured so that all revenues of
a project are  deposited  directly  with a bank or other  financial  institution
acting as escrow or security  deposit  agent.  These funds then are payable in a
specified order of priority set forth in the financing documents to ensure that,
to the extent available,  they are used first to pay operating expenses,  senior
debt  service and taxes and to fund  reserve  accounts.  Thereafter,  subject to
satisfying debt service coverage ratios and certain other conditions,  available
funds may be disbursed  for  management  fees or  dividends  or, where there are
subordinated lenders, to the payment of subordinated debt service.

These  project  financing  structures  are  designed to prevent the lenders from
looking  to  us  or  our  other  projects  for  repayment;  that  is,  they  are
"non-recourse"  to us and our affiliates not involved in the project,  unless we
or another affiliate expressly agree to undertake  liability.  In the event of a
foreclosure  after a default,  our project  affiliate  owning the facility would
only retain an interest in the  assets,  if any,  remaining  after all debts and
obligations  were paid.  In  addition,  the debt of each  operating  project may
reduce the liquidity of our equity interest in that project because the interest
is  typically  subject  both to a  pledge  securing  the  project's  debt and to
transfer restrictions set forth in the relevant financing agreements.  Also, our
ability to transfer or sell our  interest in certain  projects or the  project's
power is  restricted by certain  purchase  options or rights of first refusal in
favor of our partners and certain change of control  restrictions in the project
financing documents.

Fuel Production

Coal

Our coal production segment mines and processes  low-sulfur  sub-bituminous coal
near  Gillette,  Wyoming.  The  Wyodak  mine,  which we  acquired  in 1956  from
Homestake Gold Mining Company, sits on top of the Powder River Basin, one of the
largest coal  reserves in the United  States.  We believe the Wyodak mine is the
oldest operating  surface coal mine in the nation,  with an annual production of
approximately  three million  tons.  Mining rights to the coal are based on four
federal  leases and one state  lease.  We pay  royalties of 12.5 percent and 9.0
percent, respectively, of the selling price on all federal and state coal. As of
December 31, 2000, we had coal  reserves of 275 million tons,  enough to satisfy
present contracts for over 90 years. Substantially all of our coal production is
sold under long-term contracts to Black Hills Power, Inc., our electric utility,
and to Pacific Power & Light (Pacific Power).

Our coal  segment's  agreement  with Black Hills Power limits  earnings from all
coal sales to Black  Hills  Power to a  specified  return on our  original  cost
depreciated  investment  base.  Black Hills Power made a commitment to the South
Dakota Public Utilities  Commission,  the Wyoming Public Service  Commission and
the City of Gillette that coal would be furnished and priced as provided by that
agreement for the life of our Neil Simpson II plant.

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  terminating  in
2013. For a description  of litigation  with the parent company of Pacific Power
relating  to this  agreement,  see  "ITEM  3.  LEGAL  PROCEEDINGS  -  PacifiCorp
Litigation."

In May 2000, we acquired the K-Fuel plant, a coal enhancement plant located near
our Gillette,  Wyoming coal mine.  The plant,  which  transforms  high-moisture,
low-heat-value coal into low-moisture, high-heat-value coal, is currently not in
service.  We are working in conjunction with  Denver-based  KFx, Inc. to attract
investors to make the capital  improvements  necessary to re-start the plant. If
we do not locate suitable investment partners, the plant will not be re-started.

Over the next several years, we expect to increase coal production to supply:

     o    the Wygen I 90 megawatt mine-mouth power plant, which is scheduled for
          completion in 2003; and

     o    additional  mine mouth  generating  capacity of up to 500 megawatts at
          the same site, which is in the early stages of development.

In addition, if our K-Fuel plant is re-started, we expect to increase production
from the Wyodak mine and market any lower moisture,  higher heat content coal we
produce to an expanded customer base.

Natural Gas and Crude Oil

Our oil and gas exploration and production  segment operates  approximately  298
oil and gas wells,  all of which are located in Wyoming.  The  majority of these
wells  are in the  Finn-Shurley  Field  area,  located  in Weston  and  Niobrara
Counties in Wyoming.  We also own a working interest in, but do not operate,  an
additional  341 wells  located in  California,  Montana,  North  Dakota,  Texas,
Wyoming,  Oklahoma  and  offshore in the Gulf of Mexico.  In  addition,  we have
accumulated  significant acreage in other northern Rocky Mountain region,  which
we plan to utilize for oil and gas exploration.

We plan to target a reserve  replacement  ratio  equal to 125  percent of annual
production while minimizing exploration risk by focusing on development drilling
and relatively  low-risk  exploration  opportunities  as well as acquisitions of
producing properties. A key component of this strategy is the pursuit of shallow
gas  opportunities  in the northern  Rocky  Mountain  region.  We also expect to
modestly increase our California and offshore  production in the future,  but do
not plan to serve as the operator for such production activities.

As of December 31, 2000,  we had proved  reserves of 4.4 million  barrels of oil
and 18.4 billion  cubic feet of natural gas,  with  approximately  62 percent of
current  production  consisting  of  natural  gas.  In  2000,  our  oil  and gas
production  increased 12 percent over 1999 levels,  with record drilling results
and year-end reserves.

In March 2001, we signed a definitive  agreement to purchase  certain  operating
and  non-operating  interests  in 74 oil  and gas  wells  located  primarily  in
Colorado and Wyoming. This transaction is expected to close in April 2001. These
properties  have proved  reserves  of  approximately  8.7 billion  cubic feet of
natural gas and approximately  200,000 barrels of oil,  representing an increase
in our existing proved reserves of over 20 percent.

Fuel Marketing.  We market natural gas, oil and coal in specific  regions of the
United  States.  We offer  physical and financial  wholesale  fuel marketing and
price risk  management  products and services to a variety of  customers.  These
customers include natural gas distribution companies, municipalities, industrial
users, oil and gas producers,  electric utilities,  coal mines, energy marketers
and  retail  gas  users.  Our fuel  marketing  businesses  collectively  have 35
employees.  Our average daily marketing  volumes for the year ended December 31,
2000,  were 860,800  million British thermal units of gas, 44,300 barrels of oil
and 4,400 tons of coal.

The following table describes the location of our fuel marketing  operations and
sales offices:

                                                           Marketing
Company                                   Fuel             Operations        Sales Offices
- ----------------------------------------  -----------      ----------        -------------------------------------
                                                                    
Enserco Energy                            Natural Gas      Golden, CO        Chicago, IL; Calgary, Alberta, Canada
Black Hills Energy Resources              Crude Oil        Houston, TX       Tulsa, OK;  Midland, TX; Longview, TX
Black Hills Coal Network                  Coal             Mason, OH         St. Clairsville, OH

Gas Marketing

Our natural gas marketing operations are headquartered in Golden, Colorado, with
satellite offices in Calgary,  Canada and Chicago,  Illinois.  Our gas marketing
operations  focus  primarily  on  wholesale  marketing  and  producer  marketing
services.  Producer  services include providing for direct purchases of wellhead
gas and for risk transfer and hedging  products.  Our gas marketing  efforts are
concentrated  in the Rocky  Mountain  and Pacific  Coast  regions and in Western
Canada.  We  contractually  hold natural gas storage  capacity and both long and
short-term  transportation  capacity on several  major  pipelines in the western
United States and Canada.  We utilize this capacity to move  relatively low cost
natural gas from the producer regions to more expensive end-use market areas.

Oil Marketing and Transportation

Our crude oil marketing and transportation operations are concentrated primarily
in Texas,  Oklahoma,  Louisiana  and  Arkansas.  In July 1999,  we acquired a 33
percent  ownership  interest in a 200-mile  pipeline,  with a capacity of 67,000
barrels per day, that transports foreign crude oil from Beaumont, Texas north to
refining and trading markets.

Coal Marketing

We  market  coal to  various  industrial  customers  and  power  plants  located
primarily in the midwest and eastern  regions of the United  States  through our
coal marketing subsidiary,  Black Hills Coal Network. We formed Black Hills Coal
Network in 1998 to acquire  the assets and hire the  operational  management  of
Coal Network and Coal Niche, based in Mason,  Ohio. These predecessor  companies
were coal brokerage and agency companies with customers  located  primarily east
of the Mississippi River.

Electric Utility - Black Hills Power, Inc.

Our  electric  utility,  Black  Hills  Power,  is  engaged  in  the  generation,
transmission and distribution of electricity.  It provides a solid foundation of
revenues,  earnings and cash flow that  support  utility  capital  expenditures,
dividends, and overall performance and growth.

Distribution   and   Transmission.   Our  electric   utility   distribution  and
transmission  businesses  serve  58,600  electric  customers,  with an  electric
transmission  system of 447 miles of high  voltage  lines and 541 miles of lower
voltage lines. Our utility's  service  territory covers a 9,300 square mile area
of western South Dakota,  eastern Wyoming and southeastern Montana with a strong
and stable  economic  base.  Over 90 percent of our  utility's  retail  electric
revenues are generated in South Dakota.

The  following  are   characteristics   of  our  distribution  and  transmission
businesses:

     o    We have a diverse  customer and revenue base.  Our revenue mix in 2000
          is  comprised of 29 percent  wholesale  off-system  sales,  26 percent
          commercial, 20 percent residential,  14 percent industrial, 10 percent
          contract wholesale and 1 percent  municipal.  Approximately 68 percent
          of our large commercial and industrial  customers are provided service
          under  long-term  contracts.   We  have  historically   optimized  the
          utilization of our power supply  resources by selling  wholesale power
          to other  utilities  and to power  marketers  in the spot  market  and
          through short-term sales contracts.

     o    In 1999,  the South Dakota Public  Utilities  Commission  extended our
          previous retail rate freeze for another five-years, through January 1,
          2005. The rate freeze  preserves our low-cost rate structure at levels
          below the national  average for our retail customers while allowing us
          to  retain  the  benefits   from  cost  savings  and  from   wholesale
          "off-system"  sales,  which are not covered by the rate  freeze.  This
          provides us with flexibility in allocating our generating  capacity to
          maximize returns in changing market environments.

     o    Twenty-nine  percent  of our  electric  revenues  for the  year  ended
          December 31, 2000 consisted of off-system  sales compared to 8 percent
          in 1999 and 5 percent  in 1998.  Further  increases  in the  volume of
          off-system  sales are  expected in the future due to demand  growth in
          the Rocky Mountain regions,  the June 2000 addition of 40 megawatts of
          gas-fired  generating  capacity  and the  availability  of  additional
          generation  resources  due  to  the  scheduled  closing  of  Homestake
          Mining's Black Hills operations at the end of 2001. We expect that the
          closing of  Homestake  Mining's  operations  will release over 100,000
          megawatthours  of energy per year,  or  approximately  4.3  percent of
          megawatthours sold by our utility in 2000.

     o    Our transmission system has the capability of connecting to either the
          midwestern or western  transmission  systems as a result of the recent
          completion of the "East Express"  feeder line,  which provides us with
          transmission access between the WSCC region and the Mid-Continent Area
          Power Pool, or "MAPP" region. This system allows us the opportunity to
          improve  customer  reliability  and  take  advantage  of  power  price
          differentials  between the two electric grids. Our system allows us to
          transmit  up  to  80  megawatts  of  our  generation  into  the  MAPP.
          Alternatively,  we can receive up to 20  megawatts  of power from MAPP
          into our WSCC-based  transmission  system.  We expect to increase this
          capability  to  50  megawatts  in  2001  through  an  upgrade  of  our
          transmission facilities at a cost of less than $1 million.

     o    We have firm  transmission  access to  deliver up to 65  megawatts  of
          power on Pacific Power's system to wholesale  customers in the western
          region.

     o    On October 15, 2000, we indicated to FERC our intent to participate in
          a regional transmission organization (RTO). Our transmission system is
          a part  of the  western  transmission  grid  governed  by the  Western
          Systems  Coordinating  Council, and it interconnects with transmission
          systems  operated by Western Area Power  Administration  (WAPA) and by
          PacifiCorp.  WAPA is evaluating  participation  in the Desert Star RTO
          which will involve  transmission systems in Colorado and the southwest
          region,  while PacifiCorp is evaluating  participation in the RTO West
          which will involve  transmission  systems in Wyoming and the northwest
          region.  Neither  Desert  Star  RTO nor RTO  West  has  been  formally
          organized  at this time,  but we expect  that  Desert Star RTO and RTO
          West will be making  their  final  FERC  filings  late this year or in
          early  2002.  If FERC  approves  these  two  RTOs,  the  organizations
          anticipate  being fully  operational in late 2002. We will continue to
          monitor  the  development  of these two RTOs and  decide in the future
          which RTO best fits our transmission system and operations.

Power Purchase  Agreements.  Approximately  40 percent of our utility's  current
load is under long-term contracts.  Our key contracts include a 10-year contract
expiring in 2007 with Montana-Dakota  Utilities Company for the sale of up to 55
megawatts  of energy and  capacity to service  the  Sheridan,  Wyoming  electric
service territory, and a contract with the City of Gillette,  Wyoming,  expiring
in 2012,  to provide the city's first 23 megawatts of capacity and energy.  Both
contracts are integrated  into our control system and are treated as firm native
load.  In addition,  we recently  entered into an agreement  with the  Municipal
Electric  Agency of Nebraska  for the sale of 30  megawatts  of unit  contingent
energy and capacity for a period through the completion of  construction  of the
Wygen I independent  power  facility,  which is expected in spring 2003. For the
10-year  period  beginning  with the  completion  of the Wygen I  facility,  our
utility and our  independent  power unit will each  provide 20 megawatts of unit
contingent energy and capacity to the Municipal Electric Agency of Nebraska.

Our  utility's  electric  load is served by coal-,  oil- and  natural  gas-fired
generating  units  providing 393  megawatts of generation  capacity and from the
following purchased power and capacity contracts with Pacific Power:

     o    a power sales agreement expiring in 2023, involving the purchase by us
          of 65 megawatts of baseload power in 2001, and scheduled to decline to
          50 megawatts by 2004;

     o    a reserve capacity integration agreement expiring in 2012, which makes
          available to us 100 megawatts of reserve  capacity in connection  with
          the utilization of the Ben French CT units; and

     o    a capacity option call,  which gives us an option to purchase up to 60
          megawatts of peaking capacity seasonally through March 31, 2007.

Regulated  Power  Plants.  Since 1995,  our  utility has been a net  producer of
energy. Our utility owns 393 megawatts of generating  capacity,  all of which is
located in the Rocky  Mountain  region.  Our  utility's  peak system load of 372
megawatts  was reached in July 2000.  None of our  generation  is  restricted by
hours of operation,  thereby  providing us with the ability to generate power to
meet demand whenever necessary and feasible.

The following table describes our utility's portfolio of power plants:

                                                    Total                         Net
                                Fuel               Capacity                    Capacity    Start
Power Plant                     Type     State      (MWs)         Interest       (MWs)      Date
- -----------                   -------    -----    ---------       --------     --------    ------
                                                                          
Ben French                    Coal       SD           25.0           100%          25.0     1960
Ben French Diesels 1-5        Diesel     SD           10.0           100%          10.0     1965
Ben French CTs 1-4            Gas/Oil    SD          100.0           100%         100.0   1977
                                                                                            1979
Neil Simpson I                Coal       WY           21.8           100%          21.8     1969
Neil Simpson II               Coal       WY           88.9           100%          88.9     1995
Osage                         Coal       WY           34.5           100%          34.5     1948
Wyodak                        Coal       WY          362.0            20%          72.4     1978
Neil Simpson CT               Gas        WY           40.0           100%          40.0     2000
                                                     -----                        -----
   Total                                             682.2                        392.6
                                                     =====                        =====

Ben French

Ben French is a  wholly-owned  coal-fired  plant  situated in Rapid City,  South
Dakota, with a capacity of 25 megawatts. This plant was put into service in 1960
and has  since  been  operating  as a  baseload  plant.  Coal  for the  plant is
purchased from our Wyodak mine and delivered by truck.

Ben French Diesel Units 1-5

The Ben French Diesel Units 1-5 are wholly-owned  diesel-fired plants located in
Rapid City, South Dakota, with a capacity of 10 megawatts. These plants were put
into service in 1965, and are being operated as peaking plants.

Ben French CT's 1-4

The Ben French Combustion  Turbines 1-4 are wholly-owned gas and oil-fired units
with a capacity of 100  megawatts  located in Rapid City,  South  Dakota.  These
facilities  were put into service from 1977 to 1979,  and are being  operated as
peaking units.

Neil Simpson I and II

Neil Simpson I and II are air-cooled, coal-fired wholly-owned facilities located
near Gillette,  Wyoming. Neil Simpson I has a capacity of 21.8 megawatts and was
put into service in 1969.  Neil Simpson II has a capacity of 88.9  megawatts and
was put into service in 1995. These plants are operated as baseload  facilities,
and are mine-mouth  coal-supplied plants, receiving their coal directly from the
Wyodak mine.

Osage

The Osage plant is a  wholly-owned  coal-fired  plant in Osage,  Wyoming  with a
total  capacity of 34.5  megawatts  and was put into  service from 1948 to 1952.
This  plant has three  turbine  generation  units,  and is being  operated  as a
baseload  plant.  Coal for the  plant is  purchased  from  our  Wyodak  mine and
delivered by truck.

Wyodak

Wyodak is a 362 megawatt  mine mouth  coal-fired  plant owned jointly by Pacific
Power  and us and in which we own a 20  percent  (72.4 net  megawatt)  ownership
interest.  Our Wyodak  mine  furnishes  all the coal fuel  supply for the Wyodak
plant.  The plant was put into service in 1978, and is currently  being operated
as a baseload plant.

Neil Simpson CT

The Neil Simpson  Combustion  Turbine is a wholly-owned  gas-fired plant located
near Gillette,  Wyoming with a capacity of 40 megawatts. This plant was put into
service in 2000, and was installed to provide peaking capabilities.

Communications

Our communications  group, known as Black Hills FiberCom,  was formed to provide
state-of-the-art  broadband   telecommunications  services  to  the  underserved
markets of Rapid City and the  northern  Black Hills of South  Dakota.  We offer
residential and business customers a full suite of telecommunications  services,
including local and long distance telephone  service,  expanded cable television
service,  cable modem Internet access and high speed data and video services. We
have  completed  a 210-mile  inter-  and  intra-city  fiber  optic  network  and
currently operate 588 miles of two-way interactive hybrid fiber coaxial or "HFC"
cable.  We believe  we are one of the first  companies  in the United  States to
provide video entertainment  service,  high-speed Internet access, and local and
long distance telephone services over an advanced broadband  infrastructure.  We
have bundled these services into value packages with a single  consolidated bill
for all of these services.

We  introduced  our  broadband  communications  services  to the Rapid  City and
northern  Black Hills areas in November  1999.  As of December 31, 2000,  we had
attracted 8,368 residential customers and 646 business customers. Our goal is to
increase the number of our customers by more than two-fold, and to attain within
our service territory 50 percent residential market penetration while serving 35
percent of all broadband business customers.

The build out of our communications network is approximately 70 percent complete
and is expected to be  completed in 2001.  We estimate  that  completion  of the
build-out will require approximately $25 million in 2001.

Competition

The  independent  power,  fuel  production  and fuel  marketing  industries  are
characterized by numerous strong and capable competitors, some of which may have
more  extensive  operating  experience,   larger  staffs  or  greater  financial
resources than us. In particular, the independent power industry in recent years
has  been  characterized  by  increased  competition  for  asset  purchases  and
development opportunities.

In  addition,   Congress  has  considered   various  pieces  of  legislation  to
restructure  the  electric  industry  that would  require,  among other  things,
customer choice and/or repeal of the Public Utility Holding Company Act of 1935,
or "PUHCA".  The debate is likely to continue and perhaps intensify.  The effect
of enacting such  legislation  cannot be predicted with any degree of certainty.
Industry  deregulation may encourage the disaggregation of vertically integrated
utilities into separate generation, transmission and distribution businesses. As
a  result  of  these  potential  regulatory  changes,   significant   additional
competitors could become active in the generation segment of our industry.

Our  communications  unit  faces  competition  from  numerous  well  established
companies, including Qwest Communications, Rapid City's incumbent local exchange
carrier,  Midcontinent  Communications,  the area's  incumbent cable  television
provider, as well as long distance providers and Internet service providers. Our
success in this  business will depend upon,  among other things,  the quality of
our customer service,  the willingness of residential and business  customers to
accept us as an alternative provider of broadband  communications  services, our
products and services and our ability to offer an attractive  package of bundled
products.

Risk Management

Our fuel  marketing  operations  require  efficient  risk  management  of price,
counterparty  performance and operational  risks.  Price risk is created through
the volatility of energy prices.  Counterparty performance risk is the risk that
a  counterparty  will fail to satisfy  its  contractual  obligations  to us, and
includes credit risk.  Operational risk arises from a lack of internal controls.
We have implemented controls to mitigate each of these risks.

Our fuel  marketing  operations  are  conducted in  accordance  with  guidelines
established  through  separate risk management  policies and procedures for each
marketing company and through our credit policy.  These policies are established
by our  board of  directors,  reviewed  on a  regular  basis  and  monitored  as
described below.

We  maintain  a working  risk  management  committee  for each of our  marketing
companies,  and a  credit  committee  at the  parent  company  level.  The  risk
management  committees focus on implementation of risk management procedures and
on monitoring  compliance with established  policies.  The credit committee sets
counterparty  credit  limits,   monitors  credit  exposure  levels  and  reviews
compliance with  established  credit  policies.  Additionally,  we employ a risk
manager and a credit manager responsible for overseeing these functions.

Our risk management  policies and procedures specify maximum price risk exposure
levels  that each  respective  marketing  company  must  operate  within.  These
policies and procedures  establish  relatively low exposure  levels and prohibit
speculative trading strategies.

As part of our enterprise-wide risk management  strategy,  we limit our exposure
to energy marketing risks by maintaining  separate credit facilities within each
of our fuel marketing companies. These credit facilities have security interests
solely  against  the  assets  of the  respective  marketing  company,  with  the
exception  of a $1 million  guarantee by our coal mining  subsidiary.  We do not
currently issue parent company  performance  guarantees to counterparties of our
marketing companies.

A  significant  potential  risk related to power sales is the price risk arising
from the sale of wholesale  power that exceeds our  generating  capacity.  Short
positions  can arise from  unplanned  plant outages or from  unanticipated  load
demands.  To control  such risks,  we  restrict  wholesale  off-system  sales to
amounts by which our anticipated generation  capabilities exceed our anticipated
load  requirements  plus a required reserve margin. We further control this risk
by selling only in the day-ahead  power market and by entering into  longer-term
sales contracts that are made on a "unit contingent" basis, under which delivery
is not required during unplanned outages at specified power plants.

California Markets

In 1996, California enacted legislation restructuring the state's investor-owned
utilities.   The   legislation   instituted   a  rate  freeze  on  amounts  that
investor-owned  utilities  could  charge their  customers  for the duration of a
transition  period also established by the legislation.  The legislation did not
make any  provision  for a  California  utility  to recover  costs of  purchased
electricity that exceeded the rates that could be charged under the rate freeze.
Due to inadequate  supplies of power and an unanticipated  surge in demand,  the
California  market has experienced rapid increases in electric power and natural
gas prices.  As a result,  the state's  two  largest  investor-owned  utilities,
Pacific Gas & Electric Company (PG&E) and Southern California Edison (SCE), have
incurred costs of procuring  power  significantly  in excess of their ability to
recover those costs through  authorized  retail rates and have  indicated  that,
unless the rate freeze is eliminated or other proposed relief is provided,  they
are, or shortly will, become insolvent.

We may experience  losses related to the potential  insolvency of the California
utilities in the event that a utility defaults on its obligations:

     o    under its agreements with us;

     o    to the CAISO,  which  administers the real-time markets for energy and
          ancillary services, resulting in non-payment to us; or

     o    to other energy  companies,  causing those energy companies to default
          on their obligations to us.

          We   have two agreements with SCE involving our California independent
          power plants.

     o    In 1999, we entered into a settlement agreement with SCE involving our
          Harbor Cogeneration plant located in Wilmington,  California, in which
          we own a 31.8 percent interest.  The settlement agreement provides for
          the termination of a 30-year power purchase  agreement in exchange for
          payments of  approximately  $4 million per year by SCE through October
          2008.

     o    The cogeneration  plant located in Ontario,  California is entitled to
          receive energy and capacity  payments from SCE of  approximately  $1.7
          million per year, under a long-term contract expiring in 2010.

As of March 1, 2001,  we had  approximately  $1.5  million of past due  accounts
receivable from SCE, with delinquencies  ranging from 15 to 75 days in duration.
We have no other  material  contractual  relationships  with SCE and no material
agreements with PG&E.

The summer peaking capacity from the expansion of the Harbor  Cogeneration plant
will be sold to the CAISO  beginning in May 2001 and ending in May 2003 under an
agreement with the CAISO that provides for payments to us of $3 million per year
for each of 2001, 2002 and 2003. We have no other  agreements with the CAISO and
do not otherwise sell capacity and energy  directly into the  California  market
either through  long-term  contracts or on a merchant basis.  All other merchant
sales are made to power  marketers who in turn sell into the California  market.
In addition,  our fuel production and fuel marketing  exposure to the California
market is  primarily  indirect  through  sales to  creditworthy  counterparties,
including neighboring utilities and large, well-established gas marketing firms.

In recent months,  the Governor of the State of California,  representatives  of
the state legislature and numerous industry participants have undertaken several
initiatives  designed to address market  disruptions in California.  In February
2001,  SCE reached a tentative  agreement  under which the state would pay $2.76
billion to purchase SCE's high voltage  transmission system and SCE would drop a
federal lawsuit in which it has sought  authority to bill its customers for past
unrecovered costs. Prior to its implementation,  this agreement must be approved
by the California state legislature.  There is no assurance that any legislation
will be  enacted or that,  if  enacted,  the sale of  transmission  assets  will
provide SCE with  sufficient  funds to pay any current or future  obligations to
us. In addition,  there is no assurance  that any current or future  defaults by
California  utilities on obligations  owed to others will not result in defaults
by our counterparties. However, we believe that our direct exposure to potential
defaults in the California  market is largely limited to the agreements with SCE
and the CAISO described above and that our indirect exposure is minimal.

Regulation

We are  subject  to a broad  range  of  federal,  state  and  local  energy  and
environmental laws and regulations applicable to the development,  ownership and
operation of our projects.  These laws and regulations  generally require that a
wide variety of permits and other approvals be obtained  before  construction or
operation of a power plant commences and that,  after  completion,  the facility
operate in  compliance  with their  requirements.  We strive to comply  with the
terms of all such laws,  regulations,  permits and licenses and believe that all
of our  operating  plans are in  material  compliance  with all such  applicable
requirements.

Energy Regulation

Federal  Power  Act.  The  Federal  Power Act gives FERC  exclusive  rate-making
jurisdiction  over  wholesale  sales  of  electricity  and the  transmission  of
electricity  in  interstate  commerce.  Pursuant to the Federal  Power Act,  all
public  utilities  subject  to FERC's  jurisdiction  are  required  to file rate
schedules  with FERC prior to  commencement  of  wholesale  sales or  interstate
transmission of electricity. Public utilities with cost-based rate schedules are
also  subject  to   accounting,   record-keeping   and  reporting   requirements
administered by FERC.

The Energy  Policy  Act.  The passage of the Energy  Policy Act in 1992  further
encouraged  independent  power production by providing  certain  exemptions from
regulation for exempt  wholesale  generators or "EWGs." All of our  subsidiaries
that would  otherwise be treated as public  utilities are  currently  treated as
EWGs  under the  Energy  Policy  Act.  An EWG is an entity  that is  exclusively
engaged,  directly  or  indirectly,  in the  business  of  owning  or  operating
facilities  that are  exclusively  engaged in  generation  and selling  electric
energy at wholesale. An EWG will not be regulated under PUHCA, but is subject to
FERC and state public  utility  commission  regulatory  reviews,  including rate
approval.  Since EWGs are only allowed to sell power at  wholesale,  their rates
must receive initial approval from FERC rather than the states.  All of our EWGs
to date that have sought rate approval from FERC have been granted  market-based
rate authority,  which allows FERC to waive certain  accounting,  record-keeping
and reporting  requirements  imposed on public utilities with cost-based  rates.
However,  FERC  customarily  reserves  the  right to  suspend,  upon  complaint,
market-based  rate  authority  on a  prospective  basis  if it  is  subsequently
determined  that we or any of our EWGs exercised  market power.  If FERC were to
suspend market-based rate authority,  it would most likely be necessary to file,
and obtain FERC  acceptance of,  cost-based  rate schedules for any of our EWGs.
Also,  the loss of  market-based  rate  authority  would subject the EWGs to the
accounting, record-keeping and reporting requirements that are imposed on public
utilities with cost-based rate schedules.

In addition,  if there occurs a "material change" in facts that might affect any
of our subsidiaries'  eligibility for EWG status, within 60 days of the material
change, the relevant EWG must (1) file a written explanation of why the material
change  does not  affect  its EWG  status,  (2) file a new  application  for EWG
status,  or (3) notify FERC that it no longer wishes to maintain EWG status.  If
any of our subsidiaries were to lose EWG status,  we, along with our affiliates,
would be subject to regulation under PUHCA as a public utility company. Absent a
substantial  restructuring  of our  business,  it would be  difficult  for us to
comply with PUHCA without a material adverse effect on our business.

State Energy Regulation.  In areas outside of wholesale rate regulation (such as
financial or organizational regulation),  some state utility laws may give their
public utility commissions broad jurisdiction over steam sales or EWGs that sell
power in their service  territories.  The actual scope of the jurisdiction  over
steam  or  independent   power   projects   depends  on  state  law  and  varies
significantly from state to state.

Environmental Regulation

The  construction  and  operation  of power  projects  are subject to  extensive
environmental  protection and land use  regulation in the United  States.  These
laws and  regulations  often require a lengthy and complex  process of obtaining
licenses,  permits and approvals from federal, state and local agencies. If such
laws and  regulations  are changed  and our  facilities  are not  grandfathered,
extensive   modifications  to  project  technologies  and  facilities  could  be
required.

General.  Based on current  trends,  we expect that  environmental  and land use
regulation  will  continue to be  stringent.  Accordingly,  we  actively  review
proposed  construction  projects  that could  subject us to stringent  pollution
controls imposed on "major  modifications,"  as defined under the Clean Air Act,
and changes in  "discharge  characteristics,"  as defined  under the Clean Water
Act.  The  goal of  these  actions  is to  achieve  compliance  with  applicable
regulations,   administrative  consent  orders  and  variances  from  applicable
air-quality related regulations.

Clean Air Act.  Our Neil  Simpson II and  Wyodak  plants  located  in  Gillette,
Wyoming are  subject to Title IV of the Clean Air Act,  which  requires  certain
fossil-fuel-fired  combustion  devices to hold sulphur dioxide  "allowances" for
each ton of sulphur dioxide  emitted.  We currently hold  sufficient  allowances
credited to us as a result of sulfur removal equipment  previously  installed at
the Wyodak plant to apply to the  operation of the Neil Simpson II plant and our
interest in the Wyodak plant through 2030 without  requiring the purchase of any
additional allowances. With respect to any future plants, we plan to comply with
the need for holding the  appropriate  number of allowances by reducing  sulphur
dioxide  emissions  through the use of low sulphur fuels,  installation of "back
end" control  technology  and the purchase of allowances on the open market.  We
expect to integrate  the costs of obtaining  the required  number of  allowances
needed for future projects into our overall financial analysis of such projects.

Our  plants  are  subject to a variety of  regulations  governing  emissions  of
nitrogen oxides (NOx). On July 14, 2000, the South Coast Air Quality  Management
District (SCAQMD) sent a letter to our affiliate,  Indeck Ontario, L.L.C (Indeck
Ontario), the owner and operator of a 12 megawatt natural-gas fired cogeneration
facility located in Ontario,  California  (Ontario  Facility),  stating that the
SCAQMD  had  determined,  as a result  of a  facility  audit  completed  for the
compliance  year ended June 1, 1999,  that the Ontario  Facility's NOx emissions
were 28,958 pounds over the Ontario Facility's NOx allocation established by the
SCAQMD's RECLAIM  emissions trading program.  As a result,  the SCAQMD indicated
that it would be reducing  the Ontario  Facility's  NOx  allocation  by the same
number of allowances for the compliance year subsequent to a final determination
on this issue. If a final  determination  is reached prior to June 30, 2001, the
NOx allowances would be deducted from the Ontario Facility's  allocation for the
compliance year ended June 30, 2002.  Indeck Ontario has provided  documentation
to the SCAQMD  disputing this proposed  reduction.  In addition to this proposed
reduction,  which could affect the Ontario  Facility's  compliance  with RECLAIM
requirements for the 2001-2002  compliance period,  Indeck Ontario also projects
that its NOx  emissions  for the  compliance  year  ended  June 30,  2001 may be
approximately 30,000 pounds over its current NOx allocation.  There is currently
significant  volatility  in the price  and  supply of  RECLAIM  NOx  allowances;
although  the  SCAQMD has  proposed  a revision to its  regulations to stabilize
the RECLAIM  market,  it is  unclear whether  such  rules  will  minimize Indeck
Ontario's   potential   exposure   for   its   projected  allowance   shortfall.
Accordingly,  no   assuance  can  be given   at   this  time  regarding  whether
RECLAIM NOx  allowances   will  be   available  for  purchase  to  allow  Indeck
Ontario  to  comply  with  RECLAIM  requirements  for  the  year  ended June 30,
2001, or, if  allowances  are  available,  the  cost of such allowances.  Indeck
Ontario  may   also  be  subject  to  administrative  or  civil  penalties  with
respect  to  alleged  violations  of  the SCAQMD's regulation for the compliance
year ended June 30,  1999,  although  no  notice  of  such  penalties  has  been
issued.

