TABLE OF CONTENTS

PART I

ITEMS 1 AND 2.   BUSINESS AND PROPERTIES

Website Access to Reports

Through our Internet website, www.blackhillscorp.com, we make available free of charge, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

General

We are a diversified energy holding company operating principally in the United States. Our regulated and unregulated businesses have expanded their asset bases significantly in recent years. Our integrated energy group produces and markets power and fuel and transports crude oil. We produce and sell electricity in a number of markets, with a strong emphasis on the western United States. We also produce coal, natural gas and crude oil primarily in the Rocky Mountain region and market fuel products primarily in the Rocky Mountain, western and mid-continent regions of the United States and in Western Canada. Our electric utility serves approximately 60,000 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 change over the last five years, primarily as a result of the expansion of our integrated energy business and increases in wholesale electric sales at our electric utility. Unusual conditions in the western energy markets during the first half of 2001 and the last part of 2000 accounted for approximately $1.40 per share and $0.40 per share of our earnings in 2001 and 2000, respectively.

For additional information on our business segments see – ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 16 of NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

Industry Overview

The energy and telecommunications industries can be expected to become increasingly competitive due to a variety of regulatory, economic and technological changes.

In the last decade, many U.S. regulatory bodies took 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. As a result of regulatory initiatives at the federal and state levels, the electric power industry has experienced and is undergoing substantial change. As early as the mid-1990‘s, new regulatory initiatives to increase competition in the domestic power generation industry were adopted or were being considered. 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. These changes created new investment opportunities for competitive or partially regulated businesses to enter previously non-competitive or closed markets.

The electric power industry also witnessed growing consumer demand and frequent regional shortages of electricity over the past several years. The summers of 1998, 1999 and 2000 and the winter of 2000-2001 were characterized by very high peak prices for electricity in a number of recently deregulated wholesale electricity markets. In a number of these markets, government agencies and other interested parties made proposals to delay market restructuring or even re-regulate certain areas of the markets that had been previously deregulated. The Federal Energy Regulatory Commission (FERC) instituted a series of price controls designed to mitigate (or cap) prices in the western United States and initiated numerous investigations into the western markets as a result of the California energy crisis. These price controls contributed to the lowering of spot and forward energy prices in the western markets. Other proposals to re-regulate the energy industry or to institute price controls may be made, and legislative or other actions may cause the electric power restructuring process to be delayed, discontinued or reversed in states that have already deregulated. Mild weather patterns in the summer of 2001 and winter of 2001-2002 and the current recession mitigated most regional energy shortages.

The energy industry recently faced a financial crisis stemming from the loss of billions of dollars in market capitalization reflecting broad market conditions and investor attitudes. Investors and consumers have lost confidence in the financial health of many energy providers as a result of numerous events following the collapse of Enron. Accordingly, energy companies have been subject to much greater scrutiny and significantly tighter credit standards. Companies are moving aggressively to improve liquidity and to restructure their balance sheets. They are selling non-core assets, downsizing, issuing new equity, canceling acquisitions, postponing or canceling construction projects, reducing significant levels of capital expenditures, accelerating debt repayment and realigning trading around their own generation assets.

The oil and gas industry has experienced volatile changes in commodity prices in recent years. Price increases were driven in part by several years of modest drilling activity combined with strong growth in demand for energy commodities and the threat of war in the Middle East. Price decreases were driven by weather patterns, the recession and actions by OPEC. Natural gas is expected to remain the fuel of choice. Demand for natural gas is expected to be strong in the future as an increasing number of gas-fired power plants are brought into service.

The telecommunications industry underwent widespread changes brought about by, among other things, the Telecommunications Act of 1996, the decisions of federal and state regulators to open the monopolistic local telephone and cable television markets to competition, the increased consumer demand for higher speed and higher capacity networks and for expanded telecommunications services, including broader video choices and high speed data and Internet services. The convergence of these trends allowed many new entrants into the telecommunication market. More recently the telecommunication industry suffered the effects of an economic slowdown, increased competition and financial stress.

Our Business Strategy

Our long-term growth strategy is to add and augment revenue streams from our diverse integrated energy operations. We have implemented a balanced, integrated approach to fuel production, energy marketing and power generation, supported by disciplined risk management practices. Building on the strength of our electric utility, we enhanced our local operations by providing broadband communications to our customers in South Dakota. Our diverse operations avoid reliance on any single business to achieve our growth objectives. This diversity provides a measure of stability to our business and financial performance in volatile or cyclical periods.

Our strategy includes the following key elements:

• grow our power generation segment by developing and acquiring power generating assets in targeted western markets and, in particular, by expanding generating capacity of our existing sites through a strategy known as “brownfield development;"
  
  
• sell a large percentage of our production from new independent power projects through long-term contracts in order to secure a stable revenue stream and attractive returns;
  
  
• preserve our electric utility’s low-cost rate structure for our retail customers while retaining the flexibility to allocate excess generating capacity to maximize returns in changing market environments;
  
  
• increase our reserves of natural gas and crude oil and expand our fuel production;
  
  
• manage the risks inherent in energy marketing by maintaining position limits that minimize price risk exposure;
  
  
• conduct business with a diversified group of creditworthy counterparties;
  
  
• exploit our fuel cost advantages and our operating and marketing expertise to remain a low-cost power producer;
  
  
• increase margins from our coal production through an expansion of mine-mouth generation and increased coal sales;
  
  
• build and maintain strong relationships with wholesale energy customers;
  
  
• create a strong “super local” service company by capitalizing on our utility’s established market presence, relationships and customer loyalty to expand our local communications business, integrating our electric and telecommunications products around the same customer base; and
  
  
• organize our lines of business into retail and wholesale energy components. The retail component will consist of electric and telecommunications products in the same footprint as our electric utility exists today. The wholesale component will consist of fuel production, marketing, mid-stream assets and power production facilities.
  

Grow our Power Generation Segment by Developing and Acquiring Power Generating Assets in Targeted Western Markets, and in Particular, by Expanding Generating Capacity of our Existing Sites Through a Strategy Known as “Brownfield Development.” We aim to develop power plants in regional markets based on prevailing supply and demand fundamentals in a manner that complements our existing fuel assets and fuel and energy marketing capabilities. This approach seeks to capitalize on market growth while managing our fuel procurement needs. 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 western region where we believe we have the detailed knowledge of market fundamentals and competitive advantage to achieve attractive returns. We believe the following trends will provide us with growth opportunities in the future:

• Demand for electricity in the western regions is expected to grow and new generation capacity will be required over the next several years.
  
• New electric generation construction will be predominantly gas-fired, which may create further competitive cost advantages for new and existing coal-fired generation assets.
  
