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.

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                                              2000             1999         1998            1997           1996
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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
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(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.

                                                        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.