In July 1999, the United States Environmental  Protection Agency (EPA) finalized
rules designed to protect and improve visibility  impairment  resulting from air
emissions.  Among other  things,  the  regulations  required  states to identify
sources of  emissions  (including  certain  coal-fired  generating  units  built
between 1962 and 1977) by 2004 that would be subject to Best Available  Retrofit
Technology (BART). These sources would be required to implement BART within five
years  after  the  EPA  approved  state  plans  adopted  to  combat   visibility
impairment.  The  submission  of these  plans is due between  2004 and 2008.  In
January 2001, the EPA proposed  guidance to assist states in  determining  which
sources should be subject to the BART requirement, but the proposed guidance has
not been published pending a review by the newly appointed  Administrator of the
EPA. Currently, the best available technology consists of "scrubbers," which are
devices that trap  pollutants in  power-plant  stacks.  While we have  installed
scrubbers in our Wyodak and Neil  Simpson II plants,  we have not done so at the
remainder  of  our  coal-fired  plants.  If  the  proposed  rules  are  adopted,
management believes that the only existing plant which may be required to comply
with Clean Air Act requirements is our Neil Simpson I plant and that any capital
expenditures associated with bringing the plant into compliance would not have a
material adverse effect on our financial condition or results of operations.

Title V of the Clean Air Act imposes federal requirements which dictate that all
of our fossil fuel-fired  generation  facilities must obtain operating  permits.
All of our existing facilities subject to this requirement have submitted timely
Title V permit applications and received permits.

On November 3, 1999, the United States  Department of Justice filed suit against
a number of electric  utilities  for alleged  violations  of the Clean Air Act's
"new source  review"  requirements  related to  modifications  of air  emissions
sources at electric  generating  stations located in the southern and midwestern
regions of the United  States.  Several  states have joined these  lawsuits.  In
addition,  the EPA has also issued administrative  notices of violation alleging
similar  violations  at  additional  power  plants  owned  by some  of the  same
utilities  named as defendants in the  Department of Justice  lawsuit,  and also
issued an  administrative  order to the Tennessee  Valley  Authority for similar
violations at certain of its power plants.  The EPA has also issued requests for
information  pursuant to the Clean Air Act to numerous other electric  utilities
seeking to determine whether those utilities also engaged in activities that may
have been in violation of the Clean Air Act's new source review requirements. To
date, we are aware of three large  utilities  that have either  settled with the
United  States or have reached  agreements in principle to resolve such actions.
In each case,  the settling  party has agreed (or agreed in  principle) to incur
over $1 billion in expenditures  for the  installation  of additional  pollution
control,   the  retirement  or  repowering  of  coal-fired   generating   units,
supplemental  environmental  projects and civil  penalties.  No such proceedings
have been  initiated or requests for  information  issued with respect to any of
our  facilities,  but there can be no  assurance  that we will not be subject to
such proceedings in the future.

In December 2000, the EPA announced its intention to regulate mercury  emissions
from  coal-fired  and oil-fired  electric  power plants under Section 112 of the
Clean  Air Act.  The EPA is  committed  to  proposing  a rule to  regulate  such
emissions by no later than 2003. Because we do not know what the EPA may require
with respect to this issue,  we are not able to evaluate the impact of potential
mercury  regulations on the operation of our  facilities.  Since the adoption of
the United Nations Framework on Climate Change in 1992, there has been worldwide
attention  with respect to  greenhouse  gas  emissions.  In December  1997,  the
Clinton Administration participated in the Kyoto, Japan negotiations,  where the
basis of a Climate Change treaty was formulated.  Under the treaty, known as the
Kyoto Protocol, the United States would be required, by 2008-2012, to reduce its
greenhouse  gas  emissions by 7 percent from 1990  levels.  However,  because of
opposition to the treaty in the United States Senate, the Kyoto Protocol has not
been submitted to the Senate for ratification.  Although we are beginning to see
legislative  developments  on the state level related to controlling  greenhouse
gas emissions,  we are not aware of any such developments in the states in which
we operate.  If the United  States  ratifies the Kyoto  Protocol or we otherwise
become  subject to  limitations  on emissions of carbon dioxide from our plants,
such requirements could have a significant impact on our operations.

Clean Water Act. Our existing  facilities are also subject to a variety of state
and  federal  regulations  governing  existing  and  potential  water/wastewater
discharges.  Generally,  such regulations are promulgated under authority of the
Clean Water Act and govern overall water/wastewater  discharges through National
Pollutant Discharge Elimination System (NPDES) permits. Under current provisions
of the Clean Water Act, existing NPDES permits must be renewed every five years,
at which time  permit  limits are  extensively  reviewed  and can be modified to
account for changes in  regulations  or program  initiatives.  In addition,  the
permits have re-opener  clauses which allow the permitting  authority (which may
be the United  States or an  authorized  state) to attempt to modify a permit to
conform to changes in  applicable  laws and  regulations.  Some of our  existing
facilities  have been operating under NPDES permits for many years and have gone
through one or more NPDES permit  renewal  cycles.  Two of these  facilities are
currently in the process of renewing their existing NPDES permits.

Solid Waste  Disposal.  We dispose of all solid wastes  collected as a result of
burning coal at our 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 and Neil
Simpson II plants are deposited in 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.   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 if the
federal or state government determines that solid waste from the burning of coal
contains some  hazardous  material that requires  special  treatment,  including
solid  waste of which we  previously  disposed.  In that event,  the  government
regulator  could  consequently  hold those  entities that disposed of such waste
responsible for such treatment.

Mine Reclamation.  Under federal and state laws and regulations, we are required
to  submit  to the  regulation  by,  and  receive  approval  from,  the  Wyoming
Department  of  Environmental  Quality (DEQ) for a mining and  reclamation  plan
which provides for orderly  mining,  reclamation  and  restoration of all of our
Wyodak  cool mine in  conformity  with  state laws and  regulations.  We have an
approved  mining permit and are otherwise in compliance  with other land quality
permitting programs.

One situation  that could result in  substantial  unexpected  increases in costs
relating to our  reclamation  permit  concerns three  depressions -- the "south"
depression, the "Peerless" depression and the "North Pit" depression - that have
or will result from our mining  activities  at the Wyodak  mine.  Because of the
thick coal seam and relatively shallow overburden,  the current restoration plan
would leave these depressions,  which have limited reclamation  potential,  with
interior drainage only.  Although the DEQ has accepted the current plan to limit
reclamation  of these  depressions,  it has  reserved  the right to  review  and
evaluate  future  reclamation  plans or to reevaluate  the existing  reclamation
plan. If as a result of our mining  activities,  additional  overburden  becomes
available,  the DEQ may  require us to  conduct  additional  reclamation  of the
depressions,  particularly if the DEQ finds that the current limited reclamation
is resulting  in  exceedances  in the DEQ's water  quality  standards.  Based on
extensive  reclamation  studies,  we  have  currently  estimated  the  cost  for
reclamation for our mine at approximately $26 million and have currently accrued
approximately $17.7 million on our balance sheet for these reclamation costs. No
assurance can be given that additional requirements in the future may be imposed
that would cause an unexpected material increase in reclamation costs.

Ben French Oil Spill. In 1990 and 1991, we discovered extensive underground fuel
oil  contamination  at the Ben  French  plant  site.  With  the  help of  expert
consultants,  we worked closely with the South Dakota  Department of Environment
and Natural  Resources to assess and  remediate  the site.  Our  assessment  and
remediation  efforts  continue today and we continue to monitor the site. All of
our 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.  Soil borings and monitoring  wells on the perimeters of our
Ben French plant  property  provide 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  $472,000,  of which amount
$386,000 has been reimbursed by the South Dakota Petroleum Release  Compensation
Fund.  To date,  no  penalties,  claims or actions have been taken or threatened
against us 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 were widely used as  insulating  fluids in many  electric  utility
transformers and capacitors manufactured before the Toxic Substances Control Act
prohibited any further  manufacture  of PCB equipment.  We remove and dispose of
PCB-contaminated equipment in compliance with law as it is discovered.

Release of PCB-contaminated fluids, especially any involving a fire or a release
into a waterway,  could result in substantial cleanup costs.  Several years ago,
we began testing program of potential PCB-contaminated transformers, and in 1997
completed  testing of all  transformers  and capacitors which are not located in
our electric substations.  We have not completed the testing of sealed potential
transformers and bushings located in our electric  substations as the testing of
this equipment requires their destruction. Release of PCB-contaminated fluid, if
present,  from  our  equipment  is  unlikely  and the  volume  of  fluid in such
equipment is generally less than one gallon. Moreover, any release of this fluid
would be confined to our substation site.

Exploration and Production

Our oil and gas  exploration  and  production  operations are subject to various
types of regulation at the federal, state and local levels. They include:

     o    requiring permits for the drilling of wells;

     o    maintaining bonding requirements in order to drill or operate wells;

     o    submitting and implementing spill prevention plans;

     o    submitting  notification relating to the presence,  use and release of
          certain contaminants incidental to oil and gas operations;

     o    regulating  the  location of wells,  the method of drilling and casing
          wells,  the use,  transportation,  storage and  disposal of fluids and
          materials used in connection with drilling and production  activities;
          and

     o    regulating  surface usage and the restoration of properties upon which
          wells have been drilled,  the plugging and abandoning of wells and the
          transporting of production.

Our operations are also subject to various conservation  matters,  including the
regulation  of the size of drilling and spacing  units or proration  units,  the
number of wells which may be drilled in a unit and the unitization or pooling of
oil and gas properties.  In this regard, some states allow the forced pooling or
integration  of tracts to  facilitate  exploration  while  other  states rely on
voluntary  pooling  of lands and  leases,  which may make it more  difficult  to
develop oil and gas properties.  In addition,  state conservation laws establish
maximum  rates of  production  from oil and gas wells,  generally  prohibit  the
venting or flaring of gas and impose certain requirements  regarding the ratable
purchase of production.  The effect of these regulations is to limit the amounts
of oil and gas we can produce from our wells and to limit the number of wells or
the locations at which we can drill.  In addition,  various  federal,  state and
local laws and  regulations  concerning the discharge of  contaminants  into the
environment,   the   generation,   storage,   transportation   and  disposal  of
contaminants and the protection of public health,  natural  resources,  wildlife
and environment  affect our exploration,  development and production  operations
and our related costs.

Other Properties

In addition to the other  properties  described  herein,  we own an  eight-story
office building  consisting of approximately  47,000 square feet of office space
in Rapid City, South Dakota. We occupy  approximately 27,000 square feet in this
building and lease the remainder to others.

Employees

At  December  31,  2000,  we had 635  employees,  approximately  332 of whom are
employed in our utility  business,  170 of whom are employed in our  independent
energy businesses and 133 of whom are employed in our communications business.

Approximately  one-half  of our  utility  employees  are  covered by  collective
bargaining  agreements with the International  Brotherhood of Electrical Workers
which  expire  on  April 1,  2003.  We have  experienced  no  significant  labor
stoppages or labor disputes at our facilities.

ITEM 3.  LEGAL PROCEEDINGS

PacifiCorp Litigation

In August 2000, we initiated an action in the United States  District  Court for
the District of Wyoming against  PacifiCorp  relating to a coal supply agreement
between  PacifiCorp  and us.  We  believe  that  PacifiCorp  has  failed to make
complete  payment to us for coal sold under the coal supply  agreement  and that
PacifiCorp continues to underpay its monthly coal bill by approximately $100,000
per month. We believe that PacifiCorp's  actions constitute a breach of the coal
supply agreement and have asked for relief in the amount of $5,000,000, plus all
underpayments since the commencement of our lawsuit.

PacifiCorp  subsequently brought a counterclaim against us, alleging that we had
not properly  adjusted upward and downward the components which make up the coal
price under the coal  supply  agreement,  resulting  in alleged  overbilling  to
PacifiCorp of $35,000,000 to $40,000,000  over an undefined  period.  PacifiCorp
further alleged that if past practices continue our adjustment  methodology will
result in  additional  overcharges  of  approximately  $150,000,000  through the
balance of the term of the coal supply agreement, which expires in June of 2013.
In its action,  PacifiCorp  sought to cancel and  terminate  the contract and to
recover monetary damages as proven at trial.

Management  believes that we have properly billed  PacifiCorp under the terms of
the  coal  supply  agreement  and  that  PacifiCorp's   withholding  of  payment
constitutes  a breach of contract on their part.  Although it is  impossible  to
predict whether we will ultimately be successful in defending PacifiCorp's claim
or, if not  successful,  what the  impact  might be,  management  believes  that
disposition  of this  matter  will not have a  material  adverse  effect  on our
consolidated  results  of  operations  or  financial  condition.   In  addition,
management  believes that the pending  litigation  has not affected and will not
affect our other agreements with PacifiCorp's subsidiary, Pacific Power.

Other Litigation

There are no other  material  legal  proceedings  pending,  other than  ordinary
routine  litigation  incidental to our business,  to which we are a party. There
are no material legal  proceedings to which an officer or director is a party or
has a material interest adverse to us or our subsidiaries. There are no material
administrative or judicial  proceedings arising under  environmental  quality or
civil  rights  statutes  pending  or known to be  contemplated  by  governmental
agencies  to  which we are or would be a party  other  than the  SCAQMD  RECLAIM
requirements on the Ontario Facility "see ITEMS 1 AND 2. BUSINESS AND PROPERTIES
- - Regulation - Environmental Regulation - Clean Air Act."

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 2000.

PART II

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

Our  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 5,708  common  shareholders  of record.  All 50 states and the
District of Columbia plus 10 foreign countries are represented.

We have declared common stock  dividends  payable in cash in each year since our
predecessor's  incorporation in 1941. At our January 2001 meeting,  the Board of
Directors raised the quarterly  dividend to 28.0 cents per share,  equivalent to
an annual increase of 4.0 cents per share.  This regular  quarterly  dividend is
payable  March 1, 2001.  Dividend  payment  dates are normally  March 1, June 1,
September 1 and December 1.

Quarterly  dividends  paid and the high and low common stock prices for the last
two years were as follows:

Year ended December 31, 2000

                                                  1st                   2nd                   3rd                    4th
                                                  ---                   ---                   ---                    ---
                                                                                                        
Dividends paid per share                         $0.27                 $0.27                  $0.27                 $0.27
Common stock prices
     High                                       $25.19                $25.19                 $30.13                $46.06
     Low                                        $20.44                $20.88                 $22.00                $27.00

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

ITEM 6.  SELECTED FINANCIAL DATA

Years ended December 31,                                     2000            1999            1998           1997           1996
                                                             ----            ----            ----           ----           ----
                                                                                                            
TOTAL ASSETS (in thousands)                               $1,320,320         $668,492      $559,417         $508,741       $467,354

PROPERTY AND INVESTMENTS
     (in thousands)
    Total property and investments                        $1,136,094         $710,488      $619,549         $598,306       $581,537
    Accumulated depreciation and depletion                   277,848          246,299       229,942          197,179        181,103
    Capital expenditures (includes AFUDC)                    177,189*         154,609        27,225           28,319         24,388

CAPITALIZATION (in thousands)
    Long-term debt                                          $307,092         $160,700      $162,030         $163,360       $164,691
     Preferred stock equity                                    4,000                -             -                -              -
    Common stock equity                                      278,346          216,606       206,666          205,403        193,175
                                                           ---------        ---------     ---------        ---------      ---------

         Total capitalization                               $589,438         $377,306      $368,696         $368,763       $357,866
                                                            ========         ========      ========         ========       ========

CAPITALIZATION RATIOS
    Long-term debt                                            52.1%            42.6%           43.9%          44.3%          46.0%
     Preferred stock equity                                    0.7              -               -              -              -
    Common stock equity                                       47.2             57.4            56.1           55.7           54.0
                                                            ------           ------          ------         ------         ------
         Total                                               100.0%           100.0%          100.0%         100.0%         100.0%
                                                             =====            =====           =====          =====          =====

AVERAGE INTEREST RATE ON LONG-TERM DEBT
                                                               8.2%             8.1%            8.1%           8.1%           8.1%

TOTAL OPERATING REVENUES                                  $1,623,836         $791,875      $679,254         $313,662       $162,588

NET INCOME AVAILABLE FOR
    COMMON        STOCK (in thousands)                       $52,770          $37,067       $25,808**        $32,359        $30,252

DIVIDENDS PAID ON COMMON STOCK
    (in thousands)                                           $23,527          $22,602       $21,737          $20,540        $19,930

COMMON STOCK DATA
(in thousands)
    Shares outstanding, average                               22,118           21,445        21,623           21,692         21,660
    Shares outstanding, end of year                           22,921           21,372        21,578           21,705         21,675
(in dollars)
     Basic earnings per average share                      $    2.39        $    1.73     $    1.19**      $    1.49      $    1.40
    Diluted earnings per average share                     $    2.37        $    1.73     $    1.19**      $    1.49      $    1.40
    Dividends paid per share                               $    1.08        $    1.04     $    1.00        $    0.95      $    0.92
    Book value per share, end of year                       $  12.14         $  10.14     $    9.58        $    9.46      $    8.91

RETURN ON COMMON STOCK EQUITY (year-end)
                                                               19.0%            17.1%         12.5%*           15.8%          15.7%

 *Excludes the non-cash acquisition of Indeck Capital, Inc.
**Includes impact of $8.8 million, or 41 cents per average share, write down of
  certain oil and gas properties

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

We are a  growth  oriented, diversified  energy  holding  company  operating
principally in the United States. Our regulated and unregulated  businesses have
expanded  significantly in recent years.  Our independent  energy group produces
and  markets  fuel and power.  We produce  and sell  electricity  in a number of
markets,  with a strong emphasis in the western United States.  We produce coal,
natural gas and crude oil primarily in the Rocky Mountain region and market fuel
products  nationwide.  We also own Black Hills Power,  Inc., an electric utility
serving   58,600   customers  in  South   Dakota,   Wyoming  and  Montana.   Our
communications group offers state-of-the-art  broadband  communications services
to residential and business customers in Rapid City and the northern Black Hills
region of South Dakota.

At our  annual  meeting  of  shareholders  on June 20,  2000,  our  shareholders
approved  the  formation  of a  holding  company  structure  through  a "plan of
exchange" between Black Hills  Corporation and Black Hills Holding  Corporation.
The plan of exchange provided that each share of Black Hills Corporation  common
stock would be exchanged  for one share of common stock of the holding  company.
The  formation of our holding  company  structure  allows us to pursue,  through
separate subsidiaries,  business opportunities in both regulated and unregulated
markets.

On December  22,  2000,  articles of exchange  were filed with the South  Dakota
Secretary of State. As a result:

o    all common  shareholders of Black Hills Corporation became  shareholders of
     Black Hills Holding Corporation, the holding company;

o    Black Hills Corporation became a wholly-owned subsidiary of Black Hills
     Holding Corporation;

o    Black Hills Corporation  changed its name to "Black Hills Power,  Inc." and
     the holding company changed its name to "Black Hills Corporation;" and

o    Black  Hills  Power's  debt  securities  and  other  financial  obligations
     continue to be obligations of Black Hills Power.

                              Results of Operations

Consolidated Results

Consolidated  net income for 2000 was $52.8 million compared to $37.1 million in
1999 and  $25.8  million  in 1998 or $2.37  per  average  common  share in 2000,
compared  to $1.73  and  $1.19  per  average  common  share  in 1999  and  1998,
respectively.  This  equates to a 19.0  percent,  17.1  percent and 12.5 percent
return on year-end common equity in 2000, 1999 and 1998, respectively.

We  reported  record  earnings  in 2000  primarily  due to  strong  natural  gas
marketing  activity,  increased fuel  production,  expanded power generation and
increased  off-system  electric utility  wholesale sales.  Strong results in our
independent  energy  business  group in 2000 were  partially  offset by start-up
losses in our communications business. Unusual energy market conditions stemming
primarily from gas and  electricity  shortages in California  contributed to our
strong financial performance in 2000.

Earnings per share for 2000 were  approximately  $0.40 higher due to  prevailing
prices of gas and  electricity  and extremely wide gas trading  margins that may
not recur in the future.  Some of the energy markets in which we are active have
recently  experienced  extreme  volatility  resulting from California's fuel and
electricity  shortages.  Our fuel  production,  fuel  marketing  and power sales
exposure in these markets is primarily  indirect  through sales to credit-worthy
counterparties,  including  neighboring  utilities  and gas and power  marketing
firms.

Earnings  in 1999  increased  over  1998 due  primarily  to sales  growth in our
electric utility and improved results in our independent  energy business group,
partially offset by expected start-up losses in our communications business.

In 1998, we 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, our
earnings per average common share for 1998 would have been $1.60, and our 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
a decline in value of certain unevaluated properties.

Consolidated  revenues were $1.6 billion,  $791.9  million and $679.3 million in
2000, 1999 and 1998,  respectively,  representing a 105 percent increase in 2000
and a 17 percent increase in 1999.

The  dramatic  growth in revenues in 2000 was a result of high energy  commodity
prices and increased volumes of fuel marketed,  primarily as a result of extreme
price  volatility  in  the  western  markets,  acquisitions  and  growth  in the
independent  energy  business  group and  increases in  off-system  sales by our
electric  utility.  Natural gas prices  increased from an average of $1.97-$2.15
per MMcf in 1998 and 1999 to $4.19 per MMcf in 2000.  Daily  volumes  of natural
gas marketed increased 36 percent from 635,500 MMBtus per day in 1999 to 860,800
MMBtus in 2000.

Revenue increases in 1999 resulted primarily from the acquisitions and growth in
the  fuel  marketing  segment  of our  independent  energy  business  group  and
off-system sales by our electric utility.

Revenue and net income (loss) provided by each business group as a percentage of
our total revenue and net income were as follows:

                                 2000                1999               1998
                                 ----                ----               ----
     Revenue:
       Independent energy          89%                 83%                81%
       Electric utility            11                  17                 19
       Communications               -                   -                  -
                                 ----                ----               ----
                                  100%                100%               100%
                                 ====                ====               ====

     Net Income (Loss):
       Independent
         energy                    55%                 31%                 5%
       Electric utility            70                  74                 96
       Communications             (25)                 (5)                (1)
                                 ----                ----               ----
                                  100%                100%               100%
                                 ====                ====               ====

We believe that opportunities  exist to continue the improvement of results from
our  existing   operations  in  the  independent   energy  business  group.  The
independent  energy  group's  earnings are expected to exceed net income derived
from our regulated  utility in 2001. Our coal mining and oil and gas segments of
this  business  group have  provided,  and are  expected to continue to provide,
stable cash flow and  operating  results.  We also  believe  our fuel  marketing
operations will continue to provide strong earnings and significant revenues and
our continued expansion into the independent power generation business will have
a positive  impact on our  independent  energy business group in terms of future
growth and earnings. (See Business Outlook Statements.)

Our electric  utility has  continued  its stable growth both in terms of revenue
and  earnings  over the past two years in our retail  markets.  We believe  this
trend is stable and, absent unplanned system outages, will continue for the next
several years due to the extension of our electric  utility's  rate freeze until
January 1, 2005.  (See Rate  Regulation.)  The  degree of the  utility's  future
earnings  generated  from  wholesale  non-firm sales will depend on many factors
including  native load growth,  plant  availability  and commodity prices in the
western markets.

Although our communications  business  significantly  increased  residential and
business customers in 2000, we expect it will sustain  approximately $10 million
in net losses in 2001, with annual losses decreasing and profitability  expected
in the next three to four years.

The  following  business  group and segment  information  includes  intercompany
eliminations.

Independent Energy

                                     2000             1999            1998
                                     ----             ----            ----
                                                 (in thousands)
     Revenue:
         Fuel marketing           $1,353,795        $614,228         $506,043
         Coal                         30,530          31,095           31,413
         Gas and oil                  19,183          13,052           12,562
         Independent power            39,331               -                -
                                  ----------        --------         --------
            Total revenue          1,442,839         658,375          550,018
       Expenses                    1,381,991         644,196          536,048*
                                  ----------        --------         --------
       Operating income           $   60,848        $ 14,179         $ 13,970*
                                  ==========        ========         ========
       Net income                 $   28,946        $ 11,882         $ 10,068*
                                  ==========        ========         ========
       EBITDA**                   $   65,184        $ 25,016         $ 22,530
                                  ==========        ========         ========
- ---------------
* Excludes $13.5 million pre-tax non-cash charge relating to certain oil and gas
assets ($8.8 million net-of-tax)  **EBITDA represents the sum of earnings before
interest, taxes, depreciation and amortization.

EBITDA is included  because our management  believes that EBITDA is a meaningful
measurement  commonly  used by the  investment  community  as an  indicator of a
company's  historical  ability to service  debt,  to  sustain  potential  future
increases in debt and to satisfy capital requirements.  Our definition of EBITDA
may not be identical to similarly  titled measures  reported by other companies.
EBITDA is not intended to represent  cash flows for the period,  nor has it been
presented as an  alternative  to either  operating  income or as an indicator of
operating  performance  or cash flows from  operating,  investing  and financing
activities;  is not  intended to represent  funds  available  for debt  service,
dividends,  reinvestment,  or  other  discretionary  uses;  and  should  not  be
considered in isolation or as a substitute for measures of performance  prepared
in accordance with generally accepted accounting principles.

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

                                                          2000                         1999                        1998
                                                          ----                         ----                        ----
                                                                                                       
       Tons of coal sold                                3,050,000                    3,180,000                  3,280,000
       Barrels of oil sold                                334,000                      318,000                    344,000
       Mcf of natural gas sold                          3,274,000                    2,791,000                  2,056,000
       Mcf equivalent sales                             5,278,000                    4,698,000                  4,120,000

       Fuel marketing-average daily volumes:
             Natural gas - MMBtus                         860,800                      635,500                    524,800
             Crude oil - barrels                           44,300                       19,270                     19,000
             Coal - tons                                    4,400                        4,500                      4,400*
* Since the acquisition date

The independent  energy business group's revenues  increased 119 percent in 2000
and 20 percent in 1999. The revenue  increase in 2000 was a direct result of gas
and  electricity  shortages  in the West Coast  markets  and the  closing of the
Indeck Capital, Inc. acquisition. The revenue increase in 1999 was primarily the
result of consolidating the three fuel marketing companies'  operations from the
time of their acquisitions.  Additionally, revenues increased in both years as a
result of increased  volumes and increased  fuel and power  prices.  Natural gas
prices  increased  from an average of  $1.97-$2.15  per MMcf in 1998 and 1999 to
$4.19 per MMcf in 2000.  Daily  volumes of natural  gas  marketed  increased  35
percent  in 2000  and 21  percent  in  1999.  In July  2000,  we  completed  our
acquisition of Indeck Capital, merging it into Black Hills Energy Capital, Inc.,
which contributed to our earnings growth in 2000. In addition, in December 2000,
we sold our ownership interest in a power fund management company which resulted
in a $3.7 million pre-tax gain.

The independent  energy business  group's total  operating  expenses,  operating
income and EBITDA  increased  over 115  percent,  325 percent  and 160  percent,
respectively, in 2000. Net income of the business group increased 144 percent in
2000.  These increases  resulted  primarily from our gas marketing  operations -
which  experienced a dramatic  increase in both trading  volumes and margins,  a
significant  increase in fuel production  volumes,  record fuel and power prices
and expanded power generation.  The independent energy business group's 1999 net
income  improved over 1998 (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  operations in 1999,  partially offset by a
non-cash  write-down of certain  intangible assets relating to our wholesale gas
marketing office in Houston.

Coal Mining

Coal mining results were as follows:

                             2000                  1999                   1998
                             ----                  ----                   ----
                                              (in thousands)
        Revenue            $30,530               $31,095               $31,413
        Operating income     8,800                12,600                12,700
        Net income           7,200                 9,700                 9,750
        EBITDA              19,000                15,700                15,600

A planned  five-week outage at the Wyodak plant resulted in lower coal sales and
earnings in 2000 compared to 1999 and 1998.

Oil and Gas

Oil and gas operating results were as follows:

                            2000                   1999                  1998
                            ----                   ----                  ----
                                              (in thousands)
        Revenue           $19,183                $13,052              $ 12,562
        Operating income    7,900                  4,000                 1,200*
        Net income          5,000                  2,500                   800*
        EBITDA             11,900                  6,900                 6,400
- -------------------------------------------------------------------------------
*Excludes the impact of a $13.5 million pre-tax write-down of certain oil and
natural gas properties.

Record net income in 2000 was  primarily a result of record  natural gas prices,
higher crude oil prices, and a significant increase in production volumes.  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).  We  recognized  approximately  $3.7
million,  $2.6  million and $4.9  million of depletion  expense  (excluding  the
write-down  in 1998) related to gas and oil  production in 2000,  1999 and 1998,
respectively.

The following is a summary of our oil and gas reserves at December 31:

                                        2000          1999           1998
                                        ----          ----           ----
        Barrels of oil (in millions)    4.41          4.11           2.37
        MMcf of natural gas            18.4          19.5           16.0
        Total in MMcf equivalents      44.88         44.11          30.16

These 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 oil reserves
at  December  31,  2000 was due to  improved  product  prices.  The  increase in
reserves  at  December  31,  1999 was due to strong  drilling  results,  reserve
acquisitions and improved  product prices.  We intend to increase our net proved
reserves by selectively  increasing our oil and gas  exploration and development
activities and by acquiring producing properties.

Fuel Marketing

Our fuel marketing companies produced the following results:

                                     2000            1999           1998
                                     ----            ----           ----
                                                 (in thousands)
        Revenue                   $1,353,795       $614,228       $506,043
        Operating income (loss)       23,800         (2,200)             -
        Net income                    14,000           (200)          (300)
        EBITDA                        23,700          2,500            600

Record volumes  marketed and strong  margins  contributed to the increase in net
income from fuel  marketing in 2000 compared to 1999 and 1998.  During 1999, the
fuel 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 coal
marketing operations (acquired in September 1998),  increased product prices and
increased  oil  volumes  marketed.  Operating  income in 1999 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).

Our fuel marketing companies generate large amounts of revenue and corresponding
expense  related to buying and selling  energy  commodities.  Fuel  marketing is
extremely competitive,  and margins are typically very small. The unusual energy
market conditions stemming primarily from natural gas and electricity  shortages
in California  contributed to the strong  financial  performance in 2000 and may
not recur in the future.  However,  we believe that the continued  growth of our
fuel  and  power  production  businesses  will  create  opportunities  for us to
continue to generate strong fuel marketing operating results in future years.

Independent Power Production

Our independent power segment produced the following results:

                                    2000              1999              1998
                                    ----              ----              ----
                                                 (in thousands)
        Revenue                    $39,331          $     -          $      -
        Operating income (loss)     20,400             (160)                -
        Net income                   3,200             (100)             (100)
        EBITDA                      10,751                -              (150)

Results from the  independent  power  production  segment  were not  significant
either in 1999 or 1998.  In July 2000,  the  acquisition  of Indeck  Capital was
completed  representing  a  significant  advancement  of  our  position  in  the
independent power production  segment. We now own 250 net megawatts in currently
operating plants with a total name plate rating of approximately  870 megawatts.
Of this 250 net  megawatts,  approximately  179  megawatts  is  under  long-term
contracts   or  tolling   arrangements   with  at  least  one  year   remaining;
approximately  40 megawatts is owned through  minority  interests in independent
power investment funds,  which we do not manage; and the remainder is sold under
short-term  market  arrangements.  An  additional  470  megawatts of  generating
capacity is currently under  construction.  We expect to sell all of this output
under long-term  contracts.  We expect to increase revenues and earnings in this
segment beyond 2001 through future project development.

Electric Utility

                                                                2000                 1999                1998
                                                                ----                 ----                ----
                                                                                (in thousands)
                                                                                               
                    Revenue                                   $173,308              $133,222            $129,236
                    Operating expenses                         105,100                80,936              79,340
                                                              ---------            ----------          ---------
                    Operating income                          $ 68,208              $ 52,286            $ 49,896
                                                              ========              ========            ========
                    Net income                                $ 37,105              $ 27,286            $ 24,825
                                                              ========              ========            ========
                    EBITDA                                    $ 88,853              $ 68,299            $ 64,936
                                                              ========              ========            ========

Electric revenue increased 30.1 percent in 2000 compared to 3.1 percent in 1999.
The  increase  in  electric  revenue in 2000 was  primarily  due to a 54 percent
increase in off-system  sales at an average price that was 3.1 times higher than
the average price in 1999.  The increase in off-system  sales was driven by high
spot market prices for energy in 2000,  which enabled us to generate more energy
from our combustion  turbine  facilities,  including the Neil Simpson combustion
turbine which we placed into  commercial  operation in June 2000.  Megawatthours
generated from our oil-fired diesel and natural  gas-fired  combustion  turbines
were 305,767 in 2000,  25,882 in 1999 and 33,082 in 1998.  Historically,  market
prices were not  sufficient to support the  economics of  generating  from these
facilities  except  to meet peak  demand  and as  standby  use for  native  load
requirements.