• Transmission construction will significantly lag new generation development, favoring new development located near load centers or existing, unconstrained transmission locations.
  
• 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.

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:

• proximity to existing transmission systems;
  
• operating cost advantages related to ownership of shared facilities;
  
• a less costly and time consuming permitting process; and
  
• potential ability to share infrastructure with existing facilities at the same site.

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

Sell a Large Percentage of our Production From New Independent Power Projects Through Long-Term Contracts in Order to Secure a Stable Revenue Stream and Attractive Returns. 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. Approximately 90 percent of our unregulated power generation assets are under long-term contracts.

Preserve our Electric Utility’s Low-Cost Rate Structure for our Retail Customers While Retaining the Flexibility to Allocate Excess Generating Capacity to Maximize Returns in Changing Market Environments. In 1999, the South Dakota Public Utilities Commission extended our previous retail rate freeze until 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 wholesale “off-system” sales. This provides us with flexibility in allocating our generating capacity to maximize returns in changing market environments. 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.

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 by emphasizing natural gas. Our strategy is to expand our natural gas reserves through a combination of acquisitions and drilling programs. We aim 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:

• substantially increase our natural gas reserves while minimizing exploration risk by focusing on lower-risk exploration and development drilling as well as acquisitions of proven reserves;
  
• exploit opportunities based on our belief that the long-term demand for natural gas will remain strong by emphasizing natural gas in our acquisition and drilling activities; and
  
• add natural gas reserves and increase production by focusing on various shallow gas plays in the Rocky Mountain region, where the added production can be integrated with our fuel marketing and/or power generation activities.

Manage the Risks Inherent in Energy Marketing by Maintaining Position Limits That Minimize Price Risk Exposure. Our energy marketing operations require effective management of price and operational risks related to adverse changes in commodity prices and the volatility and liquidity of the commodity markets. To mitigate these risks, we have implemented risk management policies and procedures for each of our marketing companies that establish price risk exposure levels. We formed oversight 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.

Conduct Business With a Diversified Group of Creditworthy Counterparties. Our operations require effective management of counterparty credit risk. We mitigate this risk by conducting business with a diversified group of creditworthy counterparties. We accomplish this by establishment of counterparty credit limits, continuous credit monitoring, and regular review of credit compliance with our policy by our Executive Credit Committee that reports to our board of directors.

Exploit our Fuel Cost Advantages 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. As an increasing number of gas-fired power plants are brought into operation, we intend to utilize a low-cost power production strategy, together with access to coal and natural gas reserves, to protect our revenue stream. 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 aggressively manage 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.

Increase Margins From our Coal Production Through an Expansion of Mine-Mouth Generation and Increased Coal Sales. Our strategy is to expand our coal production through the construction of mine-mouth coal-fired generation plants at our Wyodak mine location. Our objective is to maintain coal reserves to serve our mine-mouth coal-fired generation plants directly. Specifically, we plan to:

• increase coal production and sales from our Wyodak mine by continuing to develop additional mine-mouth generating facilities at the site, such as the Wygen plant, which went into service in the first quarter 2003; and
  
• pursue future sales of coal from the Wyodak mine to rail-served customers.

Build and Maintain Strong Relationships With Wholesale Energy Customers. We strive to build strong relationships with utilities, municipalities and other wholesale customers, who we believe will continue to be the primary providers of electricity to retail customers in a deregulated environment. We further believe that these entities will need products, such as capacity, in order to serve their customers reliably. By providing these products under long-term contracts, we are able to meet our customers’ energy needs. Through this approach, we also believe 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.

Create a Strong “Super Local” Service Company by Capitalizing on our Utility’s Established Market Presence, Relationships and Customer Loyalty to Expand our Local Communications Business, Integrating our Electric and Telecommunications Products Around the Same Customer Base. 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 below the national average, we have developed a strong, supportive relationship with our utility regulators. Our utility provides a solid foundation of support for the expansion of our communications businesses. In addition, technical and market expertise from our utility and our strong brand recognition promotes rapid customer acceptance of our bundled communications services in our Black Hills service territory.

Integrated Energy

Our integrated energy group engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power primarily under long-term contracts, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing of energy products. The integrated energy group consists of four segments: power generation, natural gas and crude oil production, coal mining and energy marketing and transportation.

Power Generation

Our power generation segment acquires, develops and expands unregulated power plants. We hold varying interests in independent power plants in California, New York, Massachusetts, Wyoming, Nevada and Colorado with a total net ownership of 950 megawatts in operation, including minority interests in several power-related funds with a net ownership interest of 24 megawatts.

Project Development Program. At December 31, 2002, we were in the final stages of construction of the 90 megawatt coal-fired Wygen power plant at our Wyodak site located near Gillette, Wyoming. The Wygen plant became operational in the first quarter of 2003 and is accounted for as an operating lease.

Through our active acquisition and development program we are pursuing a number of additional generation projects in the early stages of development, including a coal-fired mine-mouth power plant with generating capacity of up to 500 megawatts, to be located at our Wyodak site near Gillette, Wyoming. We cannot assure you that we will be successful in completing any or all of the projects currently under consideration.

How We Manage Our Portfolio. We strive to maintain diversity and balance in our portfolio of regulated and unregulated power plants. Our unregulated portfolio (including plants currently operating and those under construction) is diversified in terms of fuel mix and geographic location, with 87 percent of net unregulated capacity being gas-fired, 9 percent coal-fired, and the remainder hydroelectric. Our independent power plants are located in California, Wyoming, Colorado, Nevada, New York and Massachusetts. By comparison, our electric utility capacity is approximately 50 percent coal-fired, 39 percent oil or gas-fired and 11 percent under purchased power contracts, with plants located in South Dakota and Wyoming.

We sell our output under contracts of varying length, thereby allowing us to mitigate the impact of a potential downturn in prices in the future. We sell energy and capacity under a combination of short- and long-term contracts as well as direct sales into the energy markets. Currently, we sell approximately 90 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 power markets. Substantially all of the energy and capacity generated by our Wygen plant is also under long-term contracts.

How We Develop and Acquire Power Plants. We plan to actively pursue power plant acquisitions and development opportunities in areas we view as attractive throughout North America. Our primary focus has been, and is likely to remain, in the North American Electric Reliability Council region known as the Western Electricity Coordinating Council, or “WECC.” Among the factors we consider critical in evaluating the relative attractiveness of new generation opportunities are the following:

• potential electric demand growth in the targeted region;
  
• regional generation capacity characteristics;
  
• permitting and siting requirements;
  
• proximity of the proposed site to high transmission capacity corridors;
  
• fuel supply reliability and pricing;
  
• the local regulatory environment; and
  
• the potential to exploit market expertise and operating efficiencies relating to geographic concentration of new generation with our existing power plant portfolio.

Our goal is to sell approximately 80-90 percent of the independent power generation portfolio under long-term contracts to counterparties with investment grade credit, while reserving the remainder for merchant or “spot” sales. We aim to secure long-term power sales contracts in conjunction with project financing. This structure limits our liability and establishes a debt repayment schedule to closely match the term of the power sales contracts so that at the end of the contract term, the project debt will largely be repaid.

Rocky Mountain and West Coast Facilities. We own approximately 845 megawatts of generating capacity in the WECC states of California, Colorado, Nevada and Wyoming, and at December 31, 2002, we were in the final stages of constructing another 90 megawatts in the region which became operational in the first quarter of 2003. All the facilities currently in operation are gas-fired, and the majority are operating under long-term power purchase or tolling agreements whereby the purchaser assumes the fuel price risk. The 90 megawatt plant under construction is coal-fired.

Fountain Valley, Arapahoe and Valmont Facilities. Our Fountain Valley, Arapahoe and Valmont plants are wholly-owned gas-fired peaking facilities in the Front Range of Colorado, with a total capacity of 450 megawatts. We sell all of the output from these plants to Public Service Company of Colorado under tolling contracts expiring in 2012.

Las Vegas Cogeneration Facility. Las Vegas I is a 53 megawatt, gas-fired plant northeast of Las Vegas, Nevada. Most of the power from this plant is sold to Nevada Power under a long-term contract that expires in 2024. While we own 50 percent of this plant, under generally accepted accounting principles, we consolidate 100 percent of the plant in our financial statements.

In late December 2002, we completed construction on Las Vegas II, a 224 megawatt gas-fired expansion of the Las Vegas Cogeneration Facility. We sell the power generated by Las Vegas II under a long-term contract with Allegheny Energy Supply L.L.C. that expires in 2018. We own 100 percent of Las Vegas II.

Gillette CT. The Gillette CT, a gas-fired combustion turbine located at the same site as our Wygen plant, has a total capacity of 40 megawatts and became operational in May 2001. We sell the energy and capacity from this facility to Cheyenne Light, Fuel and Power Company under a 10-year tolling agreement.

Wygen Plant. The Wygen plant is a leased mine-mouth, coal-fired plant with a total capacity of 90 megawatts, which commenced operations in the first quarter of 2003. The Wygen plant is substantially identical in design to our Neil Simpson II facility, completed in 1995. The plant runs 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 was built with the latest available environmental control technology. The majority of the power from the facility is under long-term unit contingent capacity and energy sales contracts, under which delivery is not required during plant outages. We have contracts to sell 60 megawatts of unit contingent capacity from this plant to Cheyenne Light, Fuel and Power Company with a term of 10 years and 20 megawatts of unit contingent capacity and energy to the Municipal Energy Agency of Nebraska for a term of 10 years.

Ontario Cogeneration Facility. Ontario Cogeneration Company is a 12 megawatt, gas-fired power plant in Ontario, California, which we currently operate as a baseload plant. Electrical output from the plant is subject to a 25-year power purchase agreement with Southern California Edison, which expires in January 2010. The project also sells all of its steam production to Sunkist Growers, Inc. under a five-year agreement, which terminates in November 2007.

Harbor Cogeneration Facility. Harbor Cogeneration, a gas-fired plant located in Wilmington, California, is currently being operated as a peaking plant selling ancillary services and energy into the California Independent System Operator, or “CAISO,” market. Under a settlement agreement with Southern California Edison, Harbor Cogeneration receives payments pursuant to a termination payment schedule for a period ending on October 1, 2008. During 2001, we completed an expansion of the Harbor Cogeneration plant adding 18 megawatts, and in 2002, we acquired the remaining ownership interest in this plant. In December 2002, we entered into a tolling agreement pursuant to which we will sell the peaking capacity for the summer periods from 2003 through 2007. We plan to sell the remaining capacity and energy from this plant in the California market on a merchant basis.

Northeast Facilities. We currently own approximately 82 net megawatts of generating capacity in eight plants in the Northeast region, all of which are located in New York and Massachusetts.

Adirondack Hydro Development

The seven "run-of-river" hydroelectric plant interests are:

• New York State Dam, an 11.4 megawatt plant located in Waterford and Cohoes, New York;
  
• Middle Falls, a 2.3 megawatt plant located in Easton, New York;
  
• Sissonville, a 3.0 megawatt plant located in Potsdam, New York;

• Warrensburg, a 2.9 megawatt plant located in Warrensburg, New York;
  
• Hudson Falls, a 41.9 megawatt plant located in Moreau, New York;
  
• South Glens Falls, a 13.9 megawatt plant located in South Glens Falls, New York; and
  
• Fourth Branch, a 3.4 megawatt plant located in Waterford, New York.

The seven New York projects were initially covered by long-term power purchase contracts with Niagara Mohawk Power Corporation for all or most of their output. Niagara Mohawk bought out the power purchase contracts for the New York State Dam, Sissonville, Fourth Branch and Warrensburg facilities and the power from those projects is currently being sold into the New York Independent System Operator (ISO). The remaining three New York plants, Hudson Falls, South Glens Falls and Middle Falls, continue to operate under long-term power purchase agreements with Niagara Mohawk.

Pepperell Facility. The Pepperell facility is a 40 megawatt gas-fired combined-cycle plant located in Pepperell, Massachusetts. The plant sells merchant wholesale energy into the New England ISO.

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, with a total net capacity of approximately 24 megawatts.

Natural Gas and Crude Oil Production

Our oil and gas exploration and production segment operates approximately 384 oil and gas wells, all of which are located in Wyoming, Colorado and Nebraska. 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 440 wells located in California, Montana, Louisiana, Colorado, North Dakota, Texas, Wyoming, Oklahoma and offshore in the Gulf of Mexico. In addition, we have accumulated significant acreage in the Rocky Mountain region, which we plan to utilize for oil and gas exploration.

As of December 31, 2002, we held proved reserves of 4.9 million barrels of oil and 28.5 billion cubic feet of natural gas, with approximately 63 percent of current production consisting of natural gas.

In October 2002, we entered into a definitive merger agreement with Mallon Resources Corporation pursuant to which Mallon would become our wholly-owned subsidiary. Mallon is an independent energy company engaged in oil and natural gas exploration, development and production primarily in the San Juan Basin of New Mexico. The merger was completed on March 10, 2003. We expect the merger to double our existing oil and gas reserves on a BCFE , or billion cubic feet equivalent basis, and to increase our production by approximately 50 percent over current levels.

Coal Mining

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, is located in the Powder River Basin, one of the largest coal reserves in the United States. We produced approximately 4.1 million tons of coal in 2002. 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, 2002, we had coal reserves of 272.8 million tons, enough to satisfy present contracts for approximately 60 years.