Firm kilowatthour  sales increased 2.8 percent in 2000 compared to a decrease of
0.1 percent in 1999. Residential and commercial sales increases of 6 percent and
3 percent,  respectively,  in 2000 were partially offset by a 2 percent decrease
in industrial  sales,  primarily due to load  reductions at Homestake Gold Mine.
Degree  days,  a measure of  weather  trends,  were 16 percent  above 1999 and 1
percent above normal in 2000.  Degree days in 1999 were 9 percent below 1998 and
13 percent below normal.  The increase in electric revenue in 1999 was primarily
due to stable  firm sales  combined  with a 20 percent  increase  in  off-system
sales.

Revenue per  kilowatthour  sold was 6.4 cents  compared to 5.4 cents in 1999 and
1998.  The number of  customers  in the service  area  increased  to 58,601 from
57,709 in 1999 and from 56,856 in 1998.  The revenue  per  kilowatthour  sold in
2000  reflects a 54 percent  increase  in  wholesale  non-firm  sales to 684,378
megawatthours  and robust  wholesale power prices.  The revenue per kilowatthour
sold in 1999  reflects the 20 percent  increase in wholesale  non-firm  sales to
445,712 megawatthours. The revenue per kilowatthour sold in 1998 reflects the 33
percent increase in wholesale non-firm sales to 371,104 megawatthours.

Electric utility  operating  expenses  increased by 30 percent in 2000 primarily
due to increased fuel, purchased power, and operating and maintenance  expenses,
partially offset by lower  depreciation.  Fuel expense in 2000 included the cost
associated with the additional combustion turbine generation. 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.

Firm energy sales in our retail  service  territory  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 at a rate of 2 percent.
We currently  have a winter peak of 344 megawatts  established  in December 1998
and a summer peak of 372 megawatts  established in August 2000.  These forecasts
are from studies  conducted by us whereby our 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  have  tracked  actual sales  within a band of  reasonableness  over a
period  of  several   years.   Weather   deviations   can  affect  energy  sales
significantly when compared to forecasts based on normal weather.

Communications

                                                          2000                   1999                  1998
                                                          ----                   ----                  ----
                                                                            (in thousands)
                                                                                             
        Revenue                                         $   7,689             $    278                $      -
        Operating expenses                                 20,175                4,852                   1,087
                                                        ----------            ---------               --------
        Operating loss                                   $(12,486)             $(4,574)                $(1,087)
                                                         =========             ========                ========
        Net loss                                         $(12,027)             $(1,262)               $   (280)
                                                         =========             ========               =========
        EBITDA                                           $(13,144)             $(2,626)               $   (570)
                                                         =========             ========               =========

In  September   1998,   we  formed  our   communications   business  to  provide
facilities-based  communications  services for Rapid City and the northern Black
Hills  of  South   Dakota.   We  have   invested   more  than  $100  million  in
state-of-the-art  technology  that  offers  local  and long  distance  telephone
service, expanded cable television service, Internet access, and high-speed data
and video services.  The build-out is  approximately  70 percent complete and is
expected to be completed in 2001. Further capital  expenditures of approximately
$31.3  million are expected over the next two years to complete the build-out of
the fiber optic network and to acquire  customer  premise  equipment for sale to
customers.

We began serving customers in late 1999 and market our  communications  services
to schools,  hospitals,  cities,  economic  development groups, and business and
residential  customers.  Operating losses in 2000 were attributable to increased
interest,  depreciation  and operating  expenses.  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.
As of December 31, 2000,  we had 8,368  residential  customers  and 646 business
customers.  We have a  manageable  backlog  and  expect to more than  double the
number  of  customers  in 2001.  Our goal is to attain  50  percent  residential
penetration while serving 35 percent of all broadband  business customers within
our service territory.

                       Liquidity and Capital Resources

In 2000, we generated sufficient cash flow from operations to meet our operating
needs, to pay dividends on common stock and to pay long-term debt maturities. We
funded  property  additions  primarily  related to  construction  of  additional
electric generation facilities for our independent energy business group through
a combination of operating cash flow,  increased  short-term  debt and long-term
non-recourse  project financing.  Investing and financing  activities  increased
primarily  as a result of the  acquisition  of Indeck  Capital  in July 2000 and
construction  of several  generating  facilities.  Cash  flows  from  operations
increased $0.7 million,  primarily due to increased net income and  depreciation
partially  offset by increased  working capital.  We expect increased  operating
cash flows  resulting  from our investing  activities to support the  additional
indebtedness.

As part of our  acquisition  of Indeck  Capital,  we  assumed  $40.3  million of
additional  debt,  through an increase in  borrowings on our  short-term  credit
facilities.  In  addition,  we issued 1.537  million  shares of common stock and
4,000  shares  of  convertible  preferred  stock to the  former  Indeck  Capital
stockholders.

In 1999,  we generated  cash from  operations  sufficient  to meet our operating
needs, to pay dividends on common stock, to pay long-term debt maturities and to
provide  financing for our  investment  in  independent  power assets.  Property
additions were primarily  financed through  increased  short-term debt and notes
payable.  Cash flows from  operations  increased  $19 million  primarily  due to
increased net income and decreased  working  capital.  Cash flows from investing
activities increased  substantially,  primarily related to the deployment of our
fiber optic  communications  network and our investment in the  construction  of
generating facilities.  Cash flows from financing activities increased primarily
due to increased short-term indebtedness to fund our investing activities.

In the past, we have relied upon internally  generated funds,  issuance of short
and  long-term  debt and sales of common  stock to finance  our  activities.  We
expect an  appropriate  mix of financing  options will be used to finance future
activities.  We  expect to  finance  our  independent  energy  business  group's
purchase and  construction  of electric  generating  facilities,  primarily with
long-term,  non-recourse  project level debt.  We expect that any  project-level
debt will contain  significant  restrictions on  distributions  of cash from the
project to us.

Dividends  paid on our common stock  totaled  $1.08 per share in
2000. This reflected increases approved by our Board of Directors from $1.04 per
share in 1999 and  $1.00  per  share in 1998.  All  dividends  were  paid out of
current earnings. Our three-year annual dividend growth rate was 4.4 percent and
our  payout  ratio  for 2000 was 45  percent.  In  January  2001,  our  Board of
Directors increased the quarterly dividend 3.7 percent to 28 cents per share. If
this  dividend is  maintained  during 2001,  it will be  equivalent to $1.12 per
share, an annual increase of 4 cents per share. The  determination of the amount
of future cash  dividends,  if any, to be  declared  and paid will depend  upon,
among other things, our financial condition, funds from operations, the level of
our  capital  expenditures,  restrictions  under our credit  facilities  and our
future business prospects.

Capital Requirements

Our primary  capital  requirements  for the three years ended  December 31, 2000
were as follows:

                                                                2000                1999                1998
                                                                ----                ----                ----
                                                                               (in thousands)
                                                                                              
        Property and investment additions:
          Independent energy                                  $130,787             $73,656             $12,040
          Electric utility                                      25,257              31,911              11,451
          Communications and other                              58,922              49,042               1,774
        Common stock dividends                                  23,527              22,602              21,737
        Fuel marketing assets                                        -                   -               1,960
        Maturities/redemptions of long-term debt                 1,330               1,330               1,331
                                                              --------            --------             -------
                                                              $239,823            $178,541             $50,293
                                                              ========            ========             =======

Our capital  additions for 2000 were $215  million.  The major capital items for
the year  included  the  following:  acquisition  of the net  assets  of  Indeck
Capital;  completion of  construction  of the 80 megawatt  gas-fired  generation
units at the Arapahoe  site in Denver,  Colorado,  which we placed in service in
May 2000;  completion  of  construction  of the 40  megawatt  gas-fired  Valmont
combustion turbine unit located in Boulder, Colorado, which we placed in service
in May 2000;  acquisitions  of various  interests  in  partnerships  in which we
previously  held a  minority  interest;  completion  of  construction  of the 40
megawatt  gas-fired  Neil  Simpson  combustion  turbine unit at our Wyodak site,
which  we  placed  in  service  in  June  2000;  and  the  construction  of  our
communications fiber optic network.

Forecasted  capital   requirements  for  projected  plant  construction,   other
independent  energy  investments,  regulated  utility capital  improvements  and
completion of the communications network are as follows:

                                                               2001                2002                 2003
                                                               ----                ----                 ----
                                                                              (in thousands)
                                                                                             
        Independent energy                                    $ 287,200         $ 208,390             $ 195,540
        Electric utility                                         18,340            18,160                16,450
        Communications                                           25,390             5,920                 3,290
                                                              ---------         ---------             ---------
                                                              $ 330,930         $ 232,470             $ 215,280
                                                              =========         =========             =========

Our independent energy business group's forecasted capital  requirements include
the following:

o    Acquisition of a 240 megawatt Fountain Valley gas-fired turbine  generation
     facility  currently  under  construction,  located near  Colorado  Springs,
     Colorado.  Construction  is expected to be completed  in mid-2001,  with an
     expected cost of approximately $175 million.

o    Completion of construction of a 40 megawatt gas-fired combustion turbine at
     our Wyodak, Wyoming site (expected in mid-2001).

o    Completion of  construction of a 40 megawatt  gas-turbine  expansion at our
     Valmont, Colorado site (expected in mid-2001).

o    Completion of construction of a 50 megawatt combined-cycle expansion at our
     Arapahoe, Colorado site (expected in mid-2002).

o    Expansion of the Harbor  Power plant in  Wilmington,  California  with a 30
     megawatt   combined-cycle   upgrade.   This   expansion   is  currently  in
     development,  with anticipated completion in the second quarter of 2001. We
     have a 32 percent financial interest in Harbor Power.

o    Acquisition  of  operating  and  non-operating  interests in 74 gas and oil
     wells from Stewart  Petroleum  Corporation  of Denver,  Colorado,  which is
     expected to be completed in April 2001.

o    Expected  development of an additional 400 megawatts of generating capacity
     in years 2002-2003.

In  addition  to the above  forecasted  capital  items we will lease the Wygen I
plant, a 90 megawatt coal fired plant under construction at our Wyodak,  Wyoming
site.  The Wygen I plant will run on  low-sulfur  coal fed by conveyor  from our
adjacent  Wyodak coal mine.  The plant will burn  approximately  500,000 tons of
coal per year using the latest available environmental control technology.

The Wygen I plant  will be similar  in design to our Neil  Simpson II  facility,
which was  completed in 1995 at the same site.  We  anticipate  that the Wygen I
plant would be operational by March of 2003. Because of the leasing arrangement,
the $130 million expected total construction costs of the plant are not included
in the above three year capital expenditure forecast.

Forecasted capital  expenditures for our electric utility operations include new
transmission and substation projects, re-build projects on existing transmission
lines,  distribution  projects in response to  customer  requests  for  electric
service,  capital  projects  associated with our utility's  existing  generation
plants, and other  miscellaneous  items. We do not expect additional  generation
capacity to be added to our regulated utility over the forecast period.

Our communications  group's capital requirements  forecast primarily consists of
2001  costs  related  to the  completion  of the  initial  fiber  optic  network
build-out  in Rapid  City and the  northern  Black  Hills of South  Dakota.  The
build-out is expected to be completed by November 2001, with forecasted  capital
expenditures  thereafter consisting of capital improvements to the then existing
network infrastructure.

Lines of Credit

We have established  lines of credit with various banks totaling $290 million at
December 31, 2000 and $115 million at December 31, 1999, which were available to
support  bank  borrowings  or to provide for letters of credit.  There were $211
million of borrowings  and $20.6 million of letters of credit issued under these
lines of credit at December 31, 2000,  and $96.6  million of  borrowings  and no
letters of credit  issued at December 31, 1999. We had 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,  Enserco Energy, Inc. has a $90 million uncommitted,  discretionary
line of credit to provide support for the purchase of natural gas. We provide no
guarantee  to the lender  under this  facility.  At December  31, 2000 and 1999,
there were  outstanding  letters of credit  issued  under the  facility of $69.8
million  and $19.9  million,  respectively,  with no  borrowing  balances on the
facility.

Similarly,  Black Hills Energy  Resources,  Inc. has a $25 million  uncommitted,
discretionary  credit facility.  This line of credit provides credit support for
the  purchases  of crude oil by Black  Hills  Energy  Resources.  We  provide no
guarantee  to the lender  under this  facility.  At December  31, 2000 and 1999,
Black Hills Energy  Resources had letters of credit  outstanding of $8.5 million
and $13.2  million,  respectively,  and no balance  outstanding on its overdraft
line.

Coal Reclamation Reserves

Under our mining permit, we are required to reclaim all land where we have 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 we mine the area. Approximately
$0.7 million is charged to operations as  reclamation  expense  annually.  As of
December 31, 2000, accrued reclamation costs were approximately $17.7 million.

Long-term Debt/Credit Ratings

The long-term debt  component of our capital  structure at December 31, 2000 and
1999 was 52 percent and 43 percent,  respectively.  With expected  growth within
the  independent  energy  business group, we anticipate our long-term debt ratio
will increase to 55-60 percent in the next five years.

Our first mortgage bonds are rated A1 by Moody's Investors Service,  Inc. and A+
by Standard & Poor's  Ratings  Services.  These ratings  reflect the  respective
agencies' opinions of the credit quality of our utility's first mortgage bonds.
 .
                             Market Risk Disclosures

Price Risk Management

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

We have adopted 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. We generally attempt to
balance our fixed-price physical and financial purchase and sales commitments in
terms  of  contract  volumes,   and  the  timing  of  performance  and  delivery
obligations.  However,  we may,  at  times,  have a bias in the  market,  within
established  guidelines,  resulting from the management of our portfolio. To the
extent a net open  position  exists,  fluctuating  commodity  market  prices can
impact our  financial  position or results of  operations,  either  favorably or
unfavorably.  The net open  positions  are actively  managed,  and the impact of
changing prices on our financial condition at a point in time is not necessarily
indicative of the impact of price movements throughout the year.

Effective  January 1, 1999, we 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 our comprehensive  method of accounting for energy-related  contracts,  as
defined in that statement.

We account  for all energy  trading  activities  at fair value as of the balance
sheet date and recognize  currently the net gains or losses  resulting  from the
revaluation of these contracts to fair value in our results of operations.  As a
result, substantially all of the energy trading activities of our gas marketing,
crude oil marketing and coal  marketing  operations are accounted for under fair
value accounting methodology as prescribed in EITF 98-10.

Through our independent energy business group, we utilize financial  instruments
for our fuel marketing services.  These financial  instruments include fixed for
float swap financial instruments, basis swap financial instruments, and costless
collars traded in the over-the-counter financial markets.

The derivatives are not held for speculative  purposes but rather serve to hedge
our exposure  related to commodity  purchases or sales  commitments.  Under EITF
98-10,  these  transactions  qualify as energy trading  activities  that must be
accounted for at fair value. As such,  realized and unrealized  gains and losses
are recorded as a component of income.  Because we do not speculate  with "open"
positions,   substantially  all  of  our  trading  activities  are  back-to-back
positions  where a  commitment  to  buy/(sell)  a  commodity  is matched  with a
committed sale/(buy) or financial  instrument.  The quantities and maximum terms
of derivative  financial  instruments  held for trading purposes at December 31,
2000 and 1999 are as follows:

                                                                                                              Max. Term
December 31, 2000                                                          Volume Covered                       (Years)
- -----------------                                                          --------------                       -------
(MMBtus)
                                                                                                          
Natural gas basis swaps purchased                                             25,577,894                           2
Natural gas basis swaps sold                                                  26,059,621                           2
Natural gas fixed for float swaps purchased                                    6,476,222                           1
Natural gas fixed for float swaps sold                                         7,360,560                           1

(Tons)
Coal tons sold                                                                   988,000                           1
Coal tons purchased                                                              896,000                           1

                                                                                                               Max. Term
December 31, 1999                                                          Volume Covered                       (Years)
- -----------------                                                          --------------                       -------
(MMBtus)
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

As required  under EITF 98-10,  energy  trading  activities  were marked to fair
value on December 31, 2000, and the gains and losses recognized in earnings. The
entries for the  accompanying  consolidated  balance sheets and income statement
are as follows (in thousands):

Instrument                                                 Asset                     Liability                 Gain (loss)
- ----------                                                 -----                     ---------                 -----------
                                                                                                       
Natural gas basis swaps                                    $13,391                    $23,963                   $(10,572)

Natural gas fixed for float swaps                           24,617                     27,110                     (2,493)

Natural gas physical                                        23,391                      9,427                     13,964

Coal transactions                                            5,370                      4,460                        910

Crude oil transactions                                       1,523                      1,000                        523
                                                           -------                    -------                   --------

  Totals                                                   $68,292                    $65,960                   $  2,332
                                                           =======                    =======                   =========

There were no  significant  differences  between the fair  values of  derivative
assets and liabilities at December 31, 1999.

Non-trading Energy Activities

To reduce risk from  fluctuations  in the price of oil and natural gas, we enter
into swaps and costless collar transactions.  We use these transactions to hedge
price risk from sales of our  forecasted  crude oil and natural gas  production.
For such transactions, we utilize hedge accounting.

At December 31, 2000, we had fixed-for-float  swaps for 17,000 barrels per month
for the year  2001 to hedge  our  crude  oil  price  risk  with a fair  value of
$34,000.  We had fixed for float swaps for 10,000 barrels per month for the year
2002 to hedge our crude oil price  risk with a fair value of  $416,000.  We also
had costless  collars  (purchased  puts-sold calls) for 10,000 barrels per month
for 2001 with a fair value of $323,000.  We hedged our  forecasted  2001 natural
gas  production  with fixed for float  swaps.  We had fixed for float  swaps for
1,581,000  MMBtus  with a fair value of $(3.4)  million.  These  amounts are not
reflected in our  December  31, 2000  consolidated  balance  sheet,  but will be
recorded as part of the adoption of Statement of Financial  Accounting Standards
(SFAS) No. 133, "Accounting for Derivative  Instruments and Hedging Activities,"
on January 1, 2001.

Financing Activities

To reduce risk from  fluctuations in interest rates, we enter into interest rate
swap  transactions.  We use these  transactions  to hedge interest rate risk for
variable  rate  debt  financing.   For  such  transactions,   we  utilize  hedge
accounting.  At December  31, 2000,  we had interest  rate swaps with a notional
amount  of $127.4  million,  which  have a maximum  term of six years and a fair
value of $(7.5) million.

Credit Risk

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

Interest Rate Risk

Our exposure to market risk for changes in interest  rates relates  primarily to
our  short-term  investments  and long-term debt  obligations.  As stated in our
policy,  we are averse to principal loss and ensure the safety and  preservation
of our investments by limiting default risk, market risk and reinvestment risk.

We mitigate  default risk on short-term  investments by investing in high credit
quality securities  consisting primarily of tax-exempt federal,  state and local
agency  obligations,  by  periodically  monitoring  the  credit  rating  of  any
investment issuer or guarantor and by limiting the amount of exposure to any one
issuer.  Our 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 our results of
operations  or  financial  condition,  due to  the  short-term  duration  of the
investment portfolio.

At December 31, 2000, we had $162.2 million of outstanding floating rate debt of
which $34.8  million was not offset with interest  rate swap  transactions  that
effectively convert the debt to a fixed rate.

The table below presents  principal (or notional)  amounts and related  weighted
average  interest rates by year of maturity for our short-term  investments  and
long-term debt obligations, including current maturities (in thousands).

                                      2001        2002        2003         2004          2005        Thereafter        Total
                                      ----        ----        ----         ----          ----        ----------        -----
                                                                                                 
Cash equivalents
  Fixed rate                      $  24,913    $      -     $     -       $     -       $     -        $     -      $   24,913
  Average interest rate               6.23%           -           -             -             -              -            6.23%

Long-term debt
    Fixed rate                    $   3,070    $ 18,065     $  3,122      $  2,017      $  2,026   $    130,602     $   158,902
    Average interest rate             9.30%        6.98%        9.31%        9.50%         9.52%          8.30%           8.22%

    Variable rate                    10,890      11,919        12,968       14,380        15,560         96,433          162,150
    Average interest rate             8.20%        8.20%        8.19%        8.19%         8.19%          8.10%           8.14%

       Total long term debt          13,960      29,984        16,090       16,397        17,586        227,035          321,052
       Average interest rate          8.44%        7.46%        8.41%        8.35%         8.35%          8.22%            8.18%

                                 Rate Regulation

Existing Rate Regulation

In June 1999, the South Dakota Public Utilities Commission approved a settlement
between us and the  commission  staff,  which  extended a rate  freeze in effect
since 1995 until January 1, 2005.

The South Dakota settlement provides that, absent an extraordinary event, we may
not file for any  increase in our rates or invoke any fuel and  purchased  power
adjustment  tariff  which  would  take  effect  during the  freeze  period.  The
specified extraordinary events are:

o    new  governmental  impositions  increasing  annual  costs for South  Dakota
     customers of more than $2.0 million;

o    simultaneous  forced  outages of both our Wyodak  plant and Neil Simpson II
     plant projected to continue at least 60 days;

o    forced  outages  occurring to either  plant which  continue for a period of
     three months and are projected to last at least nine months;

o    an increase in the  Consumer  Price Index at a monthly  rate for six months
     which would result in a 10 percent or higher annual inflation rate;

o    the loss of a South  Dakota  customer  or revenue  from an  existing  South
     Dakota  customer  that would result in a loss of revenue of $2.0 million or
     more during any 12-month period;

o    the cost of coal to our 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

o    electric  deregulation  occurs  as a  result  of  either  federal  or state
     mandate,  which  allows  any of our  customers  to choose its  provider  of
     electricity at any time during the freeze period.

During the freeze period,  except as identified  above,  we are  undertaking the
risks of:

o    machinery  failure;

o    load loss caused by either an economic downturn or changes in regulation;

o    increased  costs  under  power  purchase  contracts  over  which we have no
     control;

o    government interferences; and

o    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 we 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.

Over  the last  three  years  we have  initiated  an  effort  to enter  into new
contracts with our largest industrial customers. The new contracts contain "meet
or release"  provisions  which grant us a five-year right to continue to serve a
customer at market rates in the event of deregulation. Additionally, through our
new General Service Large Optional  Combined  Account  Billing  Tariff,  we have
allowed  general service  customers to aggregate  their loads.  This tariff also
provides us with a five-year  right to continue to serve those  customers in the
event of deregulation. Our "meet or release" contracts currently total more than
116 megawatts of large commercial and industrial  load. These contracts  provide
us the  assurance  of a firm  local  market  for  our  power  resources,  should
deregulation  occur. These industrial and large commercial  customers,  together
with our wholesale  power sale  agreements with the City of Gillette and Montana
Dakota Utilities, equal approximately 48 percent of our utility's firm load.

Regulatory Accounting

We  follow  SFAS  No.  71,  "Accounting  for the  Effects  of  Certain  Types of
Regulation," and our financial  statements  reflect the effects of the different
ratemaking principles followed by the various jurisdictions  regulating us. As a
result  of our  regulatory  activity,  a 50-year  depreciable  life for the Neil
Simpson  II plant  is used  for  financial  reporting  purposes.  If we 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 our generation  operations.  In the event we determine that we no longer meet
the  criteria for  following  SFAS 71, the  accounting  impact to us would be an
extraordinary  noncash charge to operations of an amount that could be material.
Criteria that may give rise to the  discontinuance of SFAS 71 include increasing
competition  that could  restrict  our  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.  We
periodically review these criteria to ensure that the continuing  application of
SFAS 71 is appropriate.

                           Business Outlook Statements

Business Strategy

Our  strategy  is  to  build  long-term   shareholder  value  by  deploying  our
development,  operating and marketing  expertise in the  competitive  energy and
telecommunications industries. We plan to operate a mix of regulated utility and
unregulated independent energy and communications  businesses,  with emphasis on
power generation, fuel production and fuel marketing.

Future Independent Energy Activities

Our  independent  energy group is expected to exceed net income derived from our
regulated  utility beginning in 2001. The following key elements are an integral
part of our plan to achieve this objective:

o    grow our  independent  power  segment by  developing  and  acquiring  power
     projects primarily in the western United States, where demand is strong and
     expected to grow, and, in particular,  by expanding the generating capacity
     of our existing sites through a strategy known as "brownfield development;"

o    sell a large percentage of the production from our newly developed projects
     through long-term contracts in order to secure attractive returns;

o    increase  our  reserves  of  natural  gas and crude oil and expand our fuel
     production;

o    manage the risks inherent in fuel marketing by maintaining  strict position
     limits that minimize price risk exposure and by conducting  business with a
     diversified group of counterparties of high credit quality;

o    exploit our fuel cost advantages and our operating and marketing  expertise
     to remain a low-cost power producer;

o    build and maintain strong  relationships  with wholesale energy  customers;
     and

o    capitalize on our utility's established market presence,  relationships and
     customer loyalty to expand our independent energy businesses.

Future Communications Activities

Our communications operations are expected to have operating losses for the next
three to four years. The recovery of capital investment and future profitability
are  dependent  primarily  on our  ability to attract new  customers,  including
customers from incumbent providers such as Qwest Communications and Midcontinent
Communications, the incumbent telephone and cable television providers. Although
we do not  anticipate  being  regulated  in the local  markets  we are unable to
predict  future  markets,  future  government  impositions  and future  economic
conditions  that  could  affect  the  profitability  of the  communications  and
technology operations.

Recent Developments and Acquisitions

In March  2001,  we signed a  definitive  agreement  to  acquire a 240  megawatt
gas-fired turbine  generation  facility located near Colorado Springs,  Colorado
from Enron  Corporation.  The  transaction is expected to close around March 31,
2001.

The  Fountain  Valley  facility  features  six LM-6000  simple-cycle,  gas-fired
turbines,  a technology  identical to our  existing  facilities  in Colorado and
Wyoming. All necessary permitting has been approved and the plant is expected to
phase in its generation  capacity  beginning in May 2001. We also announced that
we obtained an 11-year  contract with Public  Service of Colorado to utilize the
plant for peaking  purposes.  The contract is a tolling  arrangement in which we
assume no fuel costs.  The cost of the  project is expected to be  approximately
$175  million.  We expect to finance the  project  primarily  with  non-recourse
project  level debt,  and  negotiations  are  presently  under way with  certain
lenders.

Risks and Uncertainties

In  connection  with  the  safe  harbor  provisions  of the  Private  Securities
Litigation  Reform Act of 1995 (Reform  Act),  we are 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 our
Annual Report on Form 10-K,  Annual Report,  Quarterly  Report on Form 10-Q, and
presentations,  or in response  to  questions  or  otherwise.  These  statements
concern  our plans,  expectations  and  objectives  for future  operations.  All
statements,  other than statements of historical fact, that address  activities,
events or developments  that we expect,  believe or anticipate will or may occur
in the future are forward-looking statements. The words "anticipate," "believe,"
"estimate,"  "expect,"  "intend,"  "plan,"  "predicts,"  "project," "will likely
result,"  "will  continue,"  or  similar   expressions  are  not  statements  of
historical fact and may be  forward-looking.  These  forward-looking  statements
include, among others, such things as:

o    expansion and growth of our business and operations;

o    future financial performance;

o    future acquisition and development of power plants;

o    future production of coal, oil and natural gas;

o    reserve estimates; and

o    business strategy.

Forward-looking  statements  are  based  on  assumptions  which we  believe  are
reasonable based on current expectations and projections about future events and
industry conditions and trends affecting our business.  However,  whether actual
results and  developments  will conform to our  expectations  and predictions is
subject to a number of risks and uncertainties  which could cause actual results
to differ  materially  from those contained in the  forward-looking  statements,
including the following factors:

o    prevailing  governmental  policies and regulatory actions,  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;

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 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 or capital expenditures;

o    capital market conditions;

o    credit-worthiness of counterparties;

o    technological advances;

o    competition for new energy development opportunities; and

o    legal and  administrative  proceedings  that  influence  our  business  and
     profitability.

Any forward-looking statement speaks only as to the date on which that statement
is made, and we undertake 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.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

         Report of Independent Public Accountants                          40

         Consolidated Statements of Income
           for the three years ended December 31, 2000                     41

         Consolidated Balance Sheets as of December 31, 2000 and 1999      42

         Consolidated Statements of Cash Flows
            for the three years ended December 31, 2000                    43

         Consolidated Statements of Common Stockholders' Equity
            for the three years ended December 31, 2000                    44

         Notes to Consolidated Financial Statements                     45-64

                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Shareholders of Black Hills Corporation:

We have  audited the  accompanying  consolidated  balance  sheets of Black Hills
Corporation (a South Dakota  corporation)  and  Subsidiaries  as of December 31,
2000 and  1999,  and the  related  consolidated  statements  of  income,  common
stockholders'  equity and cash  flows for each of the three  years in the period
ended December 31, 2000. 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,  2000  and  1999,  and the  results  of their
operations  and their cash flows for each of the three years in the period ended
December 31, 2000, in conformity with accounting  principles  generally accepted
in the United States.

ARTHUR ANDERSEN LLP

Minneapolis, Minnesota,
January 26, 2001

                             BLACK HILLS CORPORATION
                        CONSOLIDATED STATEMENTS OF INCOME

Years ended December 31,                                            2000               1999               1998
                                                                     (in thousands, except per share amounts)
                                                                                               
Operating revenues                                               $1,623,836          $ 791,875         $  679,254
                                                                 ----------          ---------         ----------
Operating expenses:
    Fuel and purchased power                                      1,370,841            637,302            531,518
    Operations and maintenance                                       46,054             36,463             32,701
    Administrative and general                                       44,423             18,272             15,747
    Depreciation, depletion and amortization                         32,864             25,067             24,037
    Oil and gas ceilings test write down                                  -                  -             13,546
    Taxes, other than income taxes                                   14,904             12,880             12,472
                                                                 ----------          ---------          ---------
                                                                  1,509,086            729,984            630,021
                                                                 ----------          ---------          ---------

Operating income                                                    114,750             61,891             49,233
                                                                 ----------          ---------          ---------

Other income (expense):
    Interest expense                                                (30,342)           (15,460)           (14,707)
    Interest income                                                   7,075              3,614              2,861
    Other, net                                                        2,996                876                129
                                                                 ----------         ----------          ---------
                                                                    (20,271)           (10,970)           (11,717)
                                                                 ----------         ----------          ---------

Income before minority interest and income taxes                     94,479             50,921             37,516
Minority interest                                                   (11,273)             1,935                 -
Income taxes                                                        (30,358)           (15,789)           (11,708)
                                                                 ----------         ----------          ---------

          Net income                                                 52,848             37,067             25,808
Preferred stock dividends                                               (78)                 -                 -
                                                                 ----------          ---------          ---------
Net income available for common stock                            $   52,770          $  37,067          $  25,808
                                                                 ==========          =========          =========

Earnings per share of common stock:
    Basic                                                       $      2.39          $    1.73          $    1.19
                                                                ===========          =========          =========
    Diluted                                                     $      2.37          $    1.73          $    1.19
                                                                ===========          =========          =========

Weighted average common shares outstanding:
    Basic                                                            22,118             21,445             21,623
                                                                 ==========          =========          =========
    Diluted                                                          22,281             21,482             21,665
                                                                 ==========          =========          =========

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

                             BLACK HILLS CORPORATION
                           CONSOLIDATED BALANCE SHEETS

At December 31,                                                                      2000                 1999
                                                                                     ----                 ----
                                                                                (in thousands, except share amounts)
    ASSETS
                                                                                                 
Current assets:
    Cash and cash equivalents                                                     $  24,913            $  16,482
    Securities available for sale                                                     2,113                7,586
    Receivables (net of allowance for doubtful accounts of $3,631
         and $278, respectively) -
      Customers                                                                     278,436               84,331
      Other                                                                          21,283               55,694
    Materials, supplies and fuel                                                     16,545               14,278
    Prepaid expenses                                                                  7,428                2,828
    Derivatives at market value                                                      68,292                5,158
                                                                                 ----------            ---------
                                                                                    419,010              186,357
                                                                                 ----------            ---------
Investments                                                                          63,965               10,444
                                                                                 ----------            ---------
Property and equipment                                                            1,072,129              700,044
    Less accumulated depreciation and depletion                                    (277,848)            (246,299)
                                                                                 ----------            ---------
                                                                                    794,281              453,745
                                                                                 ----------            ---------
Other assets:
    Regulatory asset                                                                  4,134                3,944
    Other, principally goodwill                                                      38,930               14,002
                                                                                 ----------             --------
                                                                                     43,064               17,946
                                                                                 ----------             --------
                                                                                 $1,320,320             $668,492
                                                                                 ==========             ========
                    LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:
    Current maturities of long-term debt                                        $    13,960           $    1,330
    Notes payable                                                                   211,679               97,579
    Accounts payable                                                                247,596               80,355
    Accrued liabilities                                                              49,661               26,088
    Derivatives at market value                                                      65,960                5,158
                                                                                -----------           ----------
                                                                                    588,856              210,510
                                                                                -----------           ----------
Long-term debt, net of current maturities                                           307,092              160,700
                                                                                -----------           ----------
Deferred credits and other liabilities:
      Investment tax credits                                                          2,530                3,022
    Federal income taxes                                                             62,679               47,668
    Reclamation and regulatory liability                                             22,340               22,494
    Other                                                                            16,516                7,492
                                                                                -----------           ----------
                                                                                    104,065               80,676
                                                                                -----------           ----------
Minority interest in subsidiaries                                                    37,961                    -
                                                                                -----------           ----------

Commitments and contingencies (Notes 10, 11 and 14)

Stockholders' equity:
   Preferred stock - no par Series 2000-A; 21,500 shares authorized; Issued
    and outstanding: 4,000 shares in 2000, -0- shares in 1999                         4,000                    -
                                                                                -----------           ----------
   Common stock equity
    Common stock $1 par value; 100,000,000 shares authorized;
      Issued: 23,302,111 shares in 2000 and 21,739,030 shares in 1999                23,302               21,739
    Additional paid-in capital                                                       73,442               40,658
    Retained earnings                                                               191,482              162,239
    Treasury stock                                                                   (9,067)              (8,030)
    Accumulated other comprehensive income (loss)                                      (813)                   -
                                                                                -----------            ---------
                                                                                    278,346              216,606
                                                                                -----------            ---------
    Total stockholders' equity                                                      282,346              216,606
                                                                                -----------            ---------
                                                                                 $1,320,320            $ 668,492
                                                                                ===========            =========

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

                             BLACK HILLS CORPORATION
                      CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31,                                                 2000              1999             1998
                                                                         ----              ----             ----
                                                                                      (in thousands)
                                                                                                   
Operating activities:
    Net income available for common                                     $52,770           $37,067           $25,808
    Principal non-cash items-
        Depreciation, depletion and amortization                         32,864            25,067            24,037
        Oil and gas ceilings test write-down                                  -                 -            13,546
        Derivative fair value adjustment                                 (2,332)                -                 -
        Gain on sales of assets                                          (3,736)           (2,541)                -
        Deferred income taxes and investment tax credits                  1,937             2,291            (2,535)
        Minority interest                                                11,273            (1,935)                -
     Change in operating assets and liabilities-
        Accounts receivable                                            (201,309)            2,232           (46,821)
        Materials, supplies, fuel and other current assets               (3,513)           (4,003)           (2,954)
        Accounts payable                                                165,394             6,268            41,465
        Accrued liabilities                                              18,678             4,013             2,244
        Other, net                                                        2,444             5,284               (60)
                                                                     -----------       ----------        ----------
                                                                         74,470            73,743            54,730
                                                                     -----------       ----------        ----------

Investing activities:
    Property additions                                                 (134,855)         (102,290)          (25,265)
     Increase in investments                                            (13,646)          (52,319)           (1,960)
    Payment for acquisition of net assets, net of cash acquired         (28,688)                -                 -
     Proceeds from sales of assets                                        5,500             3,463                 -
    Available for sale securities purchased                                   -            (7,870)          (22,361)
    Available for sale securities sold                                    4,660            22,959            13,655
                                                                     ----------        ----------         ---------
                                                                       (167,029)         (136,057)          (35,931)
                                                                     ----------        ----------         ---------

Financing activities:
    Dividends paid                                                      (23,527)          (22,602)          (21,737)
    Treasury stock purchased                                             (1,037)           (4,949)           (3,081)
    Common stock issued                                                   3,854               424               273
    Increase in short-term borrowings                                    73,848            92,489             5,067
     Long-term debt - issuance                                           60,082                 -                 -
    Long-term debt - repayments                                          (1,330)           (1,330)           (1,331)
     Subsidiary distributions to minority interests                     (10,900)                -                 -
                                                                       --------         ---------         ---------
                                                                        100,990            64,032           (20,809)
                                                                       --------         ---------         ---------

      Increase (decrease) in cash and cash equivalents                    8,431             1,718            (2,010)

Cash and cash equivalents:
    Beginning of year                                                    16,482            14,764            16,774
                                                                       --------          --------          --------
    End of year                                                        $ 24,913          $ 16,482          $ 14,764
                                                                       ========          ========          ========

Supplemental disclosure of cash flow information:

    Cash paid during the period for-
      Interest                                                          $31,309           $18,819           $14,742
      Income taxes                                                      $18,518           $13,173           $13,135

Non-cash net assets acquired through issuance of common
and preferred stock (Note 14)                                           $34,493           $     -           $     -

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

                             BLACK HILLS CORPORATION
             CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

                                                                                                       Accumulated
                                  Common Stock        Additional                   Treasury Stock          Other
                              ----------------------   Paid-In     Retained     ---------------------   Comprehensive
                               Shares      Amount      Capital     Earnings     Shares     Amount       Income (loss)      Total
                              ---------   ---------- ----------    ----------   --------- -----------   -------------     --------
                                                                               (in thousands)
                                                                                                  
Balance at
December 31, 1997               21,705    $  21,705  $   39,995    $  143,703           - $        -    $           -     $205,403
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------
Comprehensive Income:
   Net income                        -            -           -        25,808           -          -                -       25,808
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------
                                     -            -           -        25,808           -          -                -       25,808

Dividends on common stock            -           -           -         (21,737)        -          -                 -      (21,737)
Issuance of common stock            14          14         259               -         -          -                 -          273
Treasury stock acquired, net         -           -           -               -      (141)    (3,081)                -       (3,081)
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------

Balance at
December 31, 1998               21,719       21,719      40,254       147,774       (141)    (3,081)                -     $206,666
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------
Comprehensive Income:
   Net income                        -            -           -             -      37,067          -                -       37,067
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------
                                     -            -           -             -      37,067          -                -       37,067
Dividends on common stock            -            -           -       (22,602)          -          -                -      (22,602)
Issuance of common stock            20           20         404             -           -          -                -          424
Treasury stock acquired, net         -            -           -             -        (227)    (4,949)               -       (4,949)
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------

Balance at
December 31, 1999               21,739       21,739      40,658       162,239        (368)    (8,030)               -     $216,606
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------
Comprehensive Income:
   Net income                        -            -           -        52,848           -          -                -       52,848
   Unrealized loss on available
   for sale securities               -            -           -             -           -          -             (813)        (813)
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------
                                     -            -           -        52,848           -          -             (813)      52,848

Dividends on preferred stock         -            -           -           (78)          -          -                -          (78)
Dividends on common stock            -            -           -       (23,527)          -          -                -      (23,527)
Issuance of common stock            26           26         544             -           -          -                -          570
Issuance of common stock
  for acquisition                1,537        1,537      32,240             -           -          -                -       33,777
Treasury stock acquired, net         -            -           -             -         (13)    (1,037)               -       (1,037)
                              --------    ---------  ----------    ----------   --------- ----------    -------------     --------
Balance at
December 31, 2000               23,302    $  23,302  $   73,442    $  191,482        (381)   $(9,067)   $        (813)    $278,346
                              ========    =========  ==========    ==========   =========  =========    =============     ========

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

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                        December 31, 2000, 1999 and 1998

 (1)  BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Corporation and its subsidiaries  operate in three primary operating
groups:   non-regulated  independent  energy,  regulated  electric  utility  and
communications.  The 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, Enserco Energy,
Black  Hills  Energy  Resources  and Black  Hills Coal  Network  related to fuel
marketing  of natural gas,  oil and coal,  respectively,  and Black Hills Energy
Capital and its subsidiaries  and Black Hills Generation  related to independent
power activities,  all consolidated for reporting purposes as Black Hills Energy
Ventures;   operates  its  public  utility  electric   operations   through  its
subsidiary,  Black Hills Power, Inc.; and operates its communications operations
through  its  indirect  subsidiaries  Black  Hills  Fiber  Systems,  Black Hills
FiberCom  and  Daksoft.  For  further  descriptions  of the  Company's  business
segments see Note 13.

In December 2000, the Company  effected a holding  company  structure  under the
renamed holding company Black Hills Corporation.

Principles of Consolidation

The  consolidated  financial  statements  include  the  accounts  of Black Hills
Corporation and its wholly-owned and majority-owned subsidiaries. Generally, the
Company uses equity  accounting for  investments of which it owns between 20 and
50 percent  and  investments  in  partnerships  under 20 percent if the  Company
exercises significant influence.

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 $9.7 million,
$7.7 million and $10.3 million in 2000, 1999 and 1998, respectively.

The Company owns 51 percent of the voting  securities  of Black Hills  FiberCom,
LLC  (FiberCom).  During 2000 FiberCom's  operating  losses reduced its members'
equity below zero.  At that point the Company  began to recognize 100 percent of
FiberCom's  operating  losses  and will  continue  to do so until  such  time as
additional  equity  investments  are made by third  parties or future net income
restores members' equity to a positive amount.

As noted in Note 14, Black Hills Energy Capital made several acquisitions during
2000. The Company's consolidated statements of income include operating activity
of these companies beginning with their acquisition date.

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

Minority Interest in Subsidiaries

Minority  interest  in  results  of  operations  of  consolidated   subsidiaries
represents  the  minority  shareholders'  share of the income or loss of various
consolidated  subsidiaries.  The minority  interest in the consolidated  balance
sheets reflect the amount of the  underlying net assets of various  consolidated
subsidiaries attributable to the minority shareholders.

Regulatory Accounting

Black  Hills  Power is  subject  to  regulation  by  various  state and  federal
agencies.  The accounting policies followed are generally subject to the Uniform
System of Accounts of the Federal Energy  Regulatory  Commission  (FERC).  These
accounting  policies  differ in some  respects  from those used by the Company's
non-regulated businesses.

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 Neil
Simpson II 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 $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  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.

Cash Equivalents

The Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents.

Available for Sale Securities

The Company has  investments  in marketable  securities  that are  classified as
available-for-sale  securities and are carried at fair value in accordance  with
the provisions of SFAS No. 115 "Accounting  for Certain  Investments in Debt and
Equity  Securities."  The unrealized  gain or loss resulting from the difference
between the securities'  fair value and cost basis is included as a component of
accumulated other comprehensive income in common stockholders' equity.

Inventory

Materials,  supplies  and fuel are  stated  at the  lower of cost or market on a
first-in, first-out basis.

Property, Plant and Equipment

The components of property, plant and equipment are as follows, at December 31:

                                          2000                     1999
                                          ----                     ----
                                                 (in thousands)

        Independent energy            $  430,979                 $125,371
        Electric utility                 530,529                  523,461
        Communications                   110,486                   50,621
        Other                                135                      591
                                      ----------                 --------
                                      $1,072,129                 $700,044
                                      ==========                 ========

Additions to property,  plant and  equipment are recorded at cost when placed in
service. Included in the cost of regulated construction projects is an allowance
for funds used during  construction  (AFUDC) which  represents  the  approximate
composite  cost of  borrowed  funds and a return on capital  used to finance the
project. The AFUDC was computed at an annual composite rate of 9.7, 8.3 and 10.1
percent  during 2000,  1999 and 1998,  respectively.  In  addition,  the Company
capitalizes interest,  when applicable,  on certain  non-regulated  construction
projects.  The amount of AFUDC and interest  capitalized was $2.0 million,  $1.2
million  and $0.2  million  in 2000,  1999 and 1998,  respectively.  The cost of
regulated electric property,  plant and equipment retired, or otherwise disposed
of in the ordinary course of business,  together with removal cost less salvage,
is charged to  accumulated  depreciation.  Retirement  or  disposal of all other
assets, except for oil and gas properties as described below, result in gains or
losses recognized as a component of income.  Repairs and maintenance of property
are charged to operations as incurred.

Depreciation provisions for regulated electric property,  plant and equipment is
computed on a straight-line  basis using an annual composite rate of 2.8 percent
in 2000,  3.1 percent in 1999 and 3.0 percent in 1998.  Non-regulated  property,
plant and equipment is  depreciated  on a  straight-line  basis using  estimated
useful  lives  ranging  from 3 to 39  years.  Depletion  of  coal,  oil  and gas
properties is computed using the cost method.

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, 2000 and 1999, no  significant  write-downs  were
required.

Goodwill and Intangible Assets

Goodwill  represents the excess of acquisition  costs over the fair market value
of  the  net  assets  of  acquired  businesses  and  is  being  amortized  on  a
straight-line basis over the estimated useful lives of such assets,  which range
from 8 to 25 years.  The cost of other  acquired  intangibles  is amortized on a
straight-line basis over their estimated useful lives.  Amortization expense was
$3.1  million,   $2.7  million  and  $0.7  million  in  2000,   1999  and  1998,
respectively.  Accumulated  amortization was $6.7 million, $3.6 million and $0.9
million at December 31, 2000, 1999 and 1998, respectively.

Income Taxes

The Company uses 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 basis of assets and  liabilities.  Such temporary  differences
are the result of provisions in the income tax law that either require or permit
certain items to be reported on the income tax return in a different period than
they are reported in the financial  statements.  To the extent such income taxes
are  recoverable  or  payable  through  future  rates,   regulatory  assets  and
liabilities have been recorded in the accompanying consolidated balance sheets.

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

Revenue Recognition

Generally,  revenue  is  recognized  at  the  time  products  and  services  are
delivered.  Fuel  marketing  businesses  also use the  mark-to-market  method of
accounting. Under that method all energy trading activities are recorded at fair
value as of the balance  sheet date and net gains or losses  resulting  from the
revaluation  of these  contracts to fair value are  recognized  currently in the
results of  operations.  In the  fourth  quarter of 2000,  the  Company  adopted
Securities and Exchange  Commission Staff Accounting  Bulletin No. 101, "Revenue
Recognition" (SAB 101), which provides guidance on the recognition, presentation
and disclosure of revenue in financial  statements.  The adoption of SAB 101 did
not have a material impact on the financial statements.

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. Any conveyances of properties,  including gains or
losses on abandonments of properties,  are treated as adjustments to the cost of
the properties with no gain or loss recognized.  Under the full cost method, net
capitalized costs may not exceed the present value of proved reserves.

Earnings Per Share of Common Stock

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 and conversion of preferred shares.

Use of Estimates

The preparation of financial  statements in conformity  with generally  accepted
accounting principles in the United States 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.

Reclassifications

Certain 1999 and 1998 amounts in the financial statements have been reclassified
to conform to the 2000 presentation.  These  reclassifications  had no effect on
the  Company's  common  stockholders'  investment or results of  operations,  as
previously reported.

Accounting Pronouncements

In June 1998, the Financial  Accounting  Standards  Board (FASB) issued SFAS No.
133 (SFAS 133),  "Accounting for Derivative Instruments and Hedging Activities."
SFAS 133, as amended,  establishes  accounting and reporting standards requiring
that every  derivative  instrument be recorded in the balance sheet as either an
asset or  liability  measured at its fair value.  The  Statement  requires  that
changes in the  derivative  instrument's  fair value be recognized  currently in
earnings unless specific hedge accounting criteria are met.

SFAS 133 allows  special hedge  accounting  for fair value and cash flow hedges.
The  Statement  provides  that  the  gain  or loss  on a  derivative  instrument
designated  and  qualifying  as a fair value  hedging  instrument as well as the
offsetting  loss or gain on the hedged item  attributable  to the hedged risk be
recognized  currently  in  earnings  in the  same  accounting  period.  SFAS 133
provides  that  the  effective  portion  of the  gain or  loss  on a  derivative
instrument  designated  and  qualifying  as a cash flow  hedging  instrument  be
reported as a component of other  comprehensive  income and be reclassified into
earnings  in the same  period or  periods  during  which the  hedged  forecasted
transaction  affects  earnings.  The  remaining  gain or loss on the  derivative
instrument, if any, must be recognized currently in earnings.

SFAS 133 requires that on date of initial  adoption,  an entity shall  recognize
all freestanding derivative instruments in the balance sheet as either assets or
liabilities  and  measure  them  at  fair  value.   The  difference   between  a
derivative's  previous carrying amount and its fair value shall be reported as a
transition  adjustment.  The transition  adjustment resulting from adopting this
Statement  shall be reported  in net income or other  comprehensive  income,  as
appropriate,  as the effect of a change in  accounting  principle in  accordance
with  paragraph  20  of  Accounting  Principles  Board  Opinion  No.  20  (APB),
"Accounting Changes."

Upon  adoption of SFAS 133,  most of the  Company's  energy  trading  activities
previously  accounted  for under  Emerging  Issues Task Force  Issue No.  98-10,
"Accounting for Energy Trading and Risk Management Activities" (EITF 98-10) will
fall under the purview of SFAS 133. The effect from this  adoption on the energy
trading  companies and energy trading  activities will not be material  because,
unless otherwise  noted,  the trading  companies will not designate their energy
trading activities as hedge instruments. This "no hedge" designation will result
in  these  derivatives  being  measured  at fair  value  and  gains  and  losses
recognized  currently  in  earnings.  This  treatment  under  SFAS  133  will be
comparable to the accounting under EITF 98-10.

At December  31,  2000,  the Company had certain  non-trading  energy  contracts
documented as cash flow hedges. These contracts are defined as derivatives under
SFAS  133 and  meet  the  requirements  for  cash  flow  hedges.  Because  these
non-trading  energy  contracts were documented as hedges prior to adoption,  the
transition  adjustment  will be  reported  in  accumulated  other  comprehensive
income. The aggregated entry for the derivatives  identified as energy cash flow
hedges will increase derivative assets by $1.4 million,  increase the derivative
liabilities by $4.0 million and decrease  accumulated other comprehensive income
by $2.6 million.

At December 31, 2000,  the Company had interest  rate swaps  documented  as cash
flow hedges.  These contracts are defined as derivatives under SFAS 133 and meet
the requirements  for cash flow hedges.  Because these contracts were documented
as hedges  prior to  adoption,  the  transition  adjustment  will be reported in
accumulated other comprehensive income. The interest rate swap transactions have
a notional  amount of $127.4 million and the associated  transition  adjustments
will increase  derivative  liabilities by $7.5 million and decrease  accumulated
other comprehensive income by $7.5 million.

(2)  PRICE RISK MANAGEMENT

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.

Effective  January 1, 1999,  the Company  adopted the  provisions of 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 Company  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 energy trading activities of
the Company's gas marketing,  crude oil marketing, and coal marketing operations
are accounted for under fair value accounting  methodology as prescribed in EITF
98-10.

The Company,  through its independent energy business group,  utilizes financial
instruments for its fuel marketing services. These financial instruments include
fixed for float swap financial instruments, basis swap financial instruments and
costless collars traded in the over-the-counter financial markets.

These  derivatives  are not held for  speculative  purposes  but rather serve to
hedge  the  Company's   exposure   related  to  commodity   purchases  or  sales
commitments.  Under EITF 98-10,  these  transactions  qualify as energy  trading
activities  that must be  accounted  for at fair value.  As such,  realized  and
unrealized  gains and losses are recorded as a component of income.  Because the
Company  does  not  as  a  policy  permit  speculation  with  "open"  positions,
substantially all of its trading  activities are back-to-back  positions where a
commitment to  buy/(sell) a commodity is matched with a committed  sale/(buy) or
financial  instrument.  The quantities and maximum terms of derivative financial
instruments  held for  trading  purposes  at  December  31, 2000 and 1999 are as
follows:

                                                                                                                Max. Term
December 31, 2000                                                            Volume Covered                      (Years)
- -----------------                                                            --------------                      -------
(MMBtus)

Natural gas basis swaps purchased                                               25,577,894                          2
Natural gas basis swaps sold                                                    26,059,621                          2
Natural gas fixed for float swaps purchased                                      6,476,222                          1
Natural gas fixed for float swaps sold                                           7,360,560                          1

(Tons)
Coal tons sold                                                                     988,000                          1
Coal tons purchased                                                                896,000                          1

                                                                                                                Max. Term
December 31, 1999                                                            Volume Covered                      (Years)
- -----------------                                                            --------------                      -------
(MMBtus)
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

As required  under EITF 98-10,  energy  trading  activities  were marked to fair
value on December 31, 2000, and the gains and losses recognized in earnings. The
entries for the accompanying consolidated balance sheet and income statement are
as follows (in thousands):

Instrument                                               Asset                    Liability                     Gain (loss)
- ----------                                               -----                    ---------                     ----------
                                                                                                       
Natural gas basis swaps                                  $13,391                    $23,963                       $(10,572)

Natural gas fixed-for-float swaps                         24,617                     27,110                         (2,493)

Natural gas physical                                      23,391                      9,427                         13,964

Coal transactions                                          5,370                      4,460                            910

Crude oil transactions                                     1,523                      1,000                            523
                                                         -------                    -------                      ---------

  Totals                                                 $68,292                    $65,960                      $   2,332
                                                         =======                    =======                      =========

There were no  significant  differences  between the fair  values of  derivative
assets and liabilities at December 31, 1999.

Non-trading Energy Activities

To  reduce  risk from  fluctuations  in the price of oil and  natural  gas,  the
Company enters into swaps and costless collar transactions. The transactions are
used to hedge price risk from sales of the  Company's  forecasted  crude oil and
natural  gas  production.  For such  transactions,  the Company  utilizes  hedge
accounting.

At December 31, 2000, the Company had  fixed-for-float  swaps for 17,000 barrels
per month for the year 2001 to hedge its crude oil price  risk with a fair value
that approximates cost. The Company had fixed-for-float swaps for 10,000 barrels
per month for the year 2002 to hedge its crude oil price  risk with a fair value
of $0.4  million.  The Company also had costless  collars  (purchased  puts sold
calls) for 10,000  barrels per month for 2001 with a fair value of $0.3 million.
The  Company   hedged  its   forecasted   2001  natural  gas   production   with
fixed-for-float  swaps.  The Company  had  fixed-for-float  swaps for  1,581,000
MMBtus with a fair value of $(3.4)  million.  These amounts are not reflected in
the Company's December 31, 2000 consolidated balance sheet, but will be recorded
as part of the adoption of SFAS 133 on January 1, 2001.

Financing Activities

To reduce risk from  fluctuations  in interest  rates,  the Company  enters into
interest rate swap  transactions.  These transactions are used to hedge interest
rate risk for variable rate debt financing.  For such transactions,  the Company
utilizes hedge  accounting.  At December 31, 2000, the Company had interest rate
swaps with a notional  amount of $127.4  million,  having a maximum  term of six
years and a fair value of $(7.5) million.

At  December  31,  2000,  the  Company  had  $162.2   million  of   outstanding,
floating-rate debt of which $34.8 million was not offset with interest rate swap
transactions that effectively convert the debt to a fixed rate.

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.

(3)  INVESTMENTS IN ASSOCIATED COMPANIES

Included in  Investments  on the  Consolidated  Balance Sheets are the following
investments that have been recorded on the equity method of accounting:

o    A 33.33 percent  interest in  Millennium  Pipeline  Company,  L.P., a Texas
     limited  partnership  which owns and  operates an oil  pipeline in the Gulf
     Coast region of Texas.  The Company has a carrying amount in the investment
     of $6.9  million  and $4.8  million  as of  December  31,  2000  and  1999,
     respectively.  The  partnership  had  assets  of $22.0  million  and  $15.7
     million,  liabilities  of $1.0  million  and $1.6  million,  and net income
     (loss) of $2.8  million  and $(0.2)  million as of, and for the years ended
     December 31, 2000 and 1999, respectively.

o    As part of the Indeck Capital, Inc.  acquisition,  the Company acquired a 5
     percent,  6 percent and 5 percent  interest in Energy Investors Fund, L.P.,
     Energy  Investors  Fund II,  L.P.,  and  Project  Finance  Fund III,  L.P.,
     respectively,   which  in  turn  have  investments  in  numerous   electric
     generating facilities in the United States and elsewhere. The Company has a
     carrying  amount in the investment of $8.4 million at December 31, 2000. As
     of,  and for the year  ended  December  31,  2000,  the funds had assets of
     $186.8  million,  liabilities  of $16.0  million  and net  income  of $27.1
     million.

o    As part of the  Indeck  Capital  acquisition,  the  Company  acquired  a 50
     percent interest in two natural gas-fired  cogeneration  facilities located
     in Rupert and Glenns  Ferry,  Idaho.  At December  31,  2000 the  Company's
     carrying  amount in the  investment  is $4.1 million  which  includes  $0.5
     million that  represents the cost of the  investment  over the value of the
     underlying net assets of the projects.  This excess is being amortized over
     19 years.  As of, and for the year ended December 31, 2000,  these projects
     had assets of $26.0 million, liabilities of $18.7 million and net income of
     $0.9 million.

o    As part  of the  Indeck  Capital  acquisition,  the  Company  directly  and
     indirectly  acquired   approximately  32  percent  of  Harbor  Cogeneration
     Company,  which in turn owns an 80 megawatt  cogeneration  facility located
     near the City of Long Beach in Los Angeles County,  California. At December
     31, 2000 the Company's  carrying amount in the investment is $42.2 million,
     which  includes  $13.7 million that  represents  the cost of the investment
     over the value of the underlying net assets of Harbor. This excess is being
     amortized  over 15 years.  As of, and for the year ended December 31, 2000,
     Harbor had assets of $41.7  million,  liabilities  of $0.8  million and net
     income of $28.8 million.

(4)  COMMON STOCK

Stock Option and Employee Stock Purchase Plans

The Company has a stock option plan (Stock  Option  Plan),  which allows for the
granting of stock options with exercise prices equal to the stock's market value
on the date of grant,  and an employee  stock  purchase  plan (ESPP  Plan).  The
Company  accounts  for  such  plans  under  APB  No.  25,  and has  adopted  the
disclosure-only  provisions  of  SFAS  No.  123,  "Accounting  for  Stock  Based
Compensation"  (SFAS  No.  123).  Accordingly,  no  compensation  cost  has been
recognized.

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 934,450 shares through
December 31, 2000. The option exercise price equals the fair market value of the
stock on the day of the grant.  The options  granted  vest  one-third a year for
three years and all expire after ten years from the grant date.

A summary of the status of the stock option plans at December 31, 2000, 1999 and
1998, and changes during the years then ended are as follows:

                                                       2000                          1999                          1998
                                           ----------------------------- ----------------------------- -----------------------------
                                                           Weighted                      Weighted                       Weighted
                                                            Average                       Average                        Average
                                                           Exercise                      Exercise                       Exercise
                                             Shares          Price         Shares          Price          Shares          Price
                                             ------          -----         ------          -----          ------          -----
                                                                                                        
Balance at beginning of year                  431,450       $21.35          292,700        $20.29          182,700        $18.69
Granted                                       492,500        25.22          140,250         23.58          113,000         22.79
Forfeited                                      (4,000)       23.25           (1,500)        23.06                -
Exercised                                      (5,033)       21.33                -                         (3,000)        16.67
                                            ----------                   ----------                     ----------
Balance at end of year                        914,917        23.43          431,450         21.35          292,700         20.29
                                            ==========                   ==========                     ==========
Exercisable at end of year                    292,891        20.43          182,400         19.19           84,800         18.06
                                            ==========                   ==========                     ==========

Exercise prices on options  outstanding at December 31, 2000,  range from $16.67
to $37.69 with a weighted  average  remaining  contractual life of approximately
8.5 years.

The fair  value of each  option  is  estimated  on the date of grant  using  the
Black-Scholes  option  pricing  model.  The  weighted  average fair value of the
options granted and the  assumptions  used to estimate the fair value of options
are as follows:

                                                               2000                       1999                       1998
                                                               ----                       ----                       ----
                                                                                                            
Fair value of options at grant date                           $3.88                       $4.16                      $0.69
Weighted average risk-free interest rate                       6.30%                       6.68%                      4.70%
Weighted average expected price volatility                    20.60%                      19.85%                     16.74%
Weighted average expected dividend yield                       4.20%                       4.50%                      4.20%
Expected life in years                                          10                         10                         10

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 pro forma amounts for the years ended December 31:

                                                              2000                     1999                     1998
                                                              ----                     ----                     ----
                                                                        (in thousands, except per share amounts)
                                                                                                       
Net income available for common:
   As reported                                               $52,770                  $37,067                 $25,808
   Pro forma                                                 $52,432                  $36,877                 $25,717

Earnings per share (basic and diluted):
   As reported - basic                                       $  2.39                   $1.73                   $1.19
               - diluted                                     $  2.37                   $1.73                   $1.19
   Pro forma - basic                                         $  2.38                   $1.72                   $1.19
             - diluted                                       $  2.35                   $1.72                   $1.19

The Company  issued  21,394,  19,565 and 12,824 shares of common stock under the
ESPP Plan in 2000, 1999 and 1998,  respectively.  At December 31, 2000,  226,176
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 2000 was $21.66.

Dividend Reinvestment and Stock Purchase Plan

The  Company has a Dividend  Reinvestment  and Stock  Purchase  Plan under which
shareholders  may purchase  additional  shares of common stock through  dividend
reinvestment  and/or optional cash payments at 100 percent of the recent average
market price. The Company has the option of issuing new shares or purchasing the
shares on the open market.  The Company  purchased  shares on the open market in
2000, 1999 and 1998. At December 31, 2000,  1,290,797  shares of unissued common
stock were available for future offerings under the Plan.

(5)   PREFERRED STOCK

The Company has 25,000,000 authorized shares of no-par preferred stock.

During 2000,  the Company  issued 4,000  preferred  shares in the Indeck Capital
acquisition.  The preferred  shares issued are  non-voting,  cumulative,  no par
shares with a dividend rate equal to 1 percent per annum per share,  computed on
the basis of $1,000  per share  plus an amount  equal to any  dividend  declared
payable with respect to the common stock,  multiplied by the number of shares of
common stock into which each share of preferred stock is convertible. The record
and payment  dates are the same as the record and payment  dates with respect to
the payment of  dividends on common  stock.  No dividend may be declared or paid
with  respect to common  stock  unless such a dividend is declared and paid with
respect to the  preferred  stock.  The  preferred  stock is senior to the common
stock in liquidation events.

The  Company  may redeem the  preferred  stock in whole or in part,  at any time
solely at its option.  The  redemption  price per share for the preferred  stock
shall be $1,000 per share plus all accrued and unpaid  dividends.  Each share of
the preferred stock is convertible at the option of the holder into common stock
at any time prior to July 7, 2005 and automatically  converted into common stock
on July 7, 2005. Each share of preferred stock is convertible  into 28.57 common
shares.  If the Company  delivers a notice of redemption,  the conversion  price
shall be  adjusted  to equal the  lesser  of (i) the  conversion  price  then in
effect, and (ii) the current market price on the redemption notice date.

(6)   LONG-TERM DEBT

Long-term debt outstanding at December 31 is as follows (in thousands):

                                                                                     2000                      1999
                                                                                     ----                      ----
                                                                                                       
First mortgage bonds:
     6.50% due 2002                                                                $  15,000                 $ 15,000
     9.00% due 2003                                                                    3,215                    4,255
     8.06% due 2010                                                                   30,000                   30,000
     9.49% due 2018                                                                    5,130                    5,420
     9.35% due 2021                                                                   35,000                   35,000
     8.30% due 2024                                                                   45,000                   45,000
                                                                                   ---------                 --------
                                                                                     133,345                  134,675
                                                                                   ---------                 --------

Other long-term debt:
     Pollution control revenue bonds at 6.7% due 2010                                 12,300                   12,300
     Pollution control revenue bonds at 7.5% due 2024                                 12,200                   12,200
     Other                                                                             3,911                    2,855
                                                                                   ---------                 --------
                                                                                      28,411                   27,355
                                                                                   ---------                 --------

Project financing debt:
     Floating-rate term loans at a weighted average rate of 8.05%
       at December 31, 2000 due 2009 through 2010 (a)                                159,296                        -
                                                                                   ---------                 --------
Total long-term debt                                                                 321,052                  162,030
Less current maturities                                                              (13,960)                  (1,330)
                                                                                    --------                 --------
Net long-term debt                                                                  $307,092                 $160,700
                                                                                    ========                 ========

- ---------------
(a)     Approximately  80 percent of the  December  31,  2000  balance  has been
        hedged with an interest  rate swap  moving the  floating  rates to fixed
        rates with a weighted  average  interest  rate of 7.69 percent (see Note
        2-Price Risk Management).

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.

Project financing debt is non-recourse debt collateralized by a mortgage on each
respective project's land and facilities, leases and rights, including rights to
receive payments under long-term purchase power contracts.

Certain debt instruments of the Company and its subsidiaries contain restrictive
covenants,  all of which the Company and its subsidiaries are in compliance with
at December 31, 2000.  Scheduled  maturities  for the next five years are: $14.0
million in 2001,  $30.0 million in 2002, $16.0 million in 2003, $16.4 million in
2004, and $17.6 million in 2005.

(7)     NOTES PAYABLE

The Company had committed  lines of credit with various banks of $290.0  million
at  December  31,  2000 and $115.0  million at  December  31,  1999,  which were
available to support bank borrowings or to provide for letters of credit.  There
were $211.0  million of borrowings and $20.6 million of letters of credit issued
under these lines of credit at December 31, 2000,  and there were $96.6  million
of borrowings  and no letters of credit issued at December 31, 1999. 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,  Enserco  Energy,  Inc.  has a $90.0
million  uncommitted,  discretionary  line of credit to provide  support for the
purchases of natural gas. The Company and its subsidiaries  provide no guarantee
to the lender. At December 31, 2000 and 1999, there were outstanding  letters of
credit   issued  under  the  facility  of  $69.8   million  and  $19.9   million
respectively, with no borrowing balances on the facility.