Substantially all of our coal production is currently sold under long-term contracts to Black Hills Power, Inc., our electric utility, and to PacifiCorp. We have an additional contract to provide approximately 500,000 tons of coal per year to the Wygen plant, which commenced operations in the first quarter of 2003. We also expect to increase our coal production to supply:

• additional mine-mouth generating capacity of up to 500 megawatts at the same site as the Wygen plant, which is in the early stages of development; and
  
• future sales of coal to rail-served customers.

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 PacifiCorp for its 80 percent interest in the Wyodak plant is determined by a coal supply agreement terminating in 2022.

Energy Marketing and Transportation

We market natural gas and crude oil in specific regions of the United States. We offer physical and financial wholesale energy 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, energy marketers and retail gas users. Our average daily marketing volumes for the year ended December 31, 2002 were approximately 1.1 million MMBtu, or British thermal units of gas and 57,000 barrels of oil.

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

Gas Marketing. Our natural gas marketing operations are headquartered in Golden, Colorado, with a satellite office in Calgary, Alberta, Canada. We focus primarily on marketing of natural gas to wholesale end users and on producer marketing services. Producer marketing services include purchases of wellhead gas and risk transfer and hedging products for gas producers in the Rocky Mountain region. Our gas marketing efforts are concentrated in the Rocky Mountain, western and mid-continent regions of the United States 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 headquartered in Houston, Texas and are concentrated primarily in Texas, Oklahoma and Louisiana. Our crude oil marketing business specializes in providing independent crude oil producers with marketing and transportation services to market their crude oil production to end use markets. In addition, we own and operate the Millennium Pipeline, a 200-mile pipeline which has a capacity of approximately 65,000 barrels of oil per day and transports imported crude oil from Beaumont, Texas to Longview, Texas, a transfer point to connecting carriers. We also own Millennium Terminal Company, L.P., which leases 1.1 million barrels of crude oil storage connected to the Millennium Pipeline at the Oil Tanking terminal in Beaumont.

In July 2002, we purchased the 190-mile long Kilgore Pipeline System. The Kilgore Pipeline System has a capacity of up to 35,000 barrels per day and transports crude oil from the Kilgore, Texas region south to Houston, Texas, which is a transport point to connecting carriers. In addition, the system has approximately 400,000 barrels of crude oil storage at Kilgore and 375,000 barrels of storage at the Texoma Tank Farm located in Longview, Texas.

Electric Utility

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 our capital expenditures, dividends, and overall performance and growth.

Distribution and Transmission

Our electric utility distribution and transmission businesses serve approximately 60,000 electric customers, with an electric transmission system of 447 miles of high voltage lines and 514 miles of lower voltage lines. In addition, we jointly own 43 miles of high voltage lines with Basin Electric Cooperative. 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:

• We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2002 was comprised of 30 percent commercial, 24 percent residential, 17 percent contract wholesale, 15 percent wholesale off-system, 13 percent industrial and 1 percent municipal sales and other revenue. Approximately 70 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.
  
• In 1999, the South Dakota Public Utilities Commission extended our previous retail rate freeze until January 1, 2005. The rate freeze preserves our low-cost rate structure for our retail customers at levels below the national average 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.
  
• 15 percent of our electric revenues for the year ended December 31, 2002 consisted of off-system and short-term contract wholesale sales. Although the demand for power in the western markets has eased from the record levels seen in the first half of 2001, we expect increases in the volume of our off-system sales in the future due to demand growth in the Rocky Mountain region and the availability of 40 megawatts of gas-fired generating capacity which we added in 2002.

• Our system is capable of connecting to either the eastern or western transmission systems, which provides us with access between the WECC region and the Mid-Continent Area Power Pool, or “MAPP” region. This allows us the opportunity to improve system reliability by adding voltage support and take advantage of power price differentials between the two electric grids. We are able to interconnect up to 80 megawatts of our generation into the MAPP. Alternatively, we can serve up to 80 megawatts of our load from the MAPP region. The available transmission capacity of the MAPP transmission system determines how much of this 80 megawatts can be served from the eastern interconnection. We are proceeding with the construction of an AC-DC-AC transmission tie which is expected to be completed in late third quarter, or early fourth quarter of 2003. The transmission tie will provide us with additional load support for our utility customers and increase our ability to buy or sell electric power.
  
• We have firm transmission access to deliver up to 55 megawatts of power on PacifiCorp’s system to wholesale customers in the western region during 2003, scheduled to decline to 50 megawatts in 2004.

Power Sales Agreements

We sell approximately 46 percent of our utility’s current load under long-term contracts. Our key contracts include a contract with Montana-Dakota Utilities Company, expiring in 2007, 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 area and are treated as firm native load. In May 2001, we began selling 30 megawatts of firm capacity and energy to Public Service Company of Colorado for a period through 2004. For the 10-year period beginning with the completion of the Wygen facility in 2003, our utility and our power generation segment will each provide 20 megawatts of unit contingent energy and capacity to the Municipal Energy Agency of Nebraska.

Regulated Power Plants and Purchased Power

Our utility’s electric load is served by coal-, oil- and natural gas-fired generating units providing 435 megawatts of generating capacity all of which is located in South Dakota and Wyoming, and from the following purchased power and capacity contracts with PacifiCorp:

• a power sales agreement expiring in 2023, involving the purchase by us of 55 megawatts of baseload power in 2003, which is scheduled to decline to 50 megawatts in 2004 and thereafter; and
  
• 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.

Since 1995, our utility has been a net producer of energy. Our utility reached its peak system load of 392 megawatts in August 2001. 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:

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. The plant purchases coal from our Wyodak mine, which is 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 placed 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 placed into service from 1977 to 1979, and operate as peaking units.

Lange CT. The Lange Combustion Turbine is a wholly owned 40 megawatt gas-fired plant located near Rapid City, South Dakota. The plant was placed into service in 2002 and provides peaking capacity and voltage support for the area.

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 placed into service in 1969. Neil Simpson II has a capacity of 91.0 megawatts and was placed into service in 1995. These plants operate as baseload facilities, and are mine-mouth coal-fired plants, receiving their coal directly from our Wyodak mine.

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 placed into service in 2000, and provides peaking capabilities.

Osage. The Osage plant is a wholly owned coal-fired plant in Osage, Wyoming with a total capacity of 34.5 megawatts and was placed into service from 1948 to 1952. This plant has three turbine generating units, and operates as a baseload plant. The plant purchases coal from our Wyodak mine, which is delivered by truck.

Wyodak. Wyodak is a 362 megawatt mine mouth coal-fired plant owned jointly by PacifiCorp and us and in which we hold 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 placed into service in 1978, and operates as a baseload plant.

Communications

Our communications group, which primarily operates through our subsidiary, Black Hills FiberCom, was formed to provide state-of-the-art broadband telecommunications services to the 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 242-mile inter- and intra-city fiber optic network and currently operate 818 miles of two-way interactive hybrid fiber coaxial or "HFC" cable. We bundle these services into value packages with a single consolidated bill for all of these services. In the future we expect to integrate electricity into the package if deregulation occurs.

We introduced our broadband communications services to the Rapid City and northern Black Hills areas in November 1999. As of December 31, 2002, we were serving 21,700 residential customers and 3,061 business customers.

The construction of our initial infrastructure build-out, which covers Rapid City and the northern Black Hills region, was completed in 2002. Emphasis now will be focused on efficiencies, both internal to our communications group and those that can be realized through our strategy as a "super local" service company.

Competition

The independent power, fuel production and energy 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.

FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses, and deregulation initiatives in a number of states may encourage further disaggregation. However, the pace of restructuring slowed significantly following public and governmental reactions to issues associated with deregulation efforts in California and the collapse of its wholesale electric energy market.

In addition, Congress is considering various legislative proposals 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. 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 strong competition from several companies, including Qwest Corporation, Rapid City's incumbent local exchange carrier and 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 products and services and our ability to offer an attractive package of bundled products.

Risk Management

Our business operations require effective management of price, counterparty performance and operational risks. Price risk arises from 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 is the risk that we will be unable to perform on our contractual obligations to our counterparties. We have implemented controls to mitigate each of these risks.

Our energy 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 and procedures. These policies and procedures specify maximum price risk exposure levels within which each respective marketing company must operate. They establish relatively low exposure levels and generally prohibit speculative trading strategies. These policies are established and approved by our board of directors, reviewed on a regular basis and monitored as described below.

We maintain a working risk management committee that oversees each of our marketing companies, and a credit committee at the parent company level. The risk management committee focuses on implementation of risk management procedures and on monitoring compliance with established policies. The credit committee monitors credit exposure levels and reviews compliance with established credit policies. Our Vice President-Risk is responsible for overseeing these functions.

We limit the exposure of our parent holding company, Black Hills Corporation, to energy marketing risks by maintaining separate credit facilities within each of our energy marketing companies. These credit facilities have security interests solely against the assets of the respective marketing company. In addition, we limit the number and amount of any parent guarantees for the marketing companies.

A 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 generating capabilities exceed our anticipated load requirements plus a required reserve margin.

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 such requirements. We strive to comply with the terms of all such laws, regulations, permits and licenses and believe that all of our operating plants are in material compliance with all such applicable requirements.

Energy Regulation

Federal Power Act. The Federal Power Act gives FERC exclusive ratemaking 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. 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 from the state regulators. All of our subsidiaries that would otherwise be treated as public utilities are currently treated as EWGs under the Energy Policy Act or as Qualifying Facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA). All of our EWGs 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, we would most likely be required to file, and obtain FERC acceptance of, cost-based rate schedules for our affected 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.

PURPA. The enactment of PURPA in 1978 provided incentives for the development of QFs which were basically cogeneration facilities and small power production facilities that utilized certain alternative or renewable fuels. QF status conveys two primary benefits. First, regulations under PURPA exempt QFs from PUHCA, most provisions of the Federal Power Act and the state laws concerning rates, and financial and organizational regulations of electric utilities. Second, FERC's regulations under PURPA require that (1) electric utilities purchase electricity generated by QFs at a price based on the purchasing utility's full avoided cost of producing power, (2) the electric utilities must sell back-up, interruptible, maintenance and supplemental power to the QF on a non-discriminatory basis, and (3) the electric utilities must interconnect with any QF in its service territory, and, if required, transmit power if they do not purchase it. We endeavor to acquire, develop and operate our QFs in a manner that minimizes the risk of those plants losing their QF status. However, if a facility were to lose QF status, we could attempt to avoid regulation under PUHCA by qualifying the project as an EWG.

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.

Air Quality. Our Neil Simpson II, Neil Simpson CT, Gillette CT, Arapahoe, Valmont, Fountain Valley, Lange CT and Wyodak plants are all subject to Title IV of the Clean Air Act, which requires certain fossil-fuel-fired combustion devices to hold sulfur dioxide "allowances" for each ton of sulfur 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 all units subject to Title IV through 2032 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 sulfur dioxide emissions through the use of low sulfur fuels, installation of "back end" control technology and if necessary, 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 subsidiary, Black Hills Ontario, the operator of a 12 megawatt natural-gas fired cogeneration facility located in Ontario, California, projects that it will need to continue purchasing NOx allowances for all future compliance years. Annual purchases are anticipated to be approximately 30,000 allowances. There is currently significant volatility in the price and supply of Regional Clean Air Incentives Market (RECLAIM) NOx allowances; although the South Coast Air Quality Management District (SCAQMD) has proposed a revision to its regulations to stabilize the RECLAIM market, it is unclear whether these rules will mitigate Black Hills Ontario's potential exposure for its projected allowance shortfall. Accordingly, no assurance can be given at this time regarding whether RECLAIM NOx allowances will be available for purchase to allow Black Hills Ontario to comply with RECLAIM requirements for the year ended June 30, 2003, or, if allowances are available, as to the cost of those allowances.

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," known as BART. These sources would be required to implement BART within five years after the EPA approved state plans adopted to combat visibility impairment. Subsequent litigation has removed EPA's requirement mandating that states adopt and impose BART requirements; however, it remains an option for states to use in addressing visibility impairment. Management believes the only existing plant which may be required to comply with the BART requirements is our Neil Simpson I plant in Wyoming. At the present time, the state of Wyoming is moving away from BART and is requesting legislative approval for an emissions trading program. Legislative approval will be followed by regulation development and therefore applicability and subsequent requirements are uncertain at this time. We are aware that currently, states are required to submit their visibility impairment plans to EPA between 2004 and 2008 and that compliance is due within five years of EPA approval. Management believes that any capital expenditures associated with future compliance requirements would not have a material adverse effect on our financial position 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 are in the process of or have submitted Title V permit applications and either have received or are in the process of receiving 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 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. 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. 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 similar 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 December 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, between 2008 and 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 legislative developments on the state level related to controlling greenhouse gas emissions have occurred, we are not aware of any similar 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, these 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, or 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. All of our facilities required to have NPDES permits have those permits in place and are in compliance with discharge limitations. There are no proposed regulations that we are aware of that will have a significant impact on our operations.