In addition to the above lines of credit, Black Hills Energy Resources, Inc. has
a $25.0 million uncommitted,  discretionary  credit facility.  The transactional
line of credit  provides  credit support for the purchases of crude oil of Black
Hills Energy Resources. The Company and its subsidiaries provide no guarantee to
the lender.  At December 31, 2000 and 1999, Black Hills Energy  Resources,  Inc.
had  letters  of  credit   outstanding   of  $8.5  million  and  $13.2  million,
respectively and no balance outstanding on the overdraft line.

Our credit facilities contain restrictive  covenants and include commitment fees
ranging from .125 percent to .375 percent;  our credit  facilities with ABN AMRO
Bank,  NV also  include  utilization  fees of .75 percent on the amount by which
facility loans exceed 50 percent of the total facility  commitment.  The Company
and its subsidiaries had complied with all the covenants at December 31, 2000.

Interest rates under the facility  borrowings  vary and are based, at the option
of the Company at the time of the loan origination,  on either (i) a prime based
borrowing  rate  varying  from prime rate (9.5  percent at December 31, 2000) to
prime  rate plus 1.5  percent,  or (ii) on the  London  Interbank  Offered  Rate
(LIBOR)  (6.5  percent  for a  one-month  LIBOR  at  December  31,  2000)  based
borrowings  rates  varying  from  LIBOR  plus .625  percent  to LIBOR plus 1.375
percent.

(8)    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 following  methods and  assumptions  were used to estimate the fair value of
each class of the Company's financial instruments.

Cash and Cash Equivalents

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

Available for Sale Securities

The fair value of the Company's  investments equals the quoted market price when
available  and a quoted  market price for similar  securities if a quoted market
price  is not  available.  The  Company  has  classified  all of its  marketable
securities as available-for-sale as of December 31, 2000 and 1999. An unrealized
loss on the  Company's  investments  of $0.8 million was recorded as of December
31, 2000. At December 31, 1999 fair value approximated 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:

                                                                              2000
                                                                          (in thousands)
                                                             Carrying Amount              Fair Value
                                                                                      
                     Cash and cash equivalents                   $ 24,913                   $ 24,913
                     Securities available for sale                  2,113                      2,113
                     Long-term debt                               321,052                    337,446

                                                                               1999
                                                                          (in thousands)
                                                             Carrying Amount              Fair Value
                     Cash and cash equivalents                   $ 16,482                   $ 16,482
                     Securities available for sale                  7,586                      7,586
                     Long-term debt                               162,030                    165,958

(9)     WYODAK PLANT

The Company  owns a 20 percent  interest  and  Pacific  Power owns an 80 percent
interest  in the  Wyodak  plant  (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, 2000, the Company's investment in
the Plant  included  $71.8  million  in  electric  plant and  $22.4  million  in
accumulated  depreciation.  The Company's  share of direct expenses of the Plant
was $5.6 million, $4.9 million and $5.8 million for the years ended December 31,
2000,  1999  and  1998,  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 the agreement for an additional 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,
2000,  approximately  17,966,000 tons of coal were covered under this agreement.
Wyodak Resources' sales to the Plant were $23.2 million, $24.9 million and $23.2
million, for the years ended December 31, 2000, 1999 and 1998, respectively.

(10)    COMMITMENTS AND CONTINGENCIES

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.  An amended  agreement signed in October
1997  reduces  the  contract  capacity by 25  megawatts  (5  megawatts  per year
starting in 2000).  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 $14.6 million,  $17.8 million and $17.5
million in 2000, 1999 and 1998, 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  $0.7  million is charged to  operations  as  reclamation  expense
annually.  As of December 31, 2000, accrued reclamation costs were approximately
$17.7 million.

Legal Proceedings
On August 14, 2000, Wyodak Resources  Development Corp.  ("Wyodak") initiated an
action against  PacifiCorp as it concerns the Further  Restated and Amended Coal
Supply Agreement, dated as of May 5, 1987 ("Coal Supply Agreement").  The action
has been filed in the United States  District  Court for the District of Wyoming
as Case No. 00CV155-B.  Wyodak alleges that PacifiCorp has failed and refused to
make complete  payment to Wyodak for coal sold under the Coal Supply  Agreement,
and there was at that time approximately $5.0 million  outstanding and allegedly
due Wyodak from PacifiCorp.  Wyodak alleged that PacifiCorp's actions constitute
a breach of contract and asked for the appropriate monetary relief.

On August 31, 2000,  PacifiCorp  answered the Wyodak  Complaint and additionally
brought a  counterclaim  against  Wyodak  and Black  Hills  Corporation.  In its
action,  PacifiCorp  alleged that as a result of Wyodak's actions as it concerns
its billings under the Coal Supply Agreement,  PacifiCorp was entitled to cancel
and terminate the Coal Supply Agreement and Coal Handling Agreement,  as well as
the  recovery  of  damages.  PacifiCorp  alleged  that  Wyodak had not  properly
adjusted  upward and downward the components  which make up the coal price under
the Coal  Supply  Agreement,  and as a  result  PacifiCorp  had been  overbilled
appproximately  $35.0  million to $40.0  million  and that Wyodak  continued  to
overcharge  PacifiCorp  under the Coal Supply  Agreement  and the Coal  Handling
Agreement.  PacifiCorp  further  alleged  that the  overcharges  would result in
additional  overcharges of  approximately  $150.0 million through the balance of
the term of the Coal Supply  Agreement,  which  expires in June of 2013.  In its
action, PacifiCorp sought not only to cancel and terminate the contract but also
to  discharge  and  excuse any  further  obligation  under the same,  as well as
recovery of damages as set forth above.

Management is of the opinion that Wyodak has properly  billed  PacifiCorp  under
the  terms  of the  Coal  Supply  Agreement  and  Coal  Handling  Agreement  and
PacifiCorp's  withholding  of payment  constitutes a breach of contract on their
part.  Although  it  is  impossible  to  predict  whether  or  not  Black  Hills
Corporation  and Wyodak will ultimately be successful in defending the claim or,
if not, what the impact might be,  management  believes that the  disposition of
this  matter  will  not  have  a  material   adverse  effect  on  the  Company's
consolidated results of operations.

In  addition,  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.

(11)    EMPLOYEE BENEFIT PLANS

Defined Benefit Pension and Other Postretirement Plans

The Company has a  noncontributory  defined benefit pension plan (Plan) covering
the employees of Black Hills Power,  Wyodak Resources  Development  Corp., Black
Hills  Exploration  and  Production  and  Daksoft who meet  certain  eligibility
requirements. 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  are held in trust and  consist  primarily  of
equity securities and cash equivalents.

Net pension income for the Plan was as follows:

                                                                  2000                    1999                    1998
                                                                  ----                    ----                    ----
                                                                                     (in thousands)
                                                                                                       
Service cost                                                     $    967              $   1,174                $    895
Interest cost                                                       2,885                  2,598                   2,406
Estimated return on assets                                         (5,257)                (4,162)                 (4,146)
Amortization of transition amount                                     (90)                   (90)                    (90)
Amortization of prior service cost                                    231                     89                      89
Recognized net actuarial gain                                        (537)                     -                    (272)
                                                                  --------               ------                  --------
Net pension income                                                $(1,801)               $  (391)                $(1,118)
                                                                  ========               ========                ========
Actuarial assumptions:
   Discount rate                                                     7.5%                  6.75%                    7.5%
   Expected long-term rate of return on assets                      10.5%                 10.5%                    10.5%
   Rate of increase in compensation levels                           5.0%                  5.0%                     5.0%

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

                                                                        2000                        1999
                                                                        ----                        ----
                                                                                  (in thousands)
                                                                                            
              Beginning projected benefit obligation                   $39,615                    $39,490
                                                                       -------                    -------
              Service cost                                                 967                      1,174
              Interest cost                                              2,885                      2,598
              Actuarial losses                                             (48)                    (3,590)
              Benefits paid                                             (2,105)                    (1,903)
              Plan amendments                                                -                      1,846
                                                                       -------                    -------
              Net increase                                               1,699                        125
                                                                       -------                    -------
              Ending projected benefit obligation                      $41,314                    $39,615
                                                                       =======                    =======

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

                                                                        2000                        1999
                                                                        ----                        ----
                                                                                  (in thousands)
                                                                                            
              Beginning market value of plan assets                    $51,212                    $40,638
              Benefits paid                                             (2,105)                    (1,903)
              Investment income                                          7,453                     12,477
                                                                       -------                    -------
              Ending market value of plan assets                       $56,560                    $51,212
                                                                       =======                    =======

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

                                                                        2000                        1999
                                                                        ----                        ----
                                                                                  (in thousands)
                                                                                            
              Fair value of plan assets                                $56,560                    $51,212
              Projected benefit obligation                             (41,314)                   (39,615)
                                                                      --------                   --------
              Funded status                                             15,246                     11,597

              Unrecognized:
                 Net gain                                              (13,812)                   (12,105)
                 Prior service cost                                      2,054                      2,285
                 Transition asset                                            -                        (90)
                                                                      --------                   --------
              Prepaid pension cost                                    $  3,488                    $ 1,687
                                                                      ========                   ========

              Accumulated benefit obligation                           $33,374                    $31,914
                                                                      ========                   ========

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 $0.5  million,  $0.4 million and $0.4
million in 2000, 1999 and 1998, respectively.

Employees who are participants in the Plan and who retire from the Company on or
after  attaining  age 55 after  completing 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 was as follows:

                                                             2000                       1999                      1998
                                                             ----                       ----                      ----
                                                                                   (in thousands)
                                                                                                         
Service cost                                                   $282                      $225                      $135
Interest cost                                                   523                       362                       290
Amortization of transition obligation                           150                       150                       150
(Gain)/loss                                                      68                         1                       (42)
                                                             ------                      ----                      ----
                                                             $1,023                      $738                      $533
                                                             ======                      ====                      ====

Funding information as of October 1 was as follows:

                                                                                  2000                          1999
                                                                                  ----                          ----
                                                                                            (in thousands)
                                                                                                           
Accumulated postretirement benefit obligation:
     Retirees                                                                    $2,478                          $2,608
     Fully eligible active participants                                           1,203                           1,195
     Other active participants                                                    3,172                           3,278
                                                                                 ------                          ------
Unfunded accumulated postretirement benefit obligation                            6,853                           7,081
Unrecognized net loss                                                            (1,001)                         (1,667)
Unrecognized transition obligation                                               (1,797)                         (1,947)
                                                                                 ------                          ------
Accrued postretirement cost                                                      $4,055                          $3,467
                                                                                 ======                          ======

For measurement  purposes,  an 8.5 percent annual rate of increase in healthcare
benefits was assumed for 2000;  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 $0.2 million or 21.8 percent and the net periodic  postretirement
cost $0.2  million or 24.1  percent.  A one percent  decrease  would  reduce the
service and  interest  cost by $0.1 million or 16.9 percent and decrease the net
periodic  postretirement cost $0.2 million or 18.6 percent. The weighted-average
discount  rate  used  in  determining  the  accumulated  postretirement  benefit
obligation was 7.5 percent.

Defined Contribution Plan

The  Company  also  sponsors  a  401(k)  savings  plan for  eligible  employees.
Participants elect to invest up to 20 percent of their eligible  compensation on
a pre-tax basis. Effective January 1, 2000 (May 1, 2000 for employees covered by
the  collective   bargaining   agreement),   the  Company  provides  a  matching
contribution of 100 percent of the employee's tax-deferred  contribution up to a
maximum  3  percent   of  the   employee's   eligible   compensation.   Matching
contributions  vest at 20  percent  per  year  and are  fully  vested  when  the
participant  has 5 years of service with the  Company.  The  Company's  matching
contributions totaled $0.6 million for 2000.

(12)     INCOME TAXES

Income tax expense for the years indicated was:

                                                                           2000                 1999                  1998
                                                                           ----                 ----                  ----
                                                                                           (in thousands)
                                                                                                            
         Current                                                         $28,421               $13,498              $14,243
         Deferred                                                          2,576                 2,931               (1,886)
         Tax credits, net                                                   (639)                 (640)                (649)
                                                                         -------               -------              -------
                                                                         $30,358               $15,789              $11,708
                                                                         =======               =======              =======

The temporary  differences  which gave rise to the net deferred tax liability at
December 31, 2000 and 1999 were as follows:

                                                                                                                  Net Deferred
                                                                                                                     Income
                                                                                                                   Tax Asset
         December 31, 2000                                                Assets             Liabilities          (Liability)
                                                                          ------             -----------          -----------
                                                                                           (in thousands)
                                                                                                           
         Accelerated depreciation and other plant-related
           differences                                                    $ 5,393              $63,559             $(58,166)
         Regulatory asset                                                   1,621                    -                1,621
         Regulatory liability                                                   -                1,447               (1,447)
         Unamortized investment tax credits                                   886                    -                  886
         Mining development and oil exploration                             3,605                8,450               (4,845)
         Employee benefits                                                  3,308                1,347                1,961
         Other                                                              3,711                6,400               (2,689)
                                                                          -------              -------             --------
                                                                          $18,524              $81,203             $(62,679)
                                                                          =======              =======             ========

                                                                                                                  Net Deferred
                                                                                                                     Income
                                                                                                                   Tax Asset
         December 31, 1999                                                Assets             Liabilities          (Liability)
                                                                          ------             -----------          -----------
                                                                                           (in thousands)
         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)
                                                                         ========              =======             ========

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

                                                                           2000                 1999                  1998
                                                                           ----                 ----                  ----
                                                                                                             
         Federal statutory rate                                             35.0%                 35.0%                35.0%
         State income tax                                                    1.4                   -                    -
         Amortization of investment tax credits                             (1.0)                 (0.9)                (1.3)
         Tax-exempt interest income                                          -                    (0.5)                (1.1)
         Percentage depletion in excess of cost                             (1.1)                 (1.6)                (1.7)
         Other                                                               2.2                  (2.1)                 0.3
                                                                            ----                  ----                 ----
                                                                            36.5%                 29.9%                31.2%
                                                                            ====                  ====                 ====

(13)      BUSINESS SEGMENTS

The  Company's  reportable  segments  are those that are based on the  Company's
method of internal reporting,  which generally segregates the strategic business
groups due to differences in products,  services and regulation.  As of December
31, 2000,  substantially all of the Company's  operations and assets are located
within the United States.  The Company's  operations  are conducted  through six
business  segments that  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;  Fuel  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;
Independent  Power, which produces and sells power to wholesale  customers;  and
Communications and Others,  which primarily markets  communications and software
development services.

Segment  information follows the same accounting policies as described in Note 1
- - BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT  ACCOUNTING POLICIES.  Segment
information  included  in  the  accompanying  Consolidated  Balance  Sheets  and
Consolidated Statements of Income is as follows (in thousands):

ASSETS                                                  Independent Energy
                                         --------------------------------------------------
                                                   Oil and       Fuel      Independent   Communications
                            Electric     Mining      Gas       Marketing      Power         & Others      Eliminations     Total
                           ---------- ---------- ----------- ------------ -------------- ---------------  ------------   -----------
                                                                                                
At December 31, 2000
Current assets              $ 133,542   $167,820     $ 3,452    $ 330,352    $   25,645  $     13,215    $  (255,016)   $  419,010
Total assets                  627,930    251,136      36,396      346,333       375,811       132,724       (450,010)    1,320,320

At December 31, 1999
Current assets              $  93,837   $ 57,427     $ 1,988     $ 84,867    $   52,471  $      9,698    $  (113,931)   $  186,357
Total assets                  522,285    136,372      29,381       99,064        52,690        72,711       (244,011)      668,492

At December 31, 1998
Current assets              $  43,760   $ 25,872     $ 1,335     $ 77,402    $        4  $      6,067    $   (13,960)   $  140,480
Total assets                  451,404     93,480      26,666       86,300            57        18,441       (116,931)      559,417

                                                        Independent Energy
                                         --------------------------------------------------
                                                   Oil and       Fuel      Independent   Communications
Year ended                  Electric     Mining      Gas       Marketing      Power         & Others      Eliminations     Total
December 31, 2000          ---------- ---------- ----------- ------------ -------------- ---------------  ------------   -----------

Electric revenues           $ 173,308  $       -   $       -  $        -     $        -  $            -    $        -     $  173,308
Coal revenues                       -     30,530           -      37,099              -               -             -         67,629
Gas revenues                        -          -       9,335     871,296              -               -       (14,320)       866,311
Oil revenues                        -          -       7,211     458,575              -               -             -        465,786
Other operating
 revenues                           -          -       3,782           -         39,660          11,371        (4,011)        50,802
                           ----------  ---------   ---------  ----------- --------------  -------------  ------------    -----------
Total operating
 revenues                   $ 173,308   $ 30,530    $ 20,328   $1,366,970     $   39,660  $      11,371    $  (18,331)    $1,623,836
                           ----------  ---------   ---------  ----------- --------------  -------------  -------------   -----------

Depreciation, depletion
 and amortization           $  14,966     $3,525     $ 4,071  $       644     $    3,646   $    6,012      $       -      $   32,864
Operating income (loss)        68,208      8,794       7,906       23,774         20,374      (14,306)             -         114,750
Interest expense               17,411      8,006         372          535         11,911        6,350        (14,243)         30,342
Income taxes (benefit)         19,469      2,660       2,609        9,323          3,154       (6,857)             -          30,358
Net income (loss)
available for common           37,100      7,173       4,992       14,009          3,241      (12,557)        (1,188)         52,770
Property additions,
investments and
acquisition of net assets      25,257      2,419       9,259           (3)        81,335*      58,922              -         177,189

*Excludes the non-cash acquisition of Indeck Capital,  Inc. as described in Note
14.

                                                        Independent Energy
                                         --------------------------------------------------
Year ended                                         Oil and       Fuel       Independent  Communications
December 31, 1999          Electric     Mining       Gas       Marketing      Power         & Others     Eliminations      Total
                         ------------- ---------- ----------- ------------ ------------  --------------  ------------   ------------
                                                                                                 
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 operating
 revenues                           -          -       2,977            -            -           3,423        (3,145)          3,255
                            ---------   --------  ----------   ----------  -----------   -------------    -----------    -----------
Total operating
 revenues                   $ 133,222   $ 31,095   $  13,052   $  614,228  $         -   $       3,423    $   (3,145)    $   791,875
                            ---------   --------  ----------   ----------- -----------   -------------    ----------     -----------

Depreciation, depletion
 and 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       1,260         568          719          111           1,172        (2,200)         15,460
Income taxes (benefit)        12,446       3,439         968           50          (58)         (1,056)            -          15,789
Net income (loss)
available for common          27,362       9,715       2,462         (185)        (109)         (1,263)         (915)         37,067
Property additions,
investments and
acquisition of net assets     31,911       5,422       9,968        5,947       52,319          49,042             -         154,609

                                                        Independent Energy
                                         --------------------------------------------------
Year ended                                         Oil and       Fuel       Independent  Communications
December 31, 1999          Electric     Mining       Gas       Marketing      Power         & Others     Eliminations      Total
                         ------------- ---------- ----------- ------------ ------------  --------------  ------------   ------------
                                                                                                  
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 operating
 revenues                            -          -      3,358          798             -        2,437          (2,437)          4,156
                          ------------ ---------- ------------ ----------  -------------- --------------  -----------     ----------
Total operating
 revenues                    $ 129,236   $ 31,413  $  12,562   $  506,043    $        -      $ 2,437       $  (2,437)     $  679,254
                          ------------ ---------- ------------ ----------  -------------- --------------  -----------     ----------

Depreciation, depletion
 and 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 income                 13,572         10        355          731             -           39               -          14,707
Income taxes (benefit)          12,612      4,126     (4,689)**      (116)          (64)        (161)              -          11,708
Net income (loss)
available for common            24,825      9,750     (7,976)**      (346)         (118)        (226)           (101)         25,808
Property additions,
investments and
acquisition of net
assets                          11,451      1,406     10,169        2,384             -        1,815               -          27,225

**Includes the impact of a $13.5 million  pre-tax  write-down of certain oil and
natural gas properties.

(14)      ACQUISITIONS

On July 7, 2000, the Company  acquired Indeck  Capital,  Inc. and merged it into
Black Hills Energy  Capital,  Inc.  The new entity owns varying  interests in 14
operating  independent  power  plants in  California,  New York,  Massachusetts,
Colorado and Idaho totaling approximately 350 megawatts.

The  acquisition  was a stock  transaction  with the Company  issuing  1,536,747
shares of common stock to the  shareholders of Indeck priced at $21.98 per share
(approximately 7 percent of the Company's  common stock after the  transaction),
along with $4 million  in  preferred  stock,  resulting  in a purchase  price of
approximately $37.8 million. Additional consideration,  consisting of common and
preferred stock, may be paid in the form of an earn-out over a four-year period.
The  earn-out  consideration  will be based on the acquired  company's  earnings
during  such  period  and  cannot  exceed  $35.0  million  in total.  Additional
consideration  paid out under the  earn-out  will be  recorded as an increase to
goodwill.

The  acquisition  has been accounted for under the purchase method of accounting
and,  accordingly,  the purchase price has been allocated to the acquired assets
and  liabilities  based on estimates of the fair values of the assets  purchased
and the liabilities  assumed as of the date of  acquisition.  Fair values in the
allocation  include assets acquired of approximately  $151.1 million  (excluding
goodwill)  and  liabilities  assumed  of  approximately  $138.7  million.  As of
December 31, 2000, the purchase price and related acquisition costs exceeded the
fair values  assigned to net tangible  assets by  approximately  $25.4  million,
which  was  recorded  as  goodwill  and is  being  amortized  over 25 years on a
straight-line basis.

Prior to the closing of the Indeck  Capital  transaction,  there was no material
relationship  between its shareholders and the Company or any of its affiliates,
any director or officer of the Company or any of their  associates,  except that
the Company  through its  subsidiaries  and Indeck  Capital  jointly owned Black
Hills  Colorado,  LLC and both parties held  interests in Indeck North  American
Power  Partners,  L.P. and Indeck North  American  Power Fund,  L.P. Black Hills
Colorado owns 111 megawatts of combustion turbine  generating  facilities in the
Front Range of Colorado.

In  addition,   the  Company  made   several   step-acquisitions   resulting  in
consolidation of $169.5 million of assets and $138.8 million of liabilities. The
related transactions are as follows:

o    Through various transactions, acquired an additional 27.11 percent interest
     in Indeck North American Power Fund,  L.P. and an additional  46.66 percent
     interest in Indeck North American Power Partners,  L.P., for  approximately
     $13.0 million in cash.

o    Acquired  a 39.6  percent  interest  in each  of  Northern  Electric  Power
     Company,  L.P. and South Glens Falls Limited  Partnership for approximately
     $4.2 million in cash.

o    Acquired  substantially  all of the  partnership  interests in Middle Falls
     Limited Partnership, Sissonville Limited Partnership and New York State Dam
     Limited Partnership for approximately $12.9 million in cash.

Operating  activities of the above acquired  companies have been included in the
accompanying   consolidated   financial   statements   since  their   respective
acquisition  dates.  The  following  unaudited  pro forma  condensed  results of
operations  presents the effect of the  acquisitions  as if they had occurred on
January 1, 1999.  The pro forma  financial  data is provided  for  informational
purposes  only and does not purport to be  indicative  of the results that would
have been obtained if the acquisitions had been effected on January 1, 1999. The
pro forma financial information reflects the amortization of the excess purchase
price  over the fair  value of net  assets  acquired  and the  income tax effect
thereof for the years ended December 31, 2000 and 1999 as follows:

                                          2000                      1999
                                          ----                      ----
                             (Unaudited, in thousands, except per share amounts)

Revenues                               $1,668,851                 $840,891
Operating income                         $139,053                  $73,900
Net income available for common           $57,542                  $34,310
Net income per share:  Basic                $2.47                    $1.49
                       Diluted              $2.45                    $1.49

(15)       OIL AND GAS RESERVES  (Unaudited)

Black Hills  Exploration  and  Production has interests in 639 producing oil and
gas properties in seven states.  Black Hills  Exploration  and  Production  also
holds leases on approximately 185,926 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, 2000, 1999
and 1998,  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.

                                                          2000                          1999                        1998
                                                          ----                          ----                        ----
                                                    Oil           Gas            Oil            Gas           Oil           Gas
                                                    ---           ---            ---            ---           ---           ---
                                                                 (in thousands of barrels of oil and MMcf of gas)
                                                                                                          
Proved developed and undeveloped reserves:
   Balance at beginning of year                      4,109        19,460          2,368        15,952           2,495        9,052
     Production                                       (352)       (3,285)          (309)       (2,801)           (353)      (2,068)
     Additions                                         625         4,228            376         7,718           1,149       10,721
     Property sales                                      -             -           (164)          (66)              -            -
     Revisions to previous estimates                    31        (1,999)         1,838        (1,343)           (923)      (1,753)
                                                   -------       -------        -------       -------         -------      -------
Balance at end of year                               4,413        18,404          4,109        19,460           2,368       15,952
                                                   =======       =======        =======       =======         =======      =======
Proved developed reserves at end of
   year included above                               3,047        16,418          2,819        14,391           1,463       10,041
                                                   =======       =======        =======       =======         =======      =======

Year-end prices                                     $26.80         $9.78         $24.28         $1.99           $9.16        $1.93
                                                    ======         =====         ======         =====           =====        =====

In December 1998,  Black Hills  Exploration  and  Production  recognized a $13.5
million  pre-tax  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.

(16)      QUARTERLY HISTORICAL DATA (Unaudited)

The Company  operates on a calendar year basis.  The following  table sets forth
selected unaudited historical operating results and market data for each quarter
of 2000 and 1999.

                                                     First         Second          Third             Fourth
                                                    Quarter        Quarter        Quarter            Quarter
                                                    -------        -------        -------            -------
                                                                (in thousands, except per share amounts)
                                                                                         
              2000:
                 Operating revenues                 $247,959       $336,978       $453,231           $585,668
                 Operating income                     16,872         15,200         42,519             40,159
                 Net income available
                  for common stock                     9,061          8,061         16,285             19,363
                 Earnings per common
                  share:    Basic                       0.42           0.38           0.71               0.84
                            Diluted                     0.42           0.38           0.71               0.83
                 Dividends paid per share               0.27           0.27           0.27               0.27
                 Common stock prices
                     High                              25.19          25.19          30.13              46.06
                     Low                               20.44          20.88          22.00              27.00

              1999:
                 Operating revenues                 $168,201       $186,195       $219,779           $217,700
                 Operating income                     15,980         13,786         16,675             15,450
                 Net income available
                  for common stock                     9,035          7,763          9,725             10,544
                 Earnings per common
                  share:    Basic                       0.42           0.36           0.45               0.50
                            Diluted                     0.42           0.36           0.45               0.50
                 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

(17)      SUBSEQUENT EVENT (Unaudited)

On March 8, 2001,  Black Hills Energy Capital,  Inc., the Company's  independent
power  subsidiary  announced it had signed a definitive  agreement to purchase a
240 megawatt  gas-fired turbine  generation  facility  (Fountain Valley) located
near Colorado  Springs,  Colorado from Enron  Corporation.  The  transaction  is
expected to close around March 31, 2001.

The  Fountain  Valley  facility  features  six LM-6000  simple-cycle,  gas-fired
turbines,  a technology identical to existing Company facilities in Colorado and
Wyoming. All necessary permitting has been approved and the plant is expected to
phase in its  generation  capacity  beginning  in May  2001.  The  Company  also
announced that it has signed an 11-year contract with Public Service of Colorado
to utilize the plant for peaking purposes. The contract is a tolling arrangement
in which the Company assumes no fuel costs.  The cost of the project is expected
to be  approximately  $175 million.  The Company  expects to finance the project
primarily with  non-recourse  debt and negotiations are presently under way with
certain lenders.

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

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

PART III

ITEM 10.       DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information  regarding  the directors of the Company is  incorporated  herein by
reference to the Proxy Statement for the Annual Shareholders' Meeting to be held
May 30, 2001.

EXECUTIVE OFFICERS

Daniel  P.  Landguth,  age 54,  was  elected  Chairman  of the  Board  and Chief
Executive  Officer in January  1991.  Mr.  Landguth  also  currently  chairs the
Executive  Committee.  He has 30 years  of  experience  with  Black  Hills.  Mr.
Landguth  holds a B.S.  degree in Electrical  Engineering  from the South Dakota
School of Mines and Technology.

Everett E. Hoyt,  age 61, has been President and Chief  Operating  Officer since
February 2001. Since 1989, he has been President and Chief Operating  Officer of
our  regulated  utility  business - a role he  continues  to play.  Mr. Hoyt was
elected to the Board of  Directors  in 1991.  Prior to joining  us, Mr. Hoyt was
employed by NorthWestern Corporation for 16 years where he served as Senior Vice
President-Legal  and as a  member  of the  Board of  Directors.  He holds a B.S.
degree  in  Mechanical  Engineering  from the South  Dakota  School of Mines and
Technology and a J.D. from the University of South Dakota School of Law.

Gary R. Fish, age 42, has been the President and COO of our  Independent  Energy
Group since September 1999. Prior to that, he served in several  development and
accounting  officer positions for us since August 1988. Mr. Fish holds a B.S. in
Business  Administration  from the University of South Dakota and is a certified
public accountant.

Ronald D. Schaible,  age 56, has been Senior Vice President of Communications of
Black Hills  Corporation  and Vice President and General  Manager of Black Hills
FiberCom since October 1998. Mr.  Schaible has more than 25 years  experience in
the  telecommunications  industry.  From 1995 to 1998, he was Vice President and
General  Manager of the Kansas City and  Missouri  subsidiaries  of Brooks Fiber
Properties.  Mr.  Schaible was  responsible  for both network  construction  and
operations in Kansas City. He holds a B.S. in Electrical  Engineering from South
Dakota State University.

Mark T. Thies,  age 37, has been our Senior Vice  President and Chief  Financial
Officer since March 2000.  From May 1997 to March 2000,  he was our  Controller.
From 1990 to 1997,  Mr. Thies served in a number of  accounting  positions  with
InterCoast  Energy  Company,  an  unregulated  energy company and a wholly-owned
subsidiary of  MidAmerican  Energy  Holdings  Company.  Mr. Thies holds B.A.s in
Accounting  and  Business  Administration  from Saint  Ambrose  College and is a
certified public accountant.

Thomas M. Ohlmacher, age 49, has been the Senior Vice President-Power Supply and
Power  Marketing  since January 30, 2001 and Vice President - Power Supply since
August 1994.  Prior to that,  he held several  positions  with our company since
1974.  Mr.  Ohlmacher  holds a B.S. in Chemistry from the South Dakota School of
Mines and Technology.

James  M.  Mattern,  age  46,  has  been  the  Senior  Vice  President-Corporate
Administration   since   September   1999,  and  was  Vice   President-Corporate
Administration  from January 1994 to September  1999.  From 1997 to 1999, he was
also  Assistant to the CEO. Mr.  Mattern has 12 years of experience  with us. He
holds a B.S. in Social  Sciences  and an M.S. in  Administration  from  Northern
State University.

Steven J. Helmers,  age 44, has been our General Counsel and Corporate Secretary
since January 2001.  Prior to joining us, Mr. Helmers was a shareholder with the
Rapid  City,  South  Dakota  law firms of Truhe,  Beardsley,  Jensen,  Helmers &
VonWald,  from 1997 to January 2001, and Lynn, Jackson,  Schultz & Lebrun, P.C.,
from 1983 to 1997. He holds a J.D. from the University of South Dakota School of
Law.

Roxann R.  Basham,  age 39, has been our Vice  President-Controller  since March
2000.  From  December  1997 to March 2000,  she was Vice  President-Finance  and
Secretary/Treasurer.   From  1993  until   December  1997,  she  served  as  our
Secretary/Treasurer,  and has a total  of 16 years of  experience  with us.  She
holds a B.S. in Business  Administration from the University of South Dakota and
is a certified public accountant.

David R. Emery, age 38, has been our Vice President-Fuel Resources since January
1997.  From June 1993 to January  1997,  he was  General  Manager of Black Hills
Exploration  and  Production.  Mr. Emery has 12 years of experience  with us. He
holds a B.S. in Petroleum Engineering from the University of Wyoming and an M.S.
in Business Administration from the University of South Dakota.

Kyle D. White, age 41, has been Vice President - Corporate Affairs since January
30, 2001 and Vice  President-Marketing  and Regulatory  Affairs since July 1998.
Mr. White served as Director-Strategic  Marketing and Sales from 1993 to January
1998 and Vice President-Energy Services from January 1998 to July 1998. He has a
total of 18 years of experience with us. Mr. White holds a B.S.
and M.S. in Business Administration from the University of South Dakota.

ITEM 11.       EXECUTIVE COMPENSATION

Information  regarding management  remuneration and transactions is incorporated
herein by reference to our Proxy Statement for the Annual Shareholders'  Meeting
to be held May 30, 2001.

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 our Proxy  statement for the
Annual Shareholders' Meeting to be held May 30, 2001.

ITEM 13.       CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information   regarding  certain   relationships  and  related  transactions  is
incorporated  herein  by  reference  to  our  Proxy  Statement  for  the  Annual
Shareholders' Meeting to be held May 30, 2001.