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. While management does not believe that any substances from our solid waste disposal activities will pollute underground water, we can give no assurance that pollution will not occur over time. In this event, we could experience material costs to mitigate any resulting damages. Agreements in place require PacifiCorp 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 any regulator 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 our entire Wyodak coal 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.

Based on extensive reclamation studies, we have accrued approximately $18.5 million on our accompanying Consolidated Balance Sheets for these reclamation costs. No assurance can be given that additional requirements in the future will not be imposed that would cause an unexpected material increase in reclamation costs.

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.

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 $0.5 million, of which amount $0.4 million 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. In 2002, the South Dakota Department of Environment and Natural Resources permanently closed numerous monitoring wells which showed no contamination for several years.

PCBs. Under the federal Toxic Substances Control Act, the EPA has issued regulations that control the use and disposal of polychlorinated biphenyls, or 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 a 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:

• requiring permits for the drilling of wells;
  
• maintaining bonding requirements in order to drill or operate wells;
  
• submitting and implementing spill prevention plans;
  
• submitting notification relating to the presence, use and release of certain contaminants incidental to oil and gas operations;
  
• 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
  
• 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 with approximately 47,000 square feet, of which we occupy approximately 75 percent and lease the remainder to others. We also own two additional office buildings consisting of approximately 48,000 square feet and two warehouse buildings consisting of approximately 35,700 square feet. All of these properties are located in Rapid City, South Dakota.

Employees

At December 31, 2002, we had 840 employees, approximately 294 of whom are employed in our utility business, 253 of whom are employed in our integrated energy businesses, 233 of whom are employed in our communications business and 60 of whom are employed at the corporate level.

Approximately one-half of our utility employees are covered by a collective bargaining agreement with the International Brotherhood of Electrical Workers, which expires on March 31, 2006. We have experienced no labor stoppages or significant labor disputes at our facilities.

RISK FACTORS

The following specific risk factors and other risk factors that we discuss in our periodic reports from time to time should be considered for a better understanding of our Company. These factors and other matters discussed herein are important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward looking statements included elsewhere in this document.

Our agreements with counterparties that have recently experienced downgrades in their credit ratings expose us to the risk of counterparty default, which could adversely affect our cash flow and profitability.

We are exposed to credit risks in our generation, distribution and energy marketing operations. Credit risk includes the risk that counterparties that owe us money or energy will breach their obligations. In recent months, a substantial number of energy companies have experienced downgrades in their credit ratings, some of which serve as our counterparties from time to time. In particular, the credit ratings of the senior unsecured debt of Public Service Company of Colorado, Nevada Power Company and Allegheny Energy Supply Company (AESC), counterparties under power purchase agreements with our subsidiaries, have recently been downgraded by one or more rating agencies. The credit ratings of Nevada Power Company and AESC were downgraded to non-investment grade status. In addition, we have project level financing arrangements in place that provide for the potential acceleration of payment obligations in the event of nonperformance by a counterparty under related power purchase agreements. If these or other counterparties fail to perform their obligations under their respective power purchase agreements, our financial condition and results of operations may be adversely affected. We may not be able to enter into replacement power purchase agreements on terms as favorable as our existing agreements, or at all, in which case we would sell the plant's power on a merchant basis.

We have substantial indebtedness, much of which is short-term. We will require significant amounts of debt or equity capital in order to refinance or repay maturing indebtedness as it becomes due and to grow our business. Our future access to these funds is not certain, and our inability to access funds in the future could adversely affect our liquidity and our ability to implement our business strategy.

As of December 31, 2002, we had total consolidated indebtedness of approximately $983 million, of which approximately $425 million will mature before December 31, 2004. Our substantial indebtedness may:

• limit our ability to borrow funds or increase the cost to borrow additional funds;
  
• hinder our ability to pay dividends at the current rate;
  
• require us to dedicate a substantial portion of our cash flow from operations to pay our debt, which would reduce funds available for us to finance our current operations and for our future business opportunities;
  
• have a negative impact on our credit ratings;

• increase our vulnerability to adverse economic and industry conditions;
  
• place us at a competitive disadvantage compared to competitors having less debt; or
  
• require us to sell assets in order to repay debt.

Some of our debt agreements contain restrictive covenants, including restrictive financial covenants pertaining to our recourse debt-to-capitalization ratio, fixed charge coverage ratio and total level of equity. If we fail to maintain these specified ratios and levels, our ability to borrow funds could be further limited. If our failure to maintain those ratios and levels were to persist, the creditors under those debt agreements could eventually require us to immediately repay the entire balance of those outstanding loans.

Our credit ratings have recently been lowered and could be further lowered in the future. If this were to occur, our access to capital and our cost of capital and other costs would be negatively affected.

Our issuer credit rating was recently downgraded to Baa3 by Moody's Investor Services, Inc., or Moody's. Any further reduction in our ratings by Moody's or Standard & Poor's Rating Service, particularly a reduction to a level below investment-grade, could adversely affect our ability to refinance or repay our existing debt and to complete new financings.

In addition, a further downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations, including borrowings made under our $200 million three-year and $195 million 364-day revolving credit facilities, our $35 million term loan, our $50 million project credit agreement, and our $27.5 million and $4.5 million secured financings. A downgrade in our credit rating would also result in an increase in the operating lease costs related to our Wygen plant lease.

A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions, particularly transactions pertaining to our energy marketing activities.

We must rely on cash from our subsidiaries to make debt payments. There may be changes in the regulatory environment that restrict our utility's ability to pay dividends to us.

We are a holding company and thus our investments in our subsidiaries are our primary assets. Consequently, our operating cash flow and our ability to service our indebtedness depends upon the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary's ability to pay dividends to us depends on any contractual or regulatory restrictions that may be applicable to it, which may include requirements to maintain minimum levels of cash or working capital.

Our utility is regulated by various state utility commissions which generally possess broad powers to ensure that the needs of the utility customers are being met. As a result of the energy crisis in California and the financial troubles at a number of energy companies, some state utility commissions may seek to impose restrictions on the ability of our utility subsidiary to pay dividends or make advances to us. If successful, this could materially and adversely affect our ability to meet our financial obligations.

Geopolitical tensions, including the armed conflict in Iraq, may impair our ability to raise capital and limit our growth.

An extended conflict with Iraq or an increase in tensions with the government of North Korea could temporarily disrupt capital markets and make it more costly or temporarily impossible for us to raise capital, thus hampering the implementation of our growth strategy. In the past, geopolitical events, including the uncertainty associated with the Gulf War in 1991 and the terrorist attacks of September 11, 2001, have been associated with general economic slowdowns. A prolonged conflict or stalemate arising from current geopolitical tensions or other factors could retard economic growth and reduce demand for the power and fuel products that we produce or market, which could adversely affect our earnings.

Our rate freeze agreement with the South Dakota Public Utilities Commission, which prevents us, absent extraordinary circumstances, from passing on to our South Dakota retail customers cost increases we may incur during the rate freeze period, could decrease our operating margins.

Our rate freeze agreement with the South Dakota Public Utilities Commission is effective until January 1, 2005. We may not file for any increase in our rates or invoke any fuel and purchased power adjustment tariff which would take effect during the freeze period, except in extraordinary circumstances. Because we are generally unable to increase our rates, our utility's historically stable returns could be threatened by plant outages, machinery failure, increases in purchased power costs over which we have no control, acts of nature, acts of terrorism or other unexpected events that could cause our operating costs to increase and our operating margins to decline. Moreover, in the event of unexpected plant outages or machinery failures, we may be required to purchase replacement power in wholesale power markets at prices which exceed the rates we are permitted to charge our retail customers.

Because prices for our products and services and other operating costs for our business are volatile, our revenues and expenses may fluctuate.

A substantial portion of our growth in net income in recent years is attributable to increasing wholesale electricity and natural gas sales into a robust market. The prices of energy products in the wholesale power markets have declined significantly since the first half of 2001. Power prices are influenced by many factors outside our control, including:

• fuel prices;
  
• transmission constraints;
  
• supply and demand;
  
• weather;
  
• economic conditions; and
  
• the rules, regulations and actions of the system operators in those markets.

Moreover, unlike most other commodities, electricity cannot be stored and therefore must be produced concurrently with its use. As a result, wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable.

The success of our oil and gas operations will depend somewhat upon the prevailing market prices of oil and natural gas. Historically, oil and natural gas prices and markets have also been volatile, and they are likely to continue to be volatile in the future. A decrease in oil or natural gas prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. A decline in fuel price volatility could also affect our revenues and returns from energy marketing, which historically tend to increase when markets are volatile.

Our broadband communications business is subject to significant competition for its services and to rapid technological change.

Our communications group, which provides a full suite of communication services, faces strong competition for its services from the incumbent local exchange carrier and from long distance providers, Internet service providers, the incumbent cable television provider and others.

Our ability to recover our capital investment is dependent on our ability to sustain our customer base and is subject to the risk that technological advances may render our network obsolete. If we determine that we will be unable to recover our investment, we would be required to take a non-cash charge to earnings in an amount that could be material in order to write down a portion of our investment in our broadband communications business.

Construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve significant risks which could lead to lost revenues or increased expenses.

The construction, expansion, refurbishment and operation of power generating and transmission and resource recovery facilities involve many risks, including:

• the inability to obtain required governmental permits and approvals;
  
• the unavailability of equipment;
  
• supply interruptions;
  
• work stoppages;
  
• labor disputes;
  
• social unrest;
  
• weather interferences;
  
• unforeseen engineering, environmental and geological problems; and
  
• unanticipated cost overruns.

The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses, higher maintenance costs and penalties. While we maintain insurance obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance, and our rights under warranties or performance guarantees may not be adequate to cover lost revenues, increased expenses or liquidated damage payments.

Our power project development, expansion and acquisition activities may not be successful, which would impair our ability to execute our growth strategy.

The growth of our independent power business through development, expansion and acquisition activities is critical to our future growth. We may not be able to continue to develop attractive opportunities or to complete acquisitions or development projects we undertake. Factors that could cause our activities to be unsuccessful include:

• competition;
  
• changes in federal or state laws and regulations;
  
• our inability to negotiate acceptable acquisition, construction, fuel supply or other material agreements;
  
• our inability to obtain financing on acceptable terms;
  
• our inability to obtain required governmental permits and approvals;
  
• capital market conditions; and
  
• our inability to successfully integrate any businesses we acquire.

Estimates of the quantity and value of our proved reserves may change materially due to numerous uncertainties inherent in estimating oil and natural gas reserves.

There are many uncertainties inherent in estimating quantities of proved reserves and their values. The process of estimating oil and natural gas reserves requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretations and judgment, and the assumptions used regarding quantities of recoverable oil and gas reserves and prices for oil and natural gas. Actual prices, production, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those assumed in our estimates, and these variances may be significant. Any significant variance from the assumptions used could result in the actual quantity of our reserves and future net cash flow being materially different from the estimates in our reported reserves. In addition, results of drilling, testing and production and changes in oil and natural gas prices after the date of the estimate may result in substantial upward or downward revisions.

Our business is subject to substantial governmental regulation and permitting requirements as well as on-site environmental liabilities we assumed when we acquired some of our facilities. We may be adversely affected by any future inability to comply with existing or future regulations or requirements or the potentially high cost of complying with such requirements.

Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally are required to obtain and comply with a wide variety of licenses, permits and other approvals in order to operate our facilities. In the course of complying with these requirements, we may incur significant additional costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, and future changes in laws and regulation may have a detrimental effect on our business.

In acquiring some of our facilities, we assumed on-site liabilities associated with the environmental condition of those facilities, regardless of when such liabilities arose and whether known or unknown, and in some cases agreed to indemnify the former owners of those facilities for on-site environmental liabilities. We strive at all times to be in compliance with all applicable environmental laws and regulations. However, steps to bring our facilities into compliance, if necessary, could be expensive, and thus could adversely affect our results of operation and financial condition. Furthermore, with the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the assets we operate, we expect our environmental expenditures to be substantial in the future.

One of our subsidiaries may incur material liabilities due to a prior owner's potential violation of regulations for "qualifying facilities" under PURPA.

In August 2001, we purchased a partnership interest in the 53 megawatt Las Vegas Cogeneration Facility from an affiliate of Enron. The partnership is called Las Vegas Cogeneration, L.P. The prior owner certified to us and to relevant governmental authorities that the facility complied with all regulations necessary to obtain and maintain "qualifying facility" status under PURPA. Qualifying facilities are allowed to sell their output to electric utilities at "avoided cost" rates, which are usually higher than prevailing market-based rates. The prior owner contracted with Nevada Power Company to sell 45 megawatts of the facility's output during the periods of peak electricity consumption at avoided cost rates. In connection with acquiring the facility, we assumed this contract.

Recently FERC issued an order announcing an investigation to determine whether Enron's ownership of the Las Vegas Cogeneration Facility violated the qualifying facility regulations under PURPA. In addition, the SEC recently issued an initial decision concluding that Enron is an electric utility and is thus not exempt from regulations under PUHCA, that, among other things, prohibit electric utilities from owning more than 50 percent of a qualifying facility. Enron is appealing this decision.

The FERC investigation does not relate to the 224 megawatt gas-fired facility owned and operated by Las Vegas Cogeneration II, LLC, and located on the same site in North Las Vegas, Nevada. This facility is not now, and never was certified as a qualifying facility under PURPA.

If FERC determines that Enron violated the qualifying facility rules with respect to the Las Vegas Cogeneration Facility, we, as a partner in the entity that now owns that facility, could be liable for any refunds, fines or other penalties FERC imposes. We could also be subject to additional liabilities resulting from third party claims. We have the right to seek indemnification from the prior owner. While the prior owner does not appear among the Enron subsidiaries and affiliates currently in bankruptcy, the Enron bankruptcy could impair our ability to enforce a claim for indemnification. Because FERC has only recently begun its investigation, we cannot predict the outcome of FERC's investigation.

We face potential claims related to forest fires in South Dakota in 2001 and 2002.

In September 2001 a fire occurred in the southwestern Black Hills. It is alleged that the fire occurred when a high voltage electrical span maintained by our electric utility subsidiary broke and electrical arcing from the severed line ignited dry grass. The fire burned approximately 10,000 acres of land owned by the Black Hills National Forest, the Oglala Sioux Tribe and other private landowners. The State of South Dakota initiated litigation against us in the Seventh Judicial Circuit Court, Fall River County, South Dakota, on or about January 31, 2003. The complaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages is asserted with respect to the claim for injury to timber. It is expected that substantially similar claims will be asserted against us by the United States Forest Service. Our investigation into the cause and origin of the fire is still pending. The total amount of damages claimed by the State of South Dakota is not specified in the complaint. We have denied all claims and will vigorously defend this matter.

In June 2002, the Grizzly Gulch forest fire damaged approximately 11,000 acres of private and governmental land located near Deadwood and Lead, South Dakota. The fire destroyed approximately 20 structures and caused the evacuation of the cities of Lead and Deadwood for approximately 48 hours.

The cause of the Grizzly Gulch fire was investigated by the State of South Dakota. Alleged contact between power lines owned by our electric utility subsidiary and undergrowth was implicated as the cause. We have initiated our own investigation into the cause of the fire, including the hiring of expert fire investigators and that investigation is continuing.

We have been notified of potential private civil claims for property damage and business loss. In addition, the State of South Dakota initiated a civil action in the Seventh Judicial Circuit Court, Pennington County, South Dakota, seeking recovery of damages for fire suppression, reclamation and remediation costs, and treble damages for injury to trees. The United States government initiated a civil action in U.S. District Court, District of South Dakota, asserting similar claims. Neither the State of South Dakota nor the United States specified the amount of their alleged damages. If it is determined that power line contact was the cause of the fire and that we were negligent in the maintenance of those power lines, we could be liable for resultant damages.

Although we cannot predict the outcome of our investigations or the viability of potential claims based on information currently available, management believes that any such claims, if determined adversely to us, will not have a material adverse effect on our financial condition or results of operations.

Ongoing changes in the United States utility industry, such as state and federal regulatory changes, a potential increase in the number of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.

The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:

• consumer demands;
  
• technological advances;
  
• deregulation;
  
• greater availability of natural gas-fired power generation; and
  
• other factors.

FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses, and deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry.

In addition, the independent system operators who oversee most of the wholesale power markets have in the past imposed, and may in the future continue to impose, price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of those generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

ITEM 3.  LEGAL PROCEEDINGS

Hell Canyon Fire

In September 2001 a fire occurred in the southwestern Black Hills. It is alleged that the fire occurred when a high voltage electrical span maintained by our electric utility subsidiary broke and electrical arcing from the severed line ignited dry grass. The fire burned approximately 10,000 acres of land owned by the Black Hills National Forest, the Oglala Sioux Tribe and other private landowners. The State of South Dakota initiated litigation against the Company in the Seventh Judicial Circuit Court, Fall River County, South Dakota, on or about January 31, 2003. The complaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages is asserted with respect to the claim for injury to timber. It is expected that substantially similar claims will be asserted against the Company by the United States Forest Service. Our investigation into the cause and origin of the fire is still pending. The total amount of damages claimed by the State of South Dakota is not specified in the complaint. We have denied all claims and will vigorously defend this matter the timing or outcome of which is uncertain.

Although we cannot predict the outcome of our investigation or the viability of potential claims based on information currently available, management believes that any such claims, if determined adversely to us, will not have a material adverse effect on our financial condition or results of operations.

Grizzly Gulch Fire

On June 29, 2002, a forest fire began near Deadwood, South Dakota. Before being contained more than eight days later, the fire consumed approximately 11,000 acres of public and private land, mostly consisting of rugged forested areas. The fire destroyed approximately 20 structures. There were no reported personal injuries. In addition, the fire burned to the edge of the City of Deadwood, forcing the evacuation of the City of Deadwood and the adjacent City of Lead, South Dakota. These communities are active in the tourist and gaming industries. Individuals were ordered to leave their homes and businesses were closed for a short period of time. On July 16, 2002, the State of South Dakota announced the results of its investigation of the cause and origin of the fire. The State asserted that the fire was caused by tree encroachment into and contact with a transmission line owned and maintained by our electric utility subsidiary.

On September 6, 2002, the State of South Dakota commenced litigation against the Company, in the Seventh Judicial Circuit Court, Pennington County, South Dakota. The complaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages is asserted with respect to the claim for injury to timber. The total amount of alleged damages is not specified.

On March 3, 2003, the United States of America filed a similar suit against the Company, in the United States District Court, District of South Dakota, Western Division. The federal government complaint likewise seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A similar claim for treble damages is asserted with respect to the claim for injury to timber. The total amount of alleged federal damages is not specified.

We are completing our own investigation of the fire cause and origin and have requested access to the materials that form the basis for the assertions of state and federal fire investigators. Our investigation is not complete, but based on information currently available, we expect to deny all claims and vigorously defend any and all claims brought by governmental or private parties.

Although we cannot predict the outcome of our investigation or the viability of potential claims based on information currently available, management believes that any such claims, if determined adversely to us, will not have a material adverse effect on our financial condition or results of operations.

FERC Investigation

In August 2001, we purchased a partnership interest in the 53 megawatt Las Vegas I power plant from an affiliate of Enron. The partnership is called Las Vegas Cogeneration, L.P. The prior owner certified to us and to relevant governmental authorities that the facility complied with all regulations necessary to obtain and maintain "qualifying facility" status under PURPA. Qualifying facilities are allowed to sell their output to electric utilities at "avoided cost" rates, which are usually higher than prevailing market-based rates. The prior owner contracted with Nevada Power Company to sell 45 megawatts of the facility's output during the periods of peak electricity consumption at avoided cost rates. In connection with acquiring the facility, we assumed this contract.

Recently FERC issued an order announcing an investigation to determine whether Enron's