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

              Exhibit
              Number                            Description
              -------                           -----------
               2*          Plan of Exchange Between Black Hills Corporation and
                           Black Hills Holding Corporation (filed as an exhibit
                           to the Registrant's Registration Statement on Form
                           S-4 (No. 333-52664)).
               3.1*        Articles of Incorporation of the Registrant (filed as
                           an exhibit to the Registrant's Registration Statement
                           on Form S-4 (No. 333-52664)).
               3.2*        Articles of Amendment of the Registrant (filed as an
                           exhibit to the Registrant's Form 8-K filed on
                           December 26, 2000).
               3.3*        Bylaws of the Registrant  (filed as an exhibit to the
                           Registrant's  Registration Statement on Form S-4 (No.
                           333-52664)).
               3.4*        Statement of  Designations,  Preferences and Relative
                           Rights and  Limitations  of No Par  Preferred  Stock,
                           Series 2000-A of the Registrant  (filed as an exhibit
                           to the  Registrant's  Form 8-K filed on December  26,
                           2000).
               4.1*        Restated and Amended Indenture of Mortgage and Deed
                           of Trust of Black Hills Power, Inc. dated as of
                           September 1, 1999 (filed as an exhibit to the
                           Registrant's Registration Statement on Form S-4
                           (No. 333-52664)).
               4.2         Form of Stock Certificate for Common Stock, Par Value
                           $1.00 Per Share.
              10.1*        Agreement for Transmission Service and the Common Use
                           of Transmission  Systems dated January 1, 1986, among
                           Black  Hills  Power,   Inc.,   Basin  Electric  Power
                           Cooperative,  Rushmore  Electric  Power  Cooperative,
                           Inc.,  Tri-County Electric  Association,  Inc., Black
                           Hills Electric  Cooperative,  Inc. and Butte Electric
                           Cooperative,  Inc.  (filed  as  Exhibit  10(d) to the
                           Registrant's Form 10-K for 1987).
              10.2*        Restated and Amended Coal Supply Agreement for NS #2
                           dated February 12, 1993 (filed as Exhibit 10(c) to
                           the Registrant's Form 10-K for 1992).
              10.3*        Coal Leases between Wyodak Resources Development
                           Corp. and the Federal Government
                           -Dated May 1, 1959 (filed as Exhibit 5(i) to the
                            Registrant's Form S-7, File No. 2-60755)
                             -Modified  January  22,  1990  (filed as  Exhibit
                              10(h) to the Registrant's Form 10-K for 1989)
                           -Dated April 1, 1961 (filed as Exhibit 5(j) to the
                            Registrant's Form S-7, File No. 2-60755)
                             -Modified  January  22,  1990  (filed as  Exhibit
                              10(i) to  Registrant's  Form 10-K for  1989)
                           -Dated October 1, 1965 (filed as Exhibit 5(k) to the
                            Registrant's Form S-7, File No. 2-60755)
                             -Modified January 22, 1990 (filed as Exhibit 10(j)
                              to the Registrant's Form 10-K for 1989).
              10.4*        Further Restated and Amended Coal Supply Agreement
                           dated May 5, 1987 between Wyodak Resources
                           Development Corp. and Pacific Power & Light Company
                           (filed as Exhibit 10(k) to the Registrant's Form 10-K
                           for 1987).
              10.5*        Second Restated and Amended Power Sales Agreement
                           dated September 29, 1997, between PacifiCorp and
                           Black Hills Power, Inc. (filed as Exhibit 10(e) to
                           the Registrant's Form 10-K for 1997).
              10.6*        Coal  Supply  Agreement  for  Wyodak  Unit  #2  dated
                           February  3,  1983,  and  Ancillary  Agreement  dated
                           February   3,   1982,    between   Wyodak   Resources
                           Development Corp.,  Pacific Power & Light Company and
                           Black Hills Power,  Inc.  (filed as Exhibit  10(o) to
                           the  Registrant's  Form 10-K for 1983).  Amendment to
                           Agreement  for Coal Supply for Wyodak #2 dated May 5,
                           1987 (filed as Exhibit 10(o) to the Registrant's Form
                           10-K for 1987).
              10.7*        Reserve Capacity  Integration  Agreement dated May 5,
                           1987, between Pacific Power & Light Company and Black
                           Hills  Power,  Inc.  (filed as  Exhibit  10(u) to the
                           Registrant's Form 10-K for 1987).
              10.8*        Marketing, Capacity and Storage Service Agreement
                           between Black Hills Power, Inc. and PacifiCorp dated
                           September 1, 1995 (filed as Exhibit 10(ag) to the
                           Registrant's Form 10-K for 1995).
              10.9*        Assignment  of Mining  Leases and  Related  Agreement
                           effective  May 27,  1997,  between  Wyodak  Resources
                           Development  Corp.  and Kerr-McGee  Coal  Corporation
                           (filed as Exhibit 10(u) to the Registrant's Form 10-K
                           for 1997).
              10.10*       Rate Freeze Extension (filed as Exhibit 10(t) to the
                           Registrant's Form 10-K for 1999).
              10.11 +      Amended and Restated Pension Equalization Plan of
                           Black Hills Corporation dated January 6, 2000.
              10.12 +      First Amendment to the Pension Equalization Plan of
                           Black Hills Corporation dated January 30, 2001.
              10.13 +      Black Hills Corporation Nonqualified Deferred
                           Compensation Plan dated June 1, 1999.
              10.14 +      Black Hills Corporation 1999 Stock Option Plan.
              10.15*+      Agreement for Supplemental Pension Benefit for
                           Everett E. Hoyt dated January 20, 1992 (flied as
                           Exhibit 10(gg) to the Registrant's Form 10-K for
                           1992).
              10.16*+      Change in Control Agreements for various officers
                           (filed as Exhibit 10(af) to the Registrant's
                           Form 10-K for 1995).
              10.17*+      Black Hills Corporation 1996 Stock Option Plan
                           (filed as Exhibit 10(s) to the Registrant's
                           Form 10-K for 1997).
              10.18*+      Outside Directors Stock Based Compensation Plan
                           (filed as Exhibit 10(t) to the Registration's Form
                           10-K for 1997).
              10.19*+      Officers Short-Term Incentive Plan (filed as Exhibit
                           10(s) to the Registrant's Form 10-K for 1999).
              10.20*       Agreement and Plan of Merger, dated as of January 1,
                           2000, among Black Hills Corporation, Black Hills
                           Energy Capital, Inc., Indeck Capital, Inc., Gerald R.
                           Forsythe, Michelle R. Fawcett, Marsha Fournier,
                           Monica Breslow, Melissa S. Forsythe and John W.
                           Salyer, Jr. (Exhibit 2 to Schedule 13D filed on
                           behalf of the former shareholders of Indeck Capital,
                           Inc. consisting of Gerald R. Forsythe, Michelle R.
                           Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                           Forsythe and John W. Salyer, Jr. dated July 7, 2000).
              10.21*       Addendum to the Agreement and Plan of Merger, dated
                           as of April 6, 2000, among Black Hills Corporation,
                           Black Hills Energy Capital, Inc., Indeck Capital,
                           Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                           Fournier, Monica Breslow, Melissa S. Forsythe and
                           John W. Salyer, Jr. (Exhibit 3 to Schedule 13D filed
                           on behalf of the former shareholders of Indeck
                           Capital,consisting of Gerald R. Forsythe, Michelle R.
                           Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                           Forsythe and John W. Salyer, Jr. dated July 7, 2000).
              10.22*       Supplemental Agreement Regarding Contingent Merger
                           Consideration, dated as of January 1, 2000, among
                           Black Hills Corporation, Black Hills Energy Capital,
                           Inc., Indeck Capital, Inc., Gerald R. Forsythe,
                           Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
                           Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit
                           4 to Schedule 13D filed on behalf of the former
                           shareholders of Indeck Capital, Inc. consisting of
                           Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                           Fournier, Monica Breslow, Melissa S. Forsythe and
                           John W. Salyer, Jr. dated July 7, 2000).
              10.23*       Supplemental Agreement Regarding Restructuring of
                           Certain Qualifying Facilities (Exhibit 5 to Schedule
                           13D filed on behalf of the former shareholders of
                           Indeck Capital, Inc. consisting of Gerald R.
                           Forsythe, Michelle R. Fawcett, Marsha Fournier,
                           Monica Breslow, Melissa S. Forsythe and John W.
                           Salyer, Jr. dated July 7, 2000).
              10.24*       Addendum to the Agreement and Plan of Merger, dated
                           as of June 30, 2000, among Black Hills Corporation,
                           Black Hills Energy Capital, Inc., Indeck Capital,
                           Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                           Fournier, Monica Breslow, Melissa S. Forsythe and
                           John W. Salyer, Jr. (Exhibit 6 to Schedule 13D filed
                           on behalf of the former shareholders of Indeck
                           Capital,consisting of Gerald R. Forsythe, Michelle R.
                           Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                           Forsythe and John W. Salyer, Jr. dated July 7, 2000).
              10.25*       Registration Rights Agreement among Black Hills
                           Corporation, Gerald R. Forsythe, Michelle R. Fawcett,
                           Marsha Fournier, Monica Breslow, Melissa S. Forsythe
                           and John W. Salyer, Jr. (Exhibit 7 to Schedule 13D
                           filed on behalf of the former shareholders of Indeck
                           Capital,consisting of Gerald R. Forsythe, Michelle R.
                           Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                           Forsythe and John W. Salyer, Jr. dated July 7, 2000).
              10.26*       Shareholders Agreement among Black Hills Corporation,
                           Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                           Fournier, Monica Breslow, Melissa S. Forsythe
                           and John W. Salyer, Jr. (Exhibit 8 to Schedule 13D
                           filed on behalf of the former shareholders of Indeck
                           Capital,consisting of Gerald R. Forsythe, Michelle R.
                           Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                           Forsythe and John W. Salyer, Jr. dated July 7, 2000).
              21           List of Subsidiaries of Black Hills Corporation.
              23.1         Consent of Independent Public Accountants.
              23.2         Consent of Petroleum Engineer and Geologist.

- ----------
*       Previously filed as part of the filing indicated and incorporated by
        reference herein.
+       Indicates a board of director or management compensatory plan.

(b)     Reports on Form 8-K

        We have filed the following Reports on Form 8-K since September 30,2000.

        Form 8-K filed December 22, 2000.

               Reported the formation of the holding company structure through a
               "Plan of  Exchange"  between  Black Hills  Corporation  and Black
               Hills Holding Corporation on December 22, 2000.

         Form 8-K dated December 5, 2000, filed January 12, 2001.

               Reported  Adirondack Hydro Development  Corporation,  an indirect
               subsidiary  of the  Registrant,  acquired a 19.8 percent  limited
               partnership  interest in each of Northern Electric Power Company,
               L.P.  and South Glens Falls  Limited  Partnership  from  Allstate
               Insurance Company and Allstate Life Insurance Company.

         Form 8-K/A1 dated February 16, 2001.

               Filed the financial statement and exhibits for the Form 8-K filed
               on January 12, 2001.

(c) See (a) 3. Exhibits above.

(d) See (a) 2. Schedules above.

                                   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
                                       and Chief Executive Officer

Dated:   March 19, 2001

         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 19, 2001
- ---------------------------------------------                   Executive Officer
Daniel P. Landguth, Chairman,
 and Chief Executive Officer

       MARK T. THIES                                          Principal Financial Officer                 March 19, 2001
- ---------------------------------------------
Mark T. Thies, Senior Vice President and
 Chief Financial Officer

       ROXANN R. BASHAM                                       Principal Accounting Officer                March 19, 2001
- ---------------------------------------------
Roxann R. Basham, Vice President-Controller,
 and Assistant Secretary

       ADIL M. AMEER                                          Director                                    March 19, 2001
- ---------------------------------------------
Adil M. Ameer

       BRUCE B. BRUNDAGE                                      Director                                    March 19, 2001
- ---------------------------------------------
Bruce B. Brundage

       DAVID C. EBERTZ                                        Director                                    March 19, 2001
- ---------------------------------------------
David C. Ebertz

       GERALD R. FORSYTHE                                     Director                                    March 19, 2001
- ---------------------------------------------
Gerald R. Forsythe

       JOHN R. HOWARD                                         Director                                    March 19, 2001
- ---------------------------------------------
John R. Howard

       EVERETT E. HOYT                                        Director and Officer                        March 19, 2001
- ---------------------------------------------
Everett E. Hoyt (President and Chief
Operating Officer of Black Hills Corporation)

       KAY S. JORGENSEN                                       Director                                    March 19, 2001
- ---------------------------------------------
Kay S. Jorgensen

       DAVID S. MANEY                                         Director                                    March 19, 2001
- ---------------------------------------------
David S. Maney

       THOMAS J. ZELLER                                       Director                                    March 19, 2001
- ---------------------------------------------
Thomas J. Zeller

                                INDEX TO EXHIBITS

         Exhibit
         Number                               Description
         ------                               -----------

          2*          Plan of Exchange Between Black Hills Corporation and Black
                      Hills Holding Corporation (filed as an exhibit to
                      the Registrant's Registration Statement on
                      Form S-4 (No. 333-52664)).
          3.1*        Articles of Incorporation  of the Registrant  (filed as an
                      exhibit to the Registrant's Registration Statement on Form
                      S-4 (No. 333-52664)).
          3.2*        Articles of Amendment of the Registrant (filed as an
                      exhibit to the Registrant's Form 8-K filed on December 26,
                      2000).
          3.3*        Bylaws  of the  Registrant  (filed  as an  exhibit  to the
                      Registrant's  Registration  Statement  on  Form  S-4  (No.
                      333-52664)).
          3.4*        Statement of Designations, Preferences and Relative Rights
                      and Limitations of No Par Preferred  Stock,  Series 2000-A
                      of the Registrant (filed as an exhibit to the Registrant's
                      Form 8-K filed on December 26, 2000).
          4.1*        Restated  and Amended  Indenture  of Mortgage  and Deed of
                      Trust of Black Hills Power,  Inc. dated as of September 1,
                      1999 (filed as an exhibit to the Registrant's Registration
                      Statement on Form S-4 (No. 333-52664)).
          4.2         Form of Stock Certificate for Common Stock, Par Value
                      $1.00 Per Share.
         10.1*        Agreement for  Transmission  Service and the Common Use of
                      Transmission  Systems dated  January 1, 1986,  among Black
                      Hills  Power,  Inc.,  Basin  Electric  Power  Cooperative,
                      Rushmore  Electric  Power  Cooperative,  Inc.,  Tri-County
                      Electric   Association,   Inc.,   Black   Hills   Electric
                      Cooperative,  Inc. and Butte  Electric  Cooperative,  Inc.
                      (filed as Exhibit 10(d) to the Registrant's  Form 10-K for
                      1987).
         10.2*        Restated and Amended Coal Supply Agreement for NS #2 dated
                      February 12, 1993 (filed as Exhibit 10(c) to the
                      Registrant's Form 10-K for 1992).
         10.3*        Coal Leases between Wyodak Resources Development Corp. and
                      the Federal Government
                         -Dated May 1, 1959 (filed as Exhibit 5(i) to the
                          Registrant's Form S-7, File No. 2-60755)
                            -Modified January 22, 1990 (filed as Exhibit 10(h)
                             to the Registrant's Form 10-K for 1989)
                         -Dated April 1, 1961 (filed as Exhibit 5(j) to the
                          Registrant's  Form S-7, File No. 2-60755)
                            -Modified January 22, 1990 (filed as Exhibit 10(i)
                             to  Registrant's  Form 10-K for 1989)
                         -Dated October 1, 1965 (filed as Exhibit 5(k) to the
                          Registrant's Form S-7, File No. 2-60755)
                            -Modified January 22, 1990 (filed as Exhibit 10(j)
                             to the Registrant's Form 10-K for 1989).
         10.4*        Further Restated and Amended Coal Supply  Agreement dated
                      May 5, 1987 between Wyodak Resources Development Corp. and
                      Pacific Power & Light  Company  (filed as Exhibit 10(k) to
                      the Registrant's Form 10-K for 1987).
         10.5*        Second  Restated and Amended Power Sales  Agreement  dated
                      September  29, 1997,  between  PacifiCorp  and Black Hills
                      Power,  Inc.  (filed as Exhibit 10(e) to the  Registrant's
                      Form 10-K for 1997).
         10.6*        Coal Supply Agreement for Wyodak Unit #2 dated February 3,
                      1983,  and  Ancillary  Agreement  dated  February 3, 1982,
                      between Wyodak Resources  Development Corp., Pacific Power
                      & Light  Company and Black  Hills  Power,  Inc.  (filed as
                      Exhibit  10(o) to the  Registrant's  Form 10-K for  1983).
                      Amendment to Agreement for Coal Supply for Wyodak #2 dated
                      May 5, 1987  (filed as Exhibit  10(o) to the  Registrant's
                      Form 10-K for 1987).
         10.7*        Reserve Capacity Integration  Agreement dated May 5, 1987,
                      between  Pacific  Power & Light  Company  and Black  Hills
                      Power,  Inc.  (filed as Exhibit 10(u) to the  Registrant's
                      Form 10-K for 1987).
         10.8*        Marketing, Capacity and Storage Service Agreement between
                      Black Hills Power, Inc. and PacifiCorp dated September 1,
                      1995 (filed as Exhibit 10(ag) to the Registrant's
                      Form 10-K for 1995).
         10.9*        Assignment   of  Mining   Leases  and  Related   Agreement
                      effective   May  27,  1997,   between   Wyodak   Resources
                      Development  Corp. and Kerr-McGee Coal Corporation  (filed
                      as Exhibit 10(u) to the Registrant's Form 10-K for 1997).
         10.10*       Rate Freeze Extension (filed as Exhibit 10(t) to the
                      Registrant's Form 10-K for 1999).
         10.11 +      Amended and Restated Pension Equalization Plan of Black
                      Hills Corporation dated January 6, 2000.
         10.12 +      First Amendment to the Pension Equalization Plan of Black
                      Hills Corporation dated January 30, 2001.
         10.13 +      Black Hills Corporation Nonqualified Deferred Compensation
                      Plan dated June 1, 1999.
         10.14 +      Black Hills Corporation 1999 Stock Option Plan.
         10.15*+      Agreement for Supplemental Pension Benefit for Everett E.
                      Hoyt dated January 20, 1992 (flied as Exhibit 10(gg)
                      to the Registrant's Form 10-K for 1992).
         10.16*+      Change in Control Agreements for various officers (filed
                      as Exhibit 10(af) to the Registrant's Form 10-K for 1995).
         10.17*+      Black  Hills  Corporation  1996 Stock  Option  Plan
                      (filed as Exhibit 10(s) to the Registrant's Form 10-K
                      for 1997).
         10.18*+      Outside Directors Stock Based Compensation Plan (filed as
                      Exhibit 10(t) to the Registration's Form 10-K for 1997).
         10.19*+      Officers Short-Term Incentive Plan (filed as Exhibit 10(s)
                      to the Registrant's Form 10-K for 1999).
         10.20*       Agreement and Plan of Merger, dated as of January 1,
                      2000, among Black Hills Corporation, Black Hills
                      Energy Capital, Inc., Indeck Capital, Inc., Gerald R.
                      Forsythe, Michelle R. Fawcett, Marsha Fournier,
                      Monica Breslow, Melissa S. Forsythe and John W.
                      Salyer, Jr. (Exhibit 2 to Schedule 13D filed on
                      behalf of the former shareholders of Indeck Capital,
                      Inc. consisting of Gerald R. Forsythe, Michelle R.
                      Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                      Forsythe and John W. Salyer, Jr. dated July 7, 2000).
         10.21*       Addendum to the Agreement and Plan of Merger, dated
                      as of April 6, 2000, among Black Hills Corporation,
                      Black Hills Energy Capital, Inc., Indeck Capital,
                      Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                      Fournier, Monica Breslow, Melissa S. Forsythe and
                      John W. Salyer, Jr. (Exhibit 3 to Schedule 13D filed
                      on behalf of the former shareholders of Indeck
                      Capital,consisting of Gerald R. Forsythe, Michelle R.
                      Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                      Forsythe and John W. Salyer, Jr. dated July 7, 2000).
         10.22*       Supplemental Agreement Regarding Contingent Merger
                      Consideration, dated as of January 1, 2000, among
                      Black Hills Corporation, Black Hills Energy Capital,
                      Inc., Indeck Capital, Inc., Gerald R. Forsythe,
                      Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
                      Melissa S. Forsythe and John W. Salyer, Jr. (Exhibit
                      4 to Schedule 13D filed on behalf of the former
                      shareholders of Indeck Capital, Inc. consisting of
                      Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                      Fournier, Monica Breslow, Melissa S. Forsythe and
                      John W. Salyer, Jr. dated July 7, 2000).
         10.23*       Supplemental Agreement Regarding Restructuring of
                      Certain Qualifying Facilities (Exhibit 5 to Schedule
                      13D filed on behalf of the former shareholders of
                      Indeck Capital, Inc. consisting of Gerald R.
                      Forsythe, Michelle R. Fawcett, Marsha Fournier,
                      Monica Breslow, Melissa S. Forsythe and John W.
                      Salyer, Jr. dated July 7, 2000).
         10.24*       Addendum to the Agreement and Plan of Merger, dated
                      as of June 30, 2000, among Black Hills Corporation,
                      Black Hills Energy Capital, Inc., Indeck Capital,
                      Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                      Fournier, Monica Breslow, Melissa S. Forsythe and
                      John W. Salyer, Jr. (Exhibit 6 to Schedule 13D filed
                      on behalf of the former shareholders of Indeck
                      Capital,consisting of Gerald R. Forsythe, Michelle R.
                      Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                      Forsythe and John W. Salyer, Jr. dated July 7, 2000).
         10.25*       Registration Rights Agreement among Black Hills
                      Corporation, Gerald R. Forsythe, Michelle R. Fawcett,
                      Marsha Fournier, Monica Breslow, Melissa S. Forsythe
                      and John W. Salyer, Jr. (Exhibit 7 to Schedule 13D
                      filed on behalf of the former shareholders of Indeck
                      Capital,consisting of Gerald R. Forsythe, Michelle R.
                      Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                      Forsythe and John W. Salyer, Jr. dated July 7, 2000).
         10.26*       Shareholders Agreement among Black Hills Corporation,
                      Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                      Fournier, Monica Breslow, Melissa S. Forsythe
                      and John W. Salyer, Jr. (Exhibit 8 to Schedule 13D
                      filed on behalf of the former shareholders of Indeck
                      Capital,consisting of Gerald R. Forsythe, Michelle R.
                      Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                      Forsythe and John W. Salyer, Jr. dated July 7, 2000).
         21           List of Subsidiaries of Black Hills Corporation.
         23.1         Consent of Independent Public Accountants.
         23.2         Consent of Petroleum Engineer and Geologist.

- ----------
*       Previously filed as part of the filing indicated and incorporated by
        reference herein.
+       Indicates a board of director or management compensatory plan.

                                                                    Exhibit 4.2
Number
NY ____                                                              Shares ___

THIS CERTIFICATE IS TRANSFERABLE IN                           SEE REVERSE FOR
NEW YORK, N.Y. OR MINNEAPOLIS, MN.                          CERTAIN DEFINITIONS

                                  COMMON STOCK

                             BLACK HILLS CORPORATION
                                                          CUSIP   092113  10  9
           (Incorporated Under the Laws of the State of South Dakota)

         This certifies that  __________________  is the owner of _________fully
paid and  non-assessable  shares,  having a par  value of $1 per  share,  of the
common stock of Black Hills  Corporation  (hereinafter  called the Corporation),
transferable  on the books of the  Corporation by the holder hereof in person or
by a duly  authorized  attorney  upon  surrender  of this  certificate  properly
endorsed.  This  certificate  and the shares  represented  hereby are issued and
shall be held subject to all the provisions of the Articles of  Incorporation of
the Corporation and all amendments thereof, copies of which are on file with the
Transfer Agent, to all of which the holder, by acceptance hereof,  assents. This
certificate  is  not  valid  until  countersigned  by  the  Transfer  Agent  and
registered by the Registrar.

         WITNESS,  the facsimile seal of the Corporation,  and the signatures of
its duly authorized officers.

Dated _______________________________

                            -------------------------------------------------
                            Chairman and CEO

                            -------------------------------------------------
                            Vice President-Controller and Corporate Secretary

Countersigned and Registered:

By ___________________________________________
     Transfer Agent and Registrar
     Authorized Signature

                             BLACK HILLS CORPORATION

Notice: The Corporation will furnish to any shareholder upon request and without
charge,  a full statement of the  designations,  preferences,  limitations,  and
relative  rights of the shares of each class of stock  authorized  to be issued,
and a like full statement relative to any preferred or special class of stock in
series which the Corporation is or may be authorized to issue, or has issued, as
to the variations in the relative rights and  preferences  between the shares of
each  such  series so far as the same have  been  fixed and  determined  and the
authority of the Board of Directors to fix and determine the relative rights and
preferences of subsequent series.

         The following  abbreviations,  when used in the inscription on the face
of this certificate,  shall be construed as though they were written out in full
according to applicable laws or regulations:

TEN COM - as tenants in common UNIF GIFT MIN ACT- _____as  Custodian for _______
                                                 (Cust)                  (Minor)
                                                  under Uniform Gifts to Minors
                                                    Act______________________
                                                            (State)
UNIF TRAN MIN ACT - _____ as  Custodian  for  ______
                   (Cust)                     (Minor)
                    under Uniform Transfers to Minors
                        Act _______________________
                                 (State)

TEN ENT - as tenants by the entireties
JT TEN - as joint tenants with right of survivorship
         and not as tenants in common
TOD - transfer on death direction in event of owner's death,
      to person named on face

Additional  abbreviations  may also be used though not in the above list.

     For Value Received, ______________________ hereby sell, assign and transfer
unto  ____________________________Shares  of the Stock represented by the within
certificate    and   do    hereby    irrevocably    constitute    and    appoint
________________________  attorney,  to  transfer  the same on the  books of the
within-named Corporation, with full power of substitution in the premises.

         Dated__________________________

                                            X__________________________________
NOTICE:  THE SIGNATURE(S) TO THIS ASSIGNMENT
MUST CORRESPOND WITH THE NAME(S) AS WRITTEN
UPON THE FACE OF THE CERTIFICATE IN EVERY
PARTICULAR, WITHOUT ALTERATION OR ENLARGEMENT
OR ANY CHANGE WHATEVER.

                                            X__________________________________

                  Signature Guaranteed by   X__________________________________

                                                                 Exhibit 10.11

                            PENSION EQUALIZATION PLAN
                           OF BLACK HILLS CORPORATION

     This Pension  Equalization  Plan ("Plan") is hereby amended and restated by
Black Hills Corporation  ("Company") effective the 6th day of January,  2000.

     1.   PURPOSE OF PLAN.

     The purpose of the Plan is to provide to a select  group of  management  or
highly  compensated  employees  with certain  retirement  and death  benefits in
addition to those benefits which the  Participants  may enjoy from the Company's
tax  qualified  defined  benefit  plan in order  to  equalize  total  retirement
benefits  being  paid to  persons  holding  like  executive  positions  by other
companies.  The Plan is designed to aid the Company in attracting  and retaining
its executive  employees,  persons whose abilities,  experience and judgment can
contribute to the well-being of the Company. It is the intention of Company that
this Plan shall be  administered  as an unfunded  benefit plan  established  and
maintained for a select group of management or highly compensated employees.

     2.   DEFINITIONS.

          "Annual  Compensation  Limitation" shall mean the limitation on annual
          compensation  for tax  qualified  retirement  plans  as set  forth  in
          Internal  Revenue Code Section  401(a)(17)  as the same may be amended
          hereafter from time to time.

          "Average  Earnings"  shall mean whichever of the following  results in
          the highest  annual  average  Earnings:  (i) a  Participant's  average
          Earnings  for  the  five  (5)  consecutive   full  calendar  years  of
          employment  during  the ten (10)  full  calendar  years of  employment
          immediately  preceding  the  Calculation  Date,  which  results in the
          highest  such  average;  or  (ii)  a  Participant's  average  Earnings
          determined  by dividing the sum of the  following by five (5): (a) the
          Participant's  Earnings for the four full calendar years preceding the
          year containing his Calculation Date; (b) the  Participant's  Earnings
          for the year  containing his  Calculation  Date as of the  Calculation
          Date;  and (c) a portion of the  Participant's  Earnings for the fifth
          full calendar year preceding the year containing his Calculation  Date
          determined by multiplying  his Earnings for said fifth  preceding full
          calendar  year by a ratio,  the  numerator of which shall be 365 minus
          the  number  of days  in the  year  containing  his  Calculation  Date
          measured from the first day of said year to his Calculation  Date, and
          the  denominator of which ratio shall be 365. If the  Participant  has
          less than five (5) full  calendar  years of  employment,  the  average
          shall be taken over his total full calendar years of employment.

          "Calculation  Date"  shall  mean  the  earlier  of (i)  the  date  the
          Participant's  employment  with the Company was  terminated,  (ii) the
          date that the Participant's  participation in the Plan was terminated,
          or (iii) the date of the Participant's death.

          "Committee"  shall  mean the  Compensation  Committee  of the Board of
          Directors of the Company.

          "Earnings"  shall mean the  compensation  paid to a Participant by the
          Company  during a calendar  year,  including  any amounts  paid to the
          Participant as overtime,  bonus, commission or incentive compensation,
          any  Earnings  reduction  under a cash or deferred  arrangement  under
          Section  401(k) of the Internal  Revenue  Code,  any salary  reduction
          under a flexible  benefit  program  under  Section 125 of the Internal
          Revenue  Code,  and the  amount of any salary or bonus  deferred  by a
          Participant  under the Company's  Nonqualified  Deferred  Compensation
          Plan, but excluding  reimbursements  and expenses  allowances,  fringe
          benefits,   moving  expenses,   nonqualified   deferred   compensation
          payments, and welfare benefits.

          "Pension  Restoration  Benefit"  shall mean the benefit  payable under
          paragraph 8.

          "PEP Benefits" shall mean the benefits payable under paragraph 4.

          "Salary Level" shall mean the base  compensation paid to a Participant
          by the Company  during a calendar  year,  including  any  compensation
          reduction under a cash or deferred arrangement under Section 401(k) of
          the Internal  Revenue Code or under a flexible  benefit  program under
          Section 125 of the Internal Revenue Code and any salary deferrals made
          by  a   Participant   under  the   Company's   Nonqualified   Deferred
          Compensation   Plan,  but  not  including  any  amounts  paid  to  the
          Participant as overtime,  bonus, commission or incentive compensation,
          nor reimbursements  and expense  allowances,  fringe benefits,  moving
          expenses,  nonqualified  deferred  compensation  payments,  or welfare
          benefits.

          "Social  Security  Wage  Base"  shall  mean the  contribution  base as
          determined under Section 1402(k)(1) of the Internal Revenue Code.

         3.       PARTICIPANTS.

         Those persons eligible for  participation in the Plan  ("Participants")
are those  management  employees  of the Company  whose  Salary  Level equals or
exceeds the Social  Security  Wage Base and who are  designated  by the Board of
Directors of the Company upon  recommendation  of the Chief Executive Officer of
the  Company.  The Board of  Directors  may in its  discretion  discontinue  the
participation of any Participant in the Plan at any time.

         4.       PEP BENEFITS.

         Benefits payable to Participants  ("PEP Benefits") shall consist of 180
equal monthly payments, each payment in the amount of one-twelfth of the product
of (i) the  Participant's  Average  Earnings  as of the  Calculation  Date times
(ii)(a) 25 percent if the  Participant's  Average Earnings as of the Calculation
Date is less than twice the Social  Security Wage Base; or (b) 30 percent if the
Participant's  Average Earnings equals or exceeds twice the Social Security Wage
Base; times (iii) the applicable vesting percentages provided in paragraph 7.

         5.       COMMENCEMENT OF PAYMENT OF PEP BENEFITS.
         PEP Benefit  payments  shall be paid  commencing at the earliest of (i)
the time the Participant is 62 years of age or more and is no longer an employee
of the Company; or (ii) upon the death of the Participant. PEP Benefits shall be
paid  to the  Participant  or,  if  deceased,  to the  Participant's  designated
beneficiary,  or, if none,  to his or her  estate.  If the  Participant's  death
occurs after  commencement of PEP Benefit payments to the Participant  under the
Plan,  the  Participant's  designated  beneficiary  or estate  will  continue to
receive the balance of the payments due the Participant under the Plan.

         6.       DESIGNATION OF BENEFICIARY.
         A  Participant  may designate a beneficiary  or  beneficiaries  for PEP
Benefits   which  shall  be  effective  upon  filing  written  notice  with  the
Compensation  Committee of the Company on the form provided for that purpose. If
more  than one  beneficiary  designation  has been  filed,  the  beneficiary  or
beneficiaries  designated  in the notice  bearing  the most  recent date will be
deemed the valid beneficiary or beneficiaries.

         7.       VESTING OF PEP BENEFITS.
         PEP Benefits payable under the Plan will vest at the following rate:

                   Years of Plan Participation                                        Percent of Benefit
                   ---------------------------                                              Vested
                                                                                            ------
                                                                                          
         Less than 3 years                                                                    0
         3 years but less than 4                                                             20
         4 years but less than 5                                                             35
         5 years but less than 6                                                             50
         6 years but less than 7                                                             65
         7 years but less than 8                                                             80
         8 or more years                                                                    100

         No credit for service with the Company prior to the  effective  date of
the Plan shall be given.  The provisions for vesting set forth in this paragraph
are not  intended to give any  Participants  any rights or claim to any specific
assets of the Company.

         8.       PENSION RESTORATION BENEFITS.
         In the event that at the time of a  Participant's  retirement  from the
Company  the  Participant's   salary  level  exceeds  the  Annual   Compensation
Limitation,  then, the Participant shall receive an additional benefit ("Pension
Restoration  Benefit")  which shall be measured  by the  difference  between the
monthly  benefit  which would have been  provided to the  Participant  under the
Company's tax qualified  defined benefit plan ("Pension  Plan") as if there were
no Annual Compensation  Limitation and the monthly benefit to be provided to the
Participant  under the Pension Plan.  The Pension  Restoration  Benefit shall be
determined  using  the  same  factors,   actuarial  or  otherwise,  as  used  in
determining the Participant's  Pension Plan benefit and shall be payable at like
times and manner as the Pension Plan benefit.

         In addition to the above benefit,  in the event that any  Participant's
deferral  of  salaries  or  bonus  under  the  Company's  Nonqualified  Deferred
Compensation Plan results in a reduction of that Participant's  benefits payable
under the Company's  Pension  Plan,  then the  Participant  shall be entitled to
payment of an additional  Pension  Restoration  Benefit which shall be a monthly
benefit which shall consist of the  difference  between (i) the monthly  benefit
which would have been provided to the  Participant  under the Pension Plan as if
the Participant had made no deferrals under the Company's  Nonqualified Deferred
Compensation Plan and (ii) the monthly benefit to be provided to the Participant
under the Pension Plan,  said benefit to be  determined  using the same factors,
actuarial or otherwise,  as used in determining the  Participant's  Pension Plan
benefit and to be payable at like times and manner as the Pension Plan benefit.

         9.       LOSS OF BENEFITS.
         Notwithstanding  any other provisions in this Plan, if a Participant is
terminated on account of misconduct or dishonesty, the Participant shall forfeit
all right to any benefits  payable  under this Plan,  including  vested  accrued
benefits.

         10.      FUNDING OF PLAN.
         All  benefit  payments  under the Plan  will be made  from the  general
assets of the Company.  Participants and their beneficiaries who are entitled to
be paid benefits under this Plan are unsecured general creditors of the Company.
The Company may, but shall not be required to, invest  corporate  assets in life
insurance or annuity  contracts to assure that the Company will have a source of
funds for the payment of benefits  required to be paid under this Plan. Any such
insurance or annuity  contract  shall  constitute  assets of the Company and the
employee shall have no right, title or interest in any such insurance or annuity
contract.  The Company reserves the right to refuse participation in the plan to
any Participant who, if requested to do so, declines to supply information or to
otherwise cooperate as necessary to allow the Company to obtain insurance on the
Participant's life.

         11.      PLAN MAY BE MODIFIED OR DISCONTINUED.
         The Company reserves the right to amend, modify or discontinue the Plan
at any time. Any  modification  or  discontinuance  of benefits shall not reduce
accrued benefits which become vested prior thereto.

         12.      WITHHOLDING.
         There  shall be  deducted  from all  benefits  paid under this Plan the
amount of any taxes  required  to be  withheld  by any  federal,  state or local
government. The Participants and their beneficiaries,  distributees and personal
representatives  will bear any and all federal,  foreign,  state, local or other
income or other taxes imposed on amounts paid under this Plan.

         13.      ASSIGNABILITY.
         No right to  receive  payments  under  this Plan  shall be  subject  to
voluntary or involuntary alienation, assignment or transfer.

         14.      ADMINISTRATION OF THE PLAN.
         The Plan shall be  administered  by the Committee.  The Committee shall
conclusively  interpret the provisions of the Plan, decide all claims, and shall
make all  determinations  under the  Plan.  The  Committee  shall act by vote or
written consent of a majority of its members.

         15.      CLAIMS PROCEDURE.
         All claims for benefits  under the Plan shall be made to the Committee.
If the  Committee  denies a claim,  the  Committee  may  provide  notice  to the
Participant or beneficiary,  in writing, within 90 days after the claim is filed
unless  special  circumstances  require an extension of time for  processing the
claim, not to exceed an additional 90 days. If the Committee does not notify the
Participant  or  beneficiary  of the denial of the claim  within the time period
specified above,  then the claim shall be deemed denied.  The notice of a denial
of a claim  shall be  written in a manner  calculated  to be  understood  by the
claimant  and shall set forth (1)  specific  references  to the  pertinent  Plan
provisions  on which the denial is based;  (2) a description  of any  additional
material or  information  necessary for the claimant to perfect the claim and an
explanation as to why such  information is necessary;  and (3) an explanation of
the Plan's claim procedure.
         Within 60 days after receipt of the above material,  the claimant shall
have a reasonable  opportunity to appeal the claim denial to the Committee for a
full and fair review. The claimant or his duly authorized representative may (1)
request a review upon  written  notice to the  Committee;  (2) review  pertinent
documents; and (3) submit issues and comments in writing.
         A decision on the review by the  Committee  will be made not later than
60 days after  receipt of a request for  review,  unless  special  circumstances
require  an  extension  of  time  for  processing  (such  as the  need to hold a
hearing),  in which case a decision  shall be rendered as soon as possible,  but
not later than 120 days after  receipt of a request for review.  The decision on
review shall be in writing and shall include  specific reasons for the decision,
written in a manner  calculated to be  understood  by the  claimant,  as well as
specific  references to the pertinent  Plan  provisions on which the decision is
based.

         16.      GOVERNING LAW.
         This  agreement  shall be governed by and construed in accordance  with
the laws of the state of South Dakota.

         17.      NO EMPLOYMENT CONTRACT.
         Neither the action taken by the Company in establishing the Plan or any
action  taken by it or by the  Committee  under  the  provisions  hereof  or any
provision of the Plan shall be  construed as giving to any eligible  Participant
the right to be retained in the employment of the Company.

         18.      NONQUALIFIED PLAN.
         This Plan is not intended to be a tax qualified plan under the Internal
Revenue Code.

                                               BLACK HILLS CORPORATION

                                               By /s/ Daniel P. Landguth
                                               Its Chairman and CEO

                                                                 Exhibit 10.12
                                 FIRST AMENDMENT
                                     TO THE
                            PENSION EQUALIZATION PLAN
                           OF BLACK HILLS CORPORATION

The Pension  Equalization  Plan of Black  Hills  Corporation  is hereby  amended
effective the 30th day of January, 2001.

1.       Add to paragraph 2, Definitions, the following definition:

         "Section  415  Benefit  Limitation"  shall mean the  limitation  on the
         provision of annual  benefits with respect to defined  benefit plans as
         set forth in Internal  Revenue Code  Section  415(b) as the same may be
         amended hereafter from time to time.

2.       Paragraph  8,  Pension  Restoration  Benefits  of the  Plan,  shall be
         amended to read as follows:

         In the event  that a  Participant's  benefit  under the  Company's  tax
         qualified  defined  benefit  plan  ("Pension  Plan") is reduced,  or is
         required  to  be  reduced,  because  of  (i)  the  Annual  Compensation
         Limitation;  (ii) the  Section  415  Benefit  Limitation;  or (iii) the
         Participant's  deferral  of  salaries  or  bonus  under  the  Company's
         Nonqualified Deferred Compensation Plan, then, the Participant shall be
         entitled  to  receive  an  additional  benefit  ("Pension   Restoration
         Benefit"),  which shall be measured by the  difference  between (x) the
         monthly benefit which would have been provided to the Participant under
         the Pension  Plan without  regard to the  reduction in the Pension Plan
         benefit  caused by any of the foregoing  limitations  in (i),  (ii), or
         (iii)  above,  and  (y)  the  monthly  benefit  to be  provided  to the
         Participant  under the Pension Plan.  The Pension  Restoration  Benefit
         shall be determined using the same factors,  actuarial or otherwise, as
         used in determining the Participant's Pension Plan benefit and shall be
         payable at like times and manner as the Pension Plan benefit.

                                                     BLACK HILLS CORPORATION

                                                     By /s/ Daniel P. Landguth
                                                     Its Chairman & CEO
                                                                  Exhibit 10.13

                             BLACK HILLS CORPORATION
                     NONQUALIFIED DEFERRED COMPENSATION PLAN

         1. Purpose of Plan and Effective Date. The effective date of this Black
Hills Corporation  Nonqualified Deferred Compensation Plan ("Plan") shall be the
1st day of June,  1999.  The  purpose  of the Plan is to provide  benefits  to a
select  group of  management  or highly  compensated  employees  who  contribute
materially to the continued  growth,  development and future business success of
the Company. It is the intention of Company that this Plan shall be administered
as an unfunded  benefit plan  established  and  maintained for a select group of
management or highly compensated employees.

         2.  Definitions.  For purposes of this Plan,  the following  phrases or
terms have the indicated  meanings unless  otherwise  clearly  apparent from the
context:

                  (a)      "Beneficiary"  shall  mean the  person,  persons,  or
                           estate of a  Participant,  entitled  to  receive  any
                           benefits  subsequent  to the  death of a  Participant
                           under a Beneficiary  Designation form entered into in
                           accordance with the terms of this Plan.

                  (b)      "Base Salary" shall mean the  compensation  paid to a
                           Participant  by the Employer  during a calendar year,
                           including any compensation  reduction under a cash or
                           deferred  arrangement  under  Section  401(k)  of the
                           Internal  Revenue  Code or under a  flexible  benefit
                           program  under  Section 125 of the  Internal  Revenue
                           Code  but  not  including  any  amounts  paid  to the
                           Participant  as  overtime,   bonus,  commission,   or
                           incentive   compensation,   nor   reimbursements  and
                           expense allowances, fringe benefits, moving expenses,
                           nonqualified   deferred   compensation,   or  welfare
                           benefits.

                  (c)      "Beneficiary  Designation"  shall  mean  the  form of
                           written agreement, by which the Participant names the
                           Beneficiary(ies) under the Plan.

                  (d)      "Board  of   Directors"   shall  mean  the  Board  of
                           Directors of Company.

                  (e)      "Change in Control"  shall mean any of the  following
                           events:

                           (1)      An acquisition (other than directly from the
                                    Company) of any common  stock of the Company
                                    (the "Common Stock") by any "Person" (as the
                                    term person is used for  purposes of Section
                                    13(d) or 14(d)  of the  Securities  Exchange
                                    Act  of  1934,  as  amended  (the  "Exchange
                                    Act"),  immediately  after which such Person
                                    has  "Beneficial   Ownership"   (within  the
                                    meaning of Rule 13d-3  promulgated under the
                                    Exchange  Act) of  thirty  percent  (30%) or
                                    more of the  Common  Stock  of the  Company;
                                    provided,  however, in determining whether a
                                    Change in Control has occurred, Common Stock
                                    which   is   acquired   in   a   "Noncontrol
                                    Acquisition" (as hereinafter  defined) shall
                                    not  constitute an  acquisition  which would
                                    cause a Change  in  Control.  A  "Noncontrol
                                    Acquisition"  shall mean an  acquisition  by
                                    (i) an  employee  benefit  plan  (or a trust
                                    forming a part  thereof)  maintained  by (A)
                                    the Company or (B) any  corporation or other
                                    Person  of which a  majority  of its  voting
                                    power  or  its  voting   equity   securities
                                    ("Voting  Securities") or equity interest is
                                    owned,   directly  or  indirectly,   by  the
                                    Company (for purposes of this definition,  a
                                    "Subsidiary"),   (ii)  the  Company  or  its
                                    Subsidiaries,   or  (iii)   any   Person  in
                                    connection  with a "Noncontrol  Transaction"
                                    (as hereinafter defined);

                           (2)      The individuals  who, as of January 1, 1997,
                                    are  members  of the Board  (the  "Incumbent
                                    Board"),  cease for any reason to constitute
                                    at least  two-thirds  of the  members of the
                                    Board;   provided,   however,  that  if  the
                                    election,  or nomination for election by the
                                    Company's  common  shareholders,  of any new
                                    director  was approved by a vote of at least
                                    two-thirds of the Incumbent Board,  such new
                                    director  shall,  for purposes of this Plan,
                                    be  considered  as a member of the Incumbent
                                    Board;  provided further,  however,  that no
                                    individual  shall be  considered a member of
                                    the  Incumbent   Board  if  such  individual
                                    initially  assumed  office  as a  result  of
                                    either  an actual  or  threatened  "Election
                                    Contest"   (as   described  in  Rule  14a-11
                                    promulgated under the Exchange Act) or other
                                    actual or threatened solicitation of proxies
                                    or  consents  by or on  behalf  of a  Person
                                    other  than the  Board (a  "Proxy  Contest")
                                    including   by  reason   of  any   agreement
                                    intended  to avoid or  settle  any  Election
                                    Contest or Proxy Contest; or

                           (3)      Approval by shareholders of the Company of:

                                    (i)     A    merger,     consolidation    or
                                            reorganization     involving     the
                                            Company,    unless   such    merger,
                                            consolidation or reorganization is a
                                            "Noncontrol      Transaction."     A
                                            "Noncontrol  Transaction" shall mean
                                            a    merger,     consolidation    or
                                            reorganization of the Company where:

                                            (A)      the   shareholders  of  the
                                                     Company, immediately before
                                                     such merger,  consolidation
                                                     or   reorganization,    own
                                                     directly   or    indirectly
                                                     immediately  following such
                                                     merger,   consolidation  or
                                                     reorganization,   at  least
                                                     seventy  percent  (70%)  of
                                                     the  combined  voting power
                                                     of the  outstanding  Voting
                                                     Securities      of      the
                                                     corporation  resulting from
                                                     such        merger       or
                                                     consolidation            or
                                                     reorganization         (the
                                                     "Surviving Corporation") in
                                                     substantially    the   same
                                                     proportion     as     their
                                                     ownership   of  the  Voting
                                                     Securities      immediately
                                                     before     such     merger,
                                                     consolidation            or
                                                     reorganization.

                                            (B)      the  individuals  who  were
                                                     members  of  the  Incumbent
                                                     Board  immediately prior to
                                                     the    execution   of   the
                                                     agreement   providing   for
                                                     such merger,  consolidation
                                                     or           reorganization
                                                     constitute     at     least
                                                     two-thirds  of the  members
                                                     of the  board of  directors
                                                     of      the       Surviving
                                                     Corporation,      or      a
                                                     corporation    beneficially
                                                     directly   or    indirectly
                                                     owning  a  majority  of the
                                                     Voting  Securities  of  the
                                                     Surviving Corporation, and

                                            (C)      no  Person  other  than (i)
                                                     the   Company,   (ii)   any
                                                     Subsidiary,    (iii)    any
                                                     employee  benefit  plan (or
                                                     any  trust  forming  a part
                                                     thereof)  maintained by the
                                                     Company,    the   Surviving
                                                     Corporation,     or     any
                                                     Subsidiary,   or  (iv)  any
                                                     Person   who,   immediately
                                                     prior   to   such   merger,
                                                     consolidation            or
                                                     reorganization          had
                                                     Beneficial   Ownership   of
                                                     thirty   percent  (30%)  or
                                                     more     of    the     then
                                                     outstanding          Voting
                                                     Securities), has Beneficial
                                                     Ownership of thirty percent
                                                     (30%)   or   more   of  the
                                                     combined  voting  power  of
                                                     the Surviving Corporation's
                                                     then   outstanding   Voting
                                                     Securities.

                                    (ii) A complete  liquidation  or dissolution
                                         of the Company; or

                                    (iii)   An  agreement  for the sale or other
                                            disposition of all or  substantially
                                            all of the assets of the  Company to
                                            any Person other than (x) a transfer
                                            to a  Subsidiary  or (y) a  sale  or
                                            transfer  of  a  Subsidiary  by  the
                                            Company   except  if  such  sale  or
                                            transfer  would  be a sale or  other
                                            disposition of all or  substantially
                                            all of the assets of the Company.

                           (4)      Notwithstanding the foregoing,  (i) a Change
                                    in  Control  shall  not be  deemed  to occur
                                    solely  because  any  Person  (the  "Subject
                                    Person")  acquired  Beneficial  Ownership of
                                    more than the  permitted  amount of the then
                                    outstanding  Common Stock as a result of the
                                    acquisition  of Common  Stock by the Company
                                    which,  by reducing  the number of shares of
                                    Common Stock then outstanding, increases the
                                    proportional  number of shares  Beneficially
                                    Owned by the Subject Persons,  provided that
                                    if a Change in Control  would occur (but for
                                    the operation of this  sentence) as a result
                                    of the  acquisition  of Common  Stock by the
                                    Company, and after such stock acquisition by
                                    the Company,  the Subject Person becomes the
                                    Beneficial  Owner of any  additional  Common
                                    Stock which  increases the percentage of the
                                    then outstanding  Common Stock  Beneficially
                                    Owned by the Subject  Person,  then a Change
                                    in Control shall occur; and (ii) a Change in
                                    Control  shall not be deemed to occur unless
                                    and until all regulatory  approvals required
                                    to effect a Change in Control of the Company
                                    have been obtained.

               (f)  "Committee"  shall mean the  Compensation  Committee  of the
                    Board of Directors.

               (g)  "Company" shall mean Black Hills Corporation, a South Dakota
                    corporation,  with  principal  offices in the State of South
                    Dakota.

               (h)  "Elective  Contribution"  means that part of a Participant's
                    compensation  that such  Participant  has  elected  to defer
                    pursuant to Section 4.1.

               (i)  "Incentive   Contribution"   means   that   portion   of   a
                    Participant's  award under the  Company's  Short Term Annual
                    Incentive Plan ("STIP") which the Participant has elected to
                    defer under the STIP and under Section 4.2.

               (j)  "Employer"  shall mean the Company and any  Subsidiary  that
                    duly adopts the Plan.

               (k)  "Employee"  shall  mean  any  person  who is in the  regular
                    full-time  employment  of the  Company or a  Subsidiary,  as
                    determined  by the  personnel  rules  and  practices  of the
                    Company or a Subsidiary.  The term does not include  persons
                    who are  retained by the Company or a  Subsidiary  solely as
                    consultants.

               (l)  "Participant"  shall mean an  Employee  who is  selected  to
                    participate in the Plan.

               (m)  "Participant's  Account" shall mean the  memorandum  account
                    established   and   maintained   by  the  Company  for  each
                    Participant with respect to the Participant's total interest
                    in  the  Plan  resulting  from  the  Participant's  Elective
                    Contributions and Incentive  Contributions plus the earnings
                    thereon.

               (n)  "Plan  Year"  shall  mean the Plan's  accounting  year of 12
                    months  beginning  on January 1 and ending on the  following
                    December 31.

               (o)  "Retirement" and "Retire" shall mean severance of employment
                    with Employer, for any reason.

               (p)  "Subsidiary"  shall mean any business  organization in which
                    Company,  directly  or  indirectly,  owns a majority  of its
                    voting power or voting equity  securities or equity interest
                    and which the Board of Directors  designates as a Subsidiary
                    for purposes of this Plan.

         3.  Eligibility  and  Participation.   In  order  to  be  eligible  for
participation  in the Plan, an Employee must be selected by the  Committee.  The
Committee, in its sole and absolute discretion,  shall determine eligibility for
participation  from among  management  or highly  compensated  employees  of the
Employer in accordance with the purposes of the Plan.

         4.       Contributions.

                  4.1  Elective  Contributions.  Each  Participant  may elect to
defer up to 50% of the  Participant's  Base Salary. An election to defer must be
made in writing prior to the beginning of a Plan Year; provided, that (a) in the
Plan  Year in which the Plan is first  implemented,  a  Participant  may make an
election to defer compensation  earned subsequent to the election within 30 days
after  the date  the  Plan is  effective  and (b) in the  first  year in which a
Participant  becomes  eligible to  participate  in the Plan,  the newly eligible
Participant may make an election to defer compensation  earned subsequent to the
election within 30 days after the date the Participant  becomes  eligible.  This
election shall be irrevocable  for that Plan Year and shall continue to be valid
unless  subsequently  revoked for the following Plan Years.  The amount by which
the Participant's  Base Salary is reduced shall be that  Participant's  Elective
Contribution and shall be allocated to that  Participant's  Account on a monthly
basis.

                  4.2  Incentive  Contributions.  In  addition  to the  Elective
Contributions,  a  Participant,  if eligible under the STIP, may elect under the
terms of the  Company's  STIP,  to defer the  receipt of all or any portion of a
Participant's award thereunder, including shares of Company stock. The amount of
the award deferred under the STIP shall be allocated to a Participant's Account.
In the event that  Participant  defers a stock  award  under the STIP,  then the
Company  shall  establish  within  the  Participant's  Account  a  common  stock
equivalent  memorandum  account  ("Stock  Account")  and shall  credit the Stock
Account with Company common stock equivalents, including fractional equivalents.
Appropriate  adjustments  shall be made to the Stock  Account for stock  splits,
stock  dividends,   mergers,   consolidation  and  other  similar  circumstances
affecting the Company common stock.

         5. Earnings on Participant's Account. Each Participant may, at the time
of  his   deferral   election,   choose  to  allocate  the  amount  of  Elective
Contributions  deferred and the amount of the Incentive  Contributions  deferred
(except for the Company stock deferred) into certain  categories of hypothetical
investments to be determined by the Participant as are available under the range
of  investments  as may be allowed by any  third-party  service  provider to the
Plan,  or  trustee,  if any,  or if none,  from  the  range  of  investments  as
determined  by the  Committee in its  discretion.  The amounts  deferred  into a
Participant's  Account shall change in value based upon the allocated underlying
hypothetical investments, including Company Stock.

         6. Payment of Benefit.  Upon Retirement of a Participant,  the Employer
shall  pay to or cause to be paid to such  Participant  the then  amount  in the
Participant's Account. At the time that a Participant makes a deferral election,
the Participant shall choose from the following payment options:  (a) a lump sum
payment  to be paid  within 30 days of  Retirement,  or (b)  annual  or  monthly
installment  payments  over a period of years  designated by Employee but not to
exceed 15 years.  Once payments  hereunder have begun, the payment option chosen
is irrevocable. In the event that a Participant has elected a payment option and
desires to change the same prior to such payment  option  becoming  irrevocable,
Participant  may make a request of the  Committee to change the payment  option;
provided,  that such  request  shall not  become  effective  until the Plan Year
subsequent to the Plan Year in which the request is made.

         If the installment payment is elected,  the first payment shall be made
in cash to  Employee  on the 1st day of  January  following  the  date on  which
Employee  Retires.  Annual  payments for each  succeeding  year shall be paid to
Employee on the first January of each succeeding year. Monthly payments shall be
made on the  first  day of  each  month.  Subsequent  to the  first  installment
payment,  accrued  interest on the unpaid  accumulated  balance will be added to
each  subsequent  payment based on  amortization  over the term of payment.  The
interest rate to be used shall be equal to the seven year United States Treasury
Bond yield as determined on the Retirement date.

         In the event of  Employee's  death after  Retirement,  and in the event
installment  payments had been elected,  the payments  shall be made as provided
herein on each payment date established and shall continue until paid in full to
Participant's Beneficiary; provided, however, that Participant's Beneficiary, or
personal  representative,  as the case may be, shall have the option, by written
notice given to Company within 12 months after  Participant's  death, to receive
any remaining  installment  payments in a lump sum. If such option is exercised,
the lump sum shall be paid within 60 days thereafter.

         7. Payment of Benefits upon  Unforeseeable  Emergency.  Notwithstanding
paragraph  6 above,  in the event of an  Unforeseeable  Emergency  as  hereafter
defined,  a Participant may withdraw amounts from the  Participant's  Account to
the  extent  reasonably  needed  to  satisfy  the  Unforeseeable  Emergency.  In
addition,  in the event of an  Unforeseeable  Emergency,  Participant  may cease
contributions during a Plan Year  notwithstanding  Section 4.1. For the purposes
of this paragraph an "Unforeseeable Emergency" is a severe financial hardship to
the  Participant  resulting from a sudden and unexpected  illness or accident of
the Participant or a dependent (as defined in Internal  Revenue Code ss. 152(a))
of the Participant, loss of the Participant's property due to casualty, or other
similar  extraordinary  and unforeseeable  circumstances  arising as a result of
events  beyond  the  control of the  Participant.  The  circumstances  that will
constitute an  Unforeseeable  Emergency will depend upon the facts of each case,
but, in any case, payment may not be made to the extent that such hardship is or
may be  relieved--(a)  through  reimbursement  or  compensation  by insurance or
otherwise;  (b) by liquidation of the  Participant's  assets,  to the extent the
liquidation of such assets would not itself cause severe financial hardship;  or
(c) by  cessation  of  Contributions  under the Plan.  Examples  of what are not
considered  to  be an  Unforeseeable  Emergency  include  the  need  to  send  a
Participant's child to college or the desire to purchase a home.

         8.       Death Benefit and Disability Benefits.

                  8.1 Amount and Payment of Death Benefit. If a Participant dies
before Retirement,  the Employer will pay or cause to be paid as a death benefit
to such Participant's Beneficiary the balance of the Participant's Account, in a
lump sum.

         Proof of death in a form determined acceptable by the Committee must be
furnished.

                  8.2 Total  Disability.  If a Participant  becomes  totally and
permanently disabled before he or she ceases to be employed by the Employer, the
balance of the Participant's Account shall be paid in a lump sum; provided, that
the Committee, in its sole discretion, may pay out Participant's Account balance
in installments.

         The  determination  of total and permanent  disability  for purposes of
this  section,  shall  be  made  by the  Committee  in  its  sole  and  absolute
discretion.

                  8.3 Time of  Payment.  The benefit  paid under  Section 8.1 or
Section 8.2 shall be paid as soon as possible following the Participant's  death
or the date on which the  Committee  determines  a  Participant  is  totally  or
permanently disabled but not later than 12 months following  Participant's death
or determination of total or permanent disability.

         9.  Change  in  Control.  In  the  event  of a  Change  in  Control,  a
Participant  shall  have the  option to request  immediate  distribution  of the
Participant's   Account  as  if   Participant   had  Retired,   whether  or  not
Participant's  employment  status with  Company or any  successor of Company has
changed.

          10.   Beneficiary.   Participant  shall  designate  a  Beneficiary  or
Beneficiaries  to receive  benefits under the Plan by completing the Beneficiary
Designation.  If more than one Beneficiary is named, the shares or precedence of
each  Beneficiary  shall be  indicated.  A  Participant  shall have the right to
change  the  Beneficiary  by  submitting  to  the  Committee  a new  Beneficiary
Designation.  The  Beneficiary  Designation  must be  approved in writing by the
Committee;  however,  upon  the  Committee's  acknowledgment  of  approval,  the
effective date of the Beneficiary  Designation shall be the date it was executed
by the Participant.  If the Committee has any doubt as to the proper Beneficiary
to receive  payments,  it shall have the right to  withhold  payments  until the
matter is finally adjudicated or to interplead the Participant's  Account into a
court of competent jurisdiction.  Any payment made by the Employer in good faith
and  in  accordance  with  the  provisions  of  this  Plan  and a  Participant's
Beneficiary  Designation  shall fully  discharge the Employer and Committee from
all further obligations with respect to the payment.

         11.      Source of Benefits.

                  11.1 Benefits  Payable from General  Assets.  Amounts  payable
shall be paid exclusively from the general assets of the Employer, and no person
entitled to payment shall have any claim,  right,  security  interest,  or other
interest in any fund, trust, account, or other asset of the Employer that may be
looked to for  payment.  The  Employer's  liability  for the payment of benefits
shall be  evidenced  only by this Plan.  In all events,  it is the intent of the
Employer  that the Plan be treated as unfunded for tax purposes and for purposes
of Title I of ERISA.

                  11.2 Investments to Facilitate  Payment of Benefits.  Although
the Employer is not  obligated to invest in any specific  asset or fund in order
to provide the means for the  payment of any  liabilities  under this Plan,  the
Employer  may  elect  to do so and may  also  elect to  acquire  life  insurance
policies on any Participant or create a "Rabbi" trust.

         The Participant also  understands and agrees that the  participation of
Participant, in any way, in the acquisition of any insurance policy or any other
general  asset by the  Employer  shall not  constitute a  representation  to the
Employee, the designated recipient,  or any person claiming through the Employee
that any of them has a special or beneficial interest in the general asset.

                  11.3  Employer   Obligation.   The  Employer   shall  have  no
obligation of any nature  whatsoever to a Participant under this Plan other than
what is specifically stated in the Plan.

         12. Termination of Employment. This Plan does not obligate the Employer
to continue the employment of a Participant  with the Employer nor does it limit
the  right of the  Employer  at any time and for any  reason  to  terminate  the
Participant's  employment.  Termination of a  Participant's  employment with the
Employer for any reason,  whether by action of the Employer or otherwise,  shall
immediately terminate a Participant's  continued  participation in this Plan. In
no event shall this Plan by its terms or  implications  constitute an employment
contract of any nature whatsoever between the Employer and a Participant.

         13.      Terminations, Amendments, Modification or Supplement of Plan.

                  13.1 Termination,  Amendment and  Modifications.  The Employer
reserves the right to terminate,  amend,  modify or supplement this Plan, wholly
or  partially,  and from time to time,  at any time.  Such  right to  terminate,
amend,  modify,  or supplement  this Plan shall be exercised for the Employer by
the Board of Directors; provided, however, that no action to terminate this Plan
shall be taken except upon written  notice to each  Participant  to be affected,
which  notice  shall be given not less  than 30 days  prior to the  action.  Any
action under this Section 14.1 shall not affect rights previously  accrued under
this Plan.

                  13.2  Rights  and  Obligations  Upon  Termination.   Upon  the
termination of this Plan by the Board of Directors,  the  Participant's  Account
shall  be paid as if the  Participant  had  Retired  as of the date the Plan was
terminated.

         14.  Other  Benefits  and  Agreements.  The  benefits  provided  for  a
Participant and any Beneficiary hereunder and under this Plan are in addition to
any other benefits available to such Participant under any other program or plan
of the Employer for its  employees,  and,  except as may  otherwise be expressly
provided for, this Plan shall  supplement  and shall not supersede,  modify,  or
amend any other program or plan of the Employer or a Participant.

         15.  Restrictions on Alienation of Benefits.  No right or benefit under
this Plan shall be subject to sale, assignment, or encumbrances, and any attempt
to sell,  assign,  or  encumber  the Plan  shall  be void.  No right or  benefit
hereunder  shall in any manner be liable for or subject to the debts,  contract,
liabilities, or torts of the person entitled to such benefit. If any Participant
or  Beneficiary  under  this Plan  should  become  bankrupt  or attempt to sell,
assign,  or encumber  any right to a benefit  under this Plan then such right or
benefit  shall,  in the  discretion of the  Committee,  terminate,  and, in that
event,  the  Committee  shall  hold or apply  the same or any part of it for the
benefit  of  the  Participant  or  Beneficiary,  or  the  Participant's  spouse,
children, or other dependents,  in a manner and in a portion that the Committee,
in its sole and absolute discretion, may deem proper.

         16.  Withholding.  There shall be deducted from all benefits paid under
this Plan the amount of any taxes required to be withheld by any federal,  state
or local government.  The Participants and their Beneficiaries will bear any and
all federal,  foreign,  state,  local or other income or other taxes  imposed on
amounts paid under this Plan.

         17. Administration of this Plan.

                  17.1 Appointment of Committee.  The general  administration of
this Plan, as well as its  construction and  interpretation,  shall be vested in
the  Committee  or its  successor,  as the members of which are  designated  and
appointed from time to time by the Board of Directors.

                  17.2  Committee  Rules and Powers --  General.  Subject to the
provisions of this Plan, the Committee shall from time to time establish  rules,
forms,  and  procedures for the  administration  of this Plan.  Such  decisions,
actions and records of the Committee  shall be  conclusive  and binding upon the
Employer and all persons  having or claiming to have any right or interest in or
under the Plan.

                  17.3  Reliance  on  Certificate,   Etc.  The  members  of  the
Committee  and the officers and  directors of the Employer  shall be entitled to
rely on all certificates and reports made by any duly appointed accountants, and
on all opinions  given by any duly appointed  legal counsel.  Such legal counsel
may be counsel for the Employer.

                  17.4  Determination  of  Benefits.  In  addition to the powers
specified,  the Committee shall have the power to compute and certify under this
Plan the amount and kind of benefits  from time to time payable to  Participants
and their Beneficiaries and to authorize all disbursements for such purposes.

                  17.5  Information  to  Committee.  To enable the  Committee to
perform its functions,  the Employer shall supply full and timely information to
the Committee on all matters relating to the  compensation of all  Participants,
their retirement,  death or other cause for termination of employment,  and such
other pertinent facts as the Committee may require.

         18. Claims. All claims for benefits under the Plan shall be made to the
Committee.  If the Committee denies a claim, the Committee may provide notice to
the  Participant or beneficiary,  in writing,  within 90 days after the claim is
filed unless special  circumstances  require an extension of time for processing
the claim, not to exceed an additional 90 days. If the Committee does not notify
the Participant or Beneficiary of the denial of the claim within the time period
specified above,  then the claim shall be deemed denied.  The notice of a denial
of a claim  shall be  written in a manner  calculated  to be  understood  by the
claimant  and shall set forth (1)  specific  references  to the  pertinent  Plan
provisions  on which the denial is based;  (2) a description  of any  additional
material or  information  necessary for the claimant to perfect the claim and an
explanation as to why such  information is necessary;  and (3) an explanation of
the Plan's claim procedure.

         Within 60 days after receipt of the above material,  the claimant shall
have a reasonable  opportunity to appeal the claim denial to the Committee for a
full and fair review. The claimant or his duly authorized representative may (1)
request a review upon  written  notice to the  Committee;  (2) review  pertinent
documents; and (3) submit issues and comments in writing.

         A decision on the review by the  Committee  will be made not later than
60 days after  receipt of a request for  review,  unless  special  circumstances
require  an  extension  of  time  for  processing  (such  as the  need to hold a
hearing),  in which case a decision  shall be rendered as soon as possible,  but
not later than 120 days after  receipt of a request for review.  The decision on
review shall be in writing and shall include  specific reasons for the decision,
written in a manner  calculated to be  understood  by the  claimant,  as well as
specific  references to the pertinent  Plan  provisions on which the decision is
based.

         19.      Miscellaneous.

                  19.1  Execution of Receipts and  Releases.  Any payment to any
Participant, a Participant's legal representative,  or Beneficiary in accordance
with the  provisions  of this Plan  shall,  to the  extent  thereof,  be in full
satisfaction  of all claims  against the Employer.  The Employer may require the
Participant,  legal representative,  or Beneficiary, as a condition precedent to
payment, to execute a receipt and release in a form it may determine.

                  19.2 No Guarantee of Interests.  Neither the Committee nor any
of its members  guarantees the payment of any amounts which may be or become due
to any person or entity under this Plan.  The  liability of the Employer to make
any  payment  under  this Plan is limited  to the then  available  assets of the
Employer.

                  19.3  Employer  Records.  Records  of  the  Employer  as  to a
Participant's  employment,  termination of employment  and the reason  therefor,
re-employment,   authorized  leaves  of  absence,   and  compensation  shall  be
conclusive on all persons and entities, unless determined to be incorrect.

                  19.4 Evidence. Evidence required of anyone under this Plan and
any Plan Agreement executed may be by certificate, affidavit, document, or other
information  which the person or entity  acting on it  considers  pertinent  and
reliable, and signed, made, or presented by the proper party or parties.

                  19.5     Administration Expenses.  The Company shall bear all
costs and expenses necessary to administer the Plan.

                  19.6 Notice. Any notice which shall or may be given under this
Plan  shall be in writing  and shall be mailed by United  States  mail,  postage
prepaid.  If  notice  is to be  given  to the  Employer,  such  notice  shall be
addressed to the Employer at:

                             Black Hills Corporation
                                 P. O. Box 1400
                              Rapid City, SD 57709

marked to the attention of the Secretary of Black Hills Corporation.

                  19.7  Change of  Address.  Any party  may,  from time to time,
change the address to which notices shall be mailed by giving  written notice of
such new address.

                  19.8 Effect of  Provisions.  The provisions of this Plan shall
be binding  upon the  Employer  and its  successors  and  assigns,  and upon the
Participant, Beneficiaries, assigns, heirs, executors and administrators.

                  19.9  Headings.  The  titles  and  headings  of  Articles  and
Sections  are  included  for  convenience  of  reference  only and are not to be
considered in the construction of the provisions hereof.

                  19.10  Governing  Law. All  questions  arising with respect to
this Plan shall be  determined  by  reference  to the laws of the State of South
Dakota unless preempted by federal law.

                                              BLACK HILLS CORPORATION

                                              By: /s/ Daniel P. Landguth
                                              Its Chairman, President & CEO

                                                                Exhibit 10.14

                          BLACK HILLS CORPORATION 1999
                                STOCK OPTION PLAN

ARTICLE 1.                 Establishment, Objectives, Duration

1.1 Establishment of Plan. Black Hills Corporation  (hereinafter  referred to as
the "Company"), hereby establishes an incentive compensation plan to be known as
the "Black Hills Corporation 1999 Stock Option Plan" (hereinafter referred to as
the  "Plan"),  as set  forth in this  document.  The Plan  permits  the grant of
Nonqualified Stock Options and Incentive Stock Options.

Subject  to  approval  by the  Company's  shareholders,  the Plan  shall  become
effective as of May 11, 1999 (the  "Effective  Date") and shall remain in effect
as provided in Section 1.3 hereof.

1.2  Objectives  of the Plan.  The  objectives  of the Plan are to optimize  the
profitability and growth of the Company through  incentives which are consistent
with the Company's  objectives and which link the interests of  Participants  to
those of the Company's  shareholders;  to provide Participants with an incentive
for  excellence  in  individual  performance;  and  to  promote  teamwork  among
Participants.

The Plan is  further  intended  to  provide  flexibility  to the  Company in its
ability to motivate,  attract,  and retain the services of Participants who make
significant  contributions to the Company's success and to allow Participants to
share in the success of the Company.

1.3 Duration of the Plan.  The Plan shall  commence on the  Effective  Date,  as
described  in Section 1.1  hereof,  and shall  remain in effect,  subject to the
right of the  Board of  Directors  to  amend or  terminate  the Plan at any time
pursuant  to Article 11 hereof,  until all Shares  subject to it shall have been
purchased or acquired according the Plan's provisions.  However, in no event may
an Award be granted under the Plan on or after May 11, 2009.

ARTICLE 2.                 Definitions

Whenever used in the Plan, the following terms shall have the meanings set forth
below, and when the meaning is intended, the initial letter of the word shall be
capitalized:

2.1 "Award" means, individually or collectively, a grant under this Plan of
Nonqualified Stock Options or Incentive Stock Options.

2.2 "Award  Agreement"  means an agreement  entered into by the Company and each
Participant setting forth the terms and provisions  applicable to Awards granted
under this Plan.

2.3 "Beneficial Owner" or "Beneficial Ownership" shall have the meaning ascribed
to such  term in Rule  13d-3 of the  General  Rules  and  Regulations  under the
Exchange Act.

2.4 "Board" or "Board of Directors" means the Board of Directors of the Company.

2.5 "Change in Control" of the Company shall be deemed to have occurred (as of a
particular  day, as  specified  by the Board) upon the  occurrence  of any event
described in this Section 2.5 as constituting a Change in Control.

         (a)      An  acquisition  (other than directly from the Company) of any
                  Shares of the  Company by any person  immediately  after which
                  such Person has  Beneficial  Ownership of thirty percent (30%)
                  or more of the Shares of the Company;  provided,  however,  in
                  determining  whether a Change in Control has occurred,  Shares
                  which  are  acquired  in  a  "Non-Control   Acquisition"   (as
                  hereinafter defined) shall not constitute an acquisition which
                  would cause a Change in Control.  A "Non-Control  Acquisition"
                  shall mean an acquisition by (i) an employee  benefit plan (or
                  a trust forming a part thereof) maintained by (A) the Company;
                  or (B) a Subsidiary; (ii) the Company or its Subsidiaries;  or
                  (iii)  any   Person   in   connection   with  a   "Non-Control
                  Transaction" (as hereinafter defined);

          (b)     The  individuals  who, as of the Effective Date hereof,  are
                  members of the Board (the  "Incumbent  Board") cease for any
                  reason  to  constitute  at  least  two-thirds  (2/3)  of the
                  members  of  the  Board;  provided,  however,  that  if  the
                  election, or nomination for election by the Company's common
                  shareholders,  of any new director was approved by a vote of
                  at least two-thirds  (2/3) of the Incumbent Board,  such new
                  director shall,  for purposes of this Plan, be considered as
                  a member of the Incumbent Board; provided further,  however,
                  that no  individual  shall be  considered  a  member  of the
                  Incumbent Board if such individual  initially assumed office
                  as a result  of either  an  actual  or  threatened  Election
                  Contest" (as described in Rule 14a-11  promulgated under the
                  Exchange Act) or other actual or threatened  solicitation of
                  proxies or consents  by or on behalf of a Person  other than
                  the Board (a  "Proxy  Contest")  including  by reason of any
                  agreement  intended to avoid or settle any Election  Contest
                  or Proxy Contest; or

         (c)      Approval by shareholders of the Company of:

                  (i)      A merger, consolidation,  or reorganization involving
                           the Company,  unless such merger,  consolidation,  or
                           reorganization  is  a  "Non-Control  Transaction."  A
                           "Non-Control   Transaction"   shall  mean  a  merger,
                           consolidation,   or  reorganization  of  the  Company
                           where:

                  (A)      the shareholders of the Company,  immediately  before
                           such merger,  consolidation,  or reorganization,  own
                           directly or  indirectly,  immediately  following such
                           merger,  consolidation,  or reorganization,  at least
                           seventy percent (70%) of the combined voting power of
                           the outstanding  Voting Securities of the corporation
                           resulting  from  such  merger  or   consolidation  or
                           reorganization   (the  "Surviving   Corporation")  in
                           substantially  the same proportion as their ownership
                           of the  Voting  Securities  immediately  before  such
                           merger, consolidation, or reorganization;

                  (B)      the  individuals  who were  members of the  Incumbent
                           Board  immediately  prior  to  the  execution  of the
                           agreement  providing for such merger,  consolidation,
                           or  reorganization  constitute  at  least  two-thirds
                           (2/3) of the members of the board of directors of the
                           Surviving Corporation,  or a corporation beneficially
                           directly  or  indirectly  owning  a  majority  of the
                           Voting Securities of the Surviving Corporation; and

                  (C)      no  Person  other  than  (i) the  Company;  (ii)  any
                           Subsidiary;  (iii) any employee  benefit plan (or any
                           trust  forming  a  part  thereof)  maintained  by the
                           Company,   the   Surviving   Corporation,    or   any
                           Subsidiary; or (iv) any Person who, immediately prior
                           to such merger, consolidation,  or reorganization had
                           Beneficial  Ownership of thirty percent (30%) or more
                           of  the  then  outstanding  Voting  Securities),  has
                           Beneficial  Ownership of thirty percent (30%) or more
                           of  the  combined   voting  power  of  the  Surviving
                           Corporation's then outstanding Voting Securities.

         (ii)     A complete liquidation or dissolution of the Company; or

         (iii)    An  agreement  for the  sale of  other  disposition  of all or
                  substantially  all of the assets of the  Company to any Person
                  other than (x) a transfer  to a  Subsidiary;  or (y) a sale or
                  transfer of a Subsidiary by the Company except if such sale or
                  transfer  would  be a  sale  or  other  disposition  of all or
                  substantially all of the assets of the Company.

(d) Notwithstanding  the foregoing,  (i) a Change in Control shall not be deemed
to occur solely because any Person (the "Subject  Person")  acquired  Beneficial
Ownership of more than the permitted amount of the then outstanding Common Stock
as a result of the  acquisition of Shares by the Company which,  by reducing the
number of Shares then outstanding,  increases the proportional  number of shares
beneficially owned by the Subject Persons,  provided that if a Change in Control
would  occur  (but  for the  operation  of this  sentence)  as a  result  of the
acquisition  of Shares by the Company,  and after such stock  acquisition by the
Company,  the Subject  Person  becomes the  Beneficial  Owner of any  additional
Shares  which   increases  the  percentage  of  the  then   outstanding   Shares
beneficially owned by the Subject Person,  then a Change in Control shall occur;
and (ii) a Change in Control  shall not be deemed to occur  unless and until all
regulatory  approvals required to effect a Change in Control of the Company have
been obtained.

2.6 "Code"  means the  Internal  Revenue  Code of 1986,  as amended from time to
time.

2.7 "Committee"  means the Compensation  Committee of the Board, as specified in
Article 3 herein,  or such other Committee  appointed by the Board to administer
the Plan with respect to grants of Awards.

2.8  "Company"  means  Black  Hills  Corporation,  together  with  any  and  all
Subsidiaries, and any successor thereto as provided in Article 14 herein.

2.9 "Director" means any individual who is a member of the Board of Directors of
the Company.

2.10  "Disability"  shall  have  the  meaning  ascribed  to  such  term  in  the
Participant's governing long-term disability plan.

2.11  "Effective  Date" shall have the meaning  ascribed to such term in Section
1.1 hereof.

2.12 "Employee" means any full-time,  active employee of the Company.  Directors
who are not employed by the Company shall not be considered Employees under this
Plan.

2.13 "Exchange  Act" means the Securities  Exchange Act of 1934, as amended from
time to time, or any successor act thereto.

2.14 "Fair Market  Value" shall be  determined  on the basis of the closing sale
price on the principal securities exchange on which the Shares are traded or, if
there is no such sale on the  relevant  date,  then on the last  previous day on
which a sale was reported.

2.15  "Incentive  Stock  Option"  or "ISO"  means an option to  purchase  Shares
granted under  Article 6 herein and which is  designated  as an Incentive  Stock
Option and which is intended to meet the requirements of Code Section 422.

2.16  "Insider"  shall  mean an  individual  who is, on the  relevant  date,  an
officer,  director or ten  percent  (10%)  beneficial  owner of any class of the
Company's  equity  securities  that is  registered to Section 12 of the Exchange
Act, all as defined under Section 16 of the Exchange Act.

2.17 "Nonemployee  Director" means an individual who is a member of the Board of
Directors of the Company but who is not an Employee of the Company.

2.18  "Nonqualified  Stock Option" or "NQSO" means an option to purchase  Shares
granted  under  Article  6  herein  and  which  is  not  intended  to  meet  the
requirements of Code Section 422.

2.19 "Option" means an Incentive Stock Option or a Nonqualified Stock Option, as
described in Article 6 herein.

2.20  "Option  Price"  means the price at which a Share  may be  purchased  by a
Participant pursuant to an Option.

2.21 "Participant"  means an Employee who has outstanding an Award granted under
the Plan. The term "Participant" shall not include Nonemployee Directors.

2.22 "Person" shall have the meaning ascribed to such term in Section 3(a)(9) of
the  Exchange  Act and used in  Sections  13(d) and 14(d)  thereof,  including a
"group" as defined in Section 13(d) thereof.

2.23 "Retirement"  shall have the meaning ascribed to such term in the Company's
tax-qualified defined benefit retirement plan.

2.24 "Shares" means the shares of Common Stock of the Company.

2.25  "Subsidiary"  means any corporation or other Person of which a majority of
its voting power or its voting equity securities ("Voting Securities") or equity
interest is owned, directly or indirectly, by the Company.

Article 3.        Administration

3.1 The Committee.  The Plan shall be administered by the Compensation Committee
of the Board, or by any other Committee  appointed by the Board, which Committee
shall satisfy the "disinterested  administration"  rules of Rule 16b-3 under the
Exchange Act, or any successor provision.  The members of the Committee shall be
appointed  from time to time by, and shall serve at the discretion of, the Board
of Directors.

3.2 Authority of the Committee.  Subject to the provisions herein, the Committee
shall have full power to select  Employees  who shall  participate  in the Plan;
determine the sizes and types of Awards;  determine the terms and  conditions of
Awards in a manner consistent with the Plan; construe and interpret the Plan and
any  agreement  or  instrument  entered  into  under  the Plan as they  apply to
Employees;  establish,  amend,  or waive  rules and  regulations  for the Plan's
administration  as they apply to  Employees;  and (subject to the  provisions of
Article 11 herein) amend the terms and  conditions of any  outstanding  Award to
the extent such terms and  conditions are within the discretion of the Committee
as  provided  in  the  Plan.  Further,   the  Committee  shall  make  all  other
determinations which may be necessary or advisable for the administration of the
Plan, as the Plan applies to  Employees.  As permitted by law, the Committee may
delegate its authority as identified herein.

3.3 Decisions  Binding.  All  determinations and decisions made by the Committee
pursuant to the provisions of the Plan and all related orders and resolutions of
the Board shall be final,  conclusive and binding on all persons,  including the
Company,  its  shareholders,  Employees,  Participants,  and their  estates  and
beneficiaries.

Article 4.  Shares Subject to the Plan

4.1 Number of Shares Available for Grants.  Subject to adjustment as provided in
Section  4.3  herein,  the number of Shares  which may be issued on  exercise of
Options  shall be 700,000.  Such Shares may be authorized  but unissued  Shares,
treasury   Shares,   Shares  acquired  on  the  open  market   specifically  for
distribution under this Plan, or any combination  thereof,  as the Committee may
from time to time determine.

4.2 Lapsed Awards. If any Award granted under this Plan is canceled, terminates,
expires,  or lapses for any reason any Shares  subject to such Award again shall
be available for the grant of an Award under the Plan.

4.3  Adjustments in Authorized  Shares.  In the event of any change in corporate
capitalization,  such as a stock split, or a corporate transaction,  such as any
merger, consolidation,  separation,  including a spin-off, or other distribution
of stock or property of the  Company,  any  reorganization  (whether or not such
reorganization  comes within the definition of such term in Code Section 368) or
any partial or complete  liquidation of the Company,  such  adjustment  shall be
made in the number and class of Shares which may be delivered under Section 4.1,
in the number and class of and/or price of Shares subject to outstanding  Awards
granted under the Plan, as may be determined to be appropriate  and equitable by
the Committee,  in its sole  discretion,  to prevent  dilution or enlargement of
rights; provided,  however, that the number of Shares subject to any Award shall
always be a whole number.

Article 5.        Eligibility and Participation

5.1  Eligibility.  Persons  eligible  to  participate  in this Plan  include all
Employees of the Company, including Employees who are members of the Board.

5.2 Actual  Participation.  Subject to the provisions of the Plan, the Committee
may, from time to time, select from all eligible Employees, those to whom Awards
shall be granted and shall determine the nature and amount of each Award.

Article 6.        Stock Options

6.1 Grant of Options.  Subject to the terms and provisions of the Plan,  Options
may be granted to Participants in such number,  and upon such terms,  and at any
time and from time to time as shall be determined by the Committee.

6.2 Award Agreement.  Each Option grant shall be evidenced by an Award Agreement
that shall specific the Option Price, the duration of the Option,  the number of
Shares to which the Option pertains,  and such other provisions as the Committee
shall  determine.  The Award  Agreement also shall specify whether the Option is
intended to be an ISO within the meaning of Code  Section  422, or an NQSO whose
grant is intended not to fall under the provisions of Code Section 422.

6.3 Option  Price.  The Option Price for each grant of an Option under this Plan
shall be at least equal to one hundred  percent  (100%) of the Fair Market Value
of a Share on the date the Option is granted or a higher amount. No repricing of
Options  by  any  method  shall  be  allowed,  including,   without  limitation,
cancellation and reissuance.

6.4 Duration of Options. Each Option granted to an Employee shall expire at such
time as the  Committee  shall  determine  at the  time of the  grant;  provided,
however,  that no  Option  shall be  exercisable  later  than the  tenth  (10th)
anniversary date of its grant.

6.5  Exercise  of  Options.  Options  granted  under  this  Article  6 shall  be
exercisable at such times and be subject to such  restrictions and conditions as
the  Committee  shall in each instance  approve,  which need not be the same for
each grant or for each Participant.

6.6  Payment.  Options  granted  under this  Article 6 shall be exercised by the
delivery  of a written  notice of  exercise to the  Company,  setting  forth the
number  of  Shares  with  respect  to  which  the  Option  is to  be  exercised,
accompanied by full payment for the Shares.

The Option Price upon  exercise of any Option shall be payable to the Company in
full either (a) in cash or its  equivalent;  (b) if permitted  in the  governing
Award  Agreement,  by tendering  previously  acquired Shares having an aggregate
Fair  Market  Value at the time of  exercise  equal to the  total  Option  Price
(provided  that the  Shares  which  are  tendered  must  have  been  held by the
Participant  for at least six (6) months  prior to their  tender to satisfy  the
Option  Price);  or (c) if  permitted in the  governing  Award  Agreement,  by a
combination of (a) and (b).

In addition,  if permitted in the Award  Agreement,  the Participant may also be
permitted to exercise  Options  pursuant to a "cashless  exercise"  procedure as
permitted under the Federal Reserve Board's  Regulation T, subject to securities
law restrictions. In the event the Participant exercises pursuant to a "cashless
exercise" procedure,  any net gain on the "cashless exercise," after appropriate
tax withholdings, shall be distributed to the Participant in the form of Shares.

As soon as practicable  after receipt of a written  notification of exercise and
full payment, the Company shall deliver to the Participant, in the Participant's
name,  Share  certificates  in an  appropriate  amount  based upon the number of
Shares purchased under the Option(s). If either the purchase price or the Shares
of Common Stock upon exercise of any Option or the tax  withholding  requirement
is satisfied by tendering or  withholding  of Shares of Common  Stock,  only the
number of Shares of Common  Stock to be issued net of the Shares of Common Stock
tendered or withheld shall be delivered.

6.7  Restrictions  on Share  Transferability.  The  Committee  may  impose  such
restrictions  on any  Shares  acquired  pursuant  to the  exercise  of an Option
granted  under  this  Article  6 as it may deem  advisable,  including,  without
limitation,  restrictions  under applicable  Federal  securities laws, under the
requirements  of any stock  exchange  or market  upon which such Shares are then
listed and/or traded, and under any blue sky or state securities laws applicable
to such Shares.

6.8 Termination of Employment.  Each Participant's  Option Award Agreement shall
set forth the extent to which the  Participant  shall have the right to exercise
the  Option  following  termination  of the  Participant's  employment  with the
Company.  Such  provisions  shall be  determined  in the sole  discretion of the
Committee,  shall be  included  in the Award  Agreement  entered  into with each
Participant,  need not be uniform  among all  Options  issued  pursuant  to this
Article 6, and may reflect  distinctions based on the reasons for termination of
employment.

6.9      Nontransferability of Options.

(a)      Incentive  Stock  Options.  No ISO granted  under the Plan may be sold,
         transferred, pledged, assigned, or otherwise alienated or hypothecated,
         other than by will or by the laws of descent and distribution. Further,
         all ISOs granted to a Participant  under the Plan shall be  exercisable
         during his or her lifetime only by such Participant.

(b)      Nonqualified   Stock  Options.   Except  as  otherwise  provided  in  a
         Participant's Award Agreement, no NQSO granted under this Article 6 may
         be sold,  transferred,  pledged,  assigned,  or otherwise  alienated or
         hypothecated,  other  than  by  will  or by the  laws  of  descent  and
         distribution.  Further, except as otherwise provided in a Participant's
         Award Agreement,  all NQSOs granted to a Participant under this Article
         6  shall  be  exercisable  during  his or her  lifetime  only  by  such
         Participant.

Article 7.        Beneficiary Designation

Each Participant  under the Plan may, from time to time, name any beneficiary or
beneficiaries  (who  may be  named  contingently  or  successively)  to whom any
benefit  under the Plan is to be paid in case of his or her  death  before he or
she received any or all of such benefit.  Each such designation shall revoke all
prior designations by the same Participant, shall be in a form prescribed by the
Company,  and will be effective  only when filed by the  Participant  in writing
with the Company during the Participant's  lifetime.  In the absence of any such
designation,  benefits remaining unpaid at the Participant's death shall be paid
to the Participant's estate.

Article 8.        Deferrals

The Committee may permit or require a  Participant  to defer such  Participant's
receipt of the payment of cash or the delivery of Shares that would otherwise be
due to such  Participant  by virtue of the  exercise  of an Option.  If any such
deferral  election is required or permitted,  the Committee  shall,  in its sole
discretion, establish rules and procedures for such payment deferrals.

Article 9.        Rights of Employees

9.1 Employment. Nothing in the Plan shall interfere with or limit in any way the
right of the Company to terminate any Participant's  employment at any time, nor
confer upon any Participant any right to continue in the employ of the Company.

9.2 Participation. No Employee shall have the right to be selected to receive an
Award under this Plan, or, having been so selected,  to be selected to receive a
future Award.

Article 10.       Change in Control

10.1  Treatment  of  Outstanding  Awards.  Upon the  occurrence  of a Change  in
Control,  unless otherwise specifically  prohibited under applicable laws, or by
the rules and  regulations  of any governing  governmental  agencies or national
securities  exchanges,  any and  all  Options  granted  hereunder  shall  become
immediately  exercisable,  and shall remain exercisable  throughout their entire
term.

10.2 Termination,  Amendment, and Modifications of Change-in-Control Provisions.
Notwithstanding  any  other  provision  of  this  Plan  or any  Award  Agreement
provision, the provisions of this Article 10 may not be terminated,  amended, or
modified  on or after the date of a Change in  Control to affect  adversely  any
Award  theretofore  granted under the Plan without the prior written  consent of
the Participant with respect to said Participant's outstanding Awards.

Article 11.       Amendment, Modification, and Termination

11.1 Amendment,  Modification, and Termination.  Subject to Section 10.2 herein,
the  Board  may at any time and from  time to time,  alter,  amend,  suspend  or
terminate  the Plan in whole or in part;  provided,  however,  that no amendment
which requires  shareholder approval in order for the Plan to continue to comply
with Rule 16b-3 under the Exchange  Act,  including  any successor to such Rule,
shall be effective unless such amendment shall be approved by the requisite vote
of shareholders of the Company entitled to vote thereon.

The  Committee  shall not have the  authority to cancel  outstanding  Awards and
issue substitute Awards in replacement thereof.

11.2 Adjustment of Awards Upon the Occurrence of Certain Unusual or Nonrecurring
Events.  The Committee may make  adjustments in the terms and conditions of, and
the  criteria  included in,  Awards in  recognition  of unusual or  nonrecurring
events  (including,  without  limitation  the events  described  in Section  4.3
hereof)  affecting the Company or the financial  statements of the Company or of
changes in applicable laws, regulations, or accounting principles,  whenever the
Committee  determines that such  adjustments are appropriate in order to prevent
dilution or  enlargement  of the benefits or potential  benefits  intended to be
made available under the Plan.

11.3 Awards Previously  Granted. No termination,  amendment,  or modification of
the Plan shall adversely affect in any material way any Award previously granted
under the Plan,  without the written  consent of the  Participant  holding  such
Award.

Article 12.       Withholding

12.1 Tax  Withholding.  The Company shall have the power and the right to deduct
or  withhold,  or  require  a  Participant  to remit to the  Company,  an amount
sufficient  to satisfy  Federal,  state and local  taxes,  domestic  or foreign,
required by law or  regulation  to be withheld with respect to any taxable event
arising as a result of this Plan.

12.2 Share Withholding.  With respect to withholding  required upon the exercise
of Options, Participants may elect, subject to the approval of the Committee, to
satisfy the withholding requirement,  in whole or in part, by having the Company
withhold  Shares  having  a Fair  Market  Value  on the  date  the  tax is to be
determined  equal to the minimum  statutory total tax which could be withheld on
the  transaction.  All such  elections  shall be  irrevocable,  made in writing,
signed  by  the  Participant,  and  shall  be  subject  to any  restrictions  or
limitations that the Committee, in its sole discretion, deems appropriate.

Article 13.       Indemnification

Each  person  who is or shall  have  been a member of the  Committee,  or of the
Board,  shall be indemnified  and held harmless by the Company  against and from
any loss,  cost,  liability,  or expense that may be imposed upon or  reasonably
incurred by him or her in connection  with or resulting from any claim,  action,
suit,  or proceeding to which he or she may be a party or in which he or she may
be involved  by reason of any action  taken or failure to act under the Plan and
against and from any and all amounts paid by him or her in  settlement  thereof,
with  the  Company's  approval,  or  paid by him or her in  satisfaction  of any
judgment in any such action,  suit, or proceeding against him or her provided he
or she shall give the Company an opportunity,  at its own expense, to handle and
defend the same  before he or she  undertakes  to handle and defend it on his or
her own behalf. The foregoing right of indemnification shall not be exclusive of
any other rights of  indemnification to which such persons may be entitled under
the  Company's  Articles  of  Incorporation  or Bylaws,  as a matter of law,  or
otherwise, or any power that the Company may have to indemnify them or hold them
harmless.

Article 14.       Successors

All  obligations  of the Company  under the Plan with respect to Awards  granted
hereunder  shall  be  binding  on any  successor  to the  Company,  whether  the
existence of such successor is the result of a direct or indirect  purchase,  of
all or  substantially  all of the business  and/or  assets of the Company,  or a
merger, consolidation, or otherwise.

Article 15.       Miscellaneous Provisions

15.1 Gender and Number.  Except where  otherwise  indicated by the context,  any
masculine  term used herein also shall  include the  feminine;  the plural shall
include the singular and the singular shall include the plural.

15.2 Severability.  In the event any provision of the Plan shall be held illegal
or invalid for any reason,  the  illegality or  invalidity  shall not affect the
remaining  parts of the Plan, and the Plan shall be construed and enforced as if
the illegal or invalid provision had not been included.

15.3  Requirements  of Law.  The  granting of Awards and the  issuance of Shares
under the Plan shall be subject to all applicable laws,  rules, and regulations,
and to such  approvals  by any  governmental  agencies  or  national  securities
exchanges as may be required.

15.4 Securities Law  Compliance.  With respect to Insiders,  transactions  under
this Plan are intended to comply with all applicable conditions of Rule 16b-3 or
its  successors  under the Exchange Act. To the extent any provision of the plan
or action by the Committee fails to so comply, it shall be deemed null and void,
to the extent permitted by law and deemed advisable by the Committee.

15.5  Governing  Law. To the extent not preempted by Federal law, the Plan,  and
all agreements hereunder,  shall be construed in accordance with and governed by
the laws of the state of South Dakota.

15.6  Unfunded  Status  of the  Plan.  The Plan is  intended  to  constitute  an
"unfunded"  Plan.  With respect to any payments or  deliveries of Shares not yet
made to a Participant by the Company,  nothing  contained  herein shall give any
rights that are greater than those of a general creditor of the Company.

15.7  Purchase  for  Investment.  The  Committee  may require  each  Participant
purchasing or receiving  Shares  pursuant to an Option to represent to and agree
with the  Company  in  writing  that such  person is  acquiring  the  Shares for
investment and without a view to distribution or resale.

                                                                     Exhibit 21

                             BLACK HILLS CORPORATION

                  SIGNIFICANT DIRECT AND INDIRECT SUBSIDIARIES

                Black Hills Power, Inc., South Dakota corporation

          Black Hills Energy Ventures, Inc., a South Dakota corporation

            Black Hills Energy Capital, Inc., a Delaware corporation

           Wyodak Resources Development Corp., a Delaware corporation

        Adirondack Hydro Development Corporation, a Delaware corporation

           Black Hills Capital Group, Inc., a South Dakota Corporation

           Black Hills Coal Network, Inc., a South Dakota corporation

                Black Hills Colorado, LLC, a Delaware corporation

         Black Hills Energy Resources, Inc., a South Dakota corporation

       Black Hills Exploration and Production, Inc., a Wyoming corporation

              Black Hills FiberCom, LLC, a South Dakota corporation

           Black Hills Fiber Systems, Inc., a South Dakota corporation

               Black Hills Generation, Inc., a Wyoming corporation

                    Daksoft, Inc., a South Dakota corporation

                Enserco Energy, Inc., a South Dakota corporation

                    Hudson Falls, LLC, a New York corporation

            Landrica Development Company, a South Dakota corporation

                 South Glens Falls, LLC, a New York corporation

                    CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the incorporation of our
report dated  January 26, 2001  included or  incorporation  by reference in this
Form 10-K, into the Company's  previously filed  Registration  Statements,  File
Numbers 33-71130, 33-63059, 33-17451, 333-61969, 333-82787 and 333-30272.

                                                     ARTHUR ANDERSEN LLP

Minneapolis, Minnesota
   March 15, 2001

                                                                  Exhibit 23.2

             CONSENT OF INDEPENDENT PETROLEUM ENGINEER AND GEOLOGIST

As petroleum  engineers,  we hereby consent to the inclusion of the  information
included  in this Form 10-K with  respect to the oil and gas  reserves  of Black
Hills Exploration and Production,  Inc., the future revenues from such reserves,
and the present value thereof,  which information has been included in this Form
10-K in  reliance  upon the report of this firm and upon the  authority  of this
firm as experts  in  petroleum  engineering.  We hereby  further  consent to all
references  to our firm included in this Form 10-K and to the  incorporation  by
reference in the Registration  Statements on Form S-8 Nos. 33-63059,  333-61969,
333-17451,  333-82787 and 333-30272 and the Registration  Statement on Form S-3,
No. 33-71130.

                                              RALPH E. DAVIS ASSOCIATES, INC.

March 15, 2001

                                           UT

                                                        YEAR
                                             DEC-31-2000
                                                  DEC-31-2000
                                                     PER-BOOK
                                     358,180,000
                                   500,066,000
                                        419,010,000
                                       43,064,000
                                                          0
                                              1,320,320,000
                                                       23,302,000
                                      73,442,000
                                           191,482,000
                                278,346,000
                                                   0
                                                             0
                                          307,092,000
                                            211,679,000
                                               0
                                          0
                                  13,960,000
                                       4,000,000
                                             0
                                                        0
                                495,363,000
                               1,320,320,000
                                   1,623,836,000
                                           30,358,000
                                  1,509,086,000
                                  1,539,444,000
                                        84,392,000
                                             (1,202,000)
                                 83,190,000
                                       30,342,000
                                                   52,848,000
                                        78,000
                                  52,770,000
                                       23,527,000
                                      13,094,000
                                         74,470,000
                                                        2.39
                                                        2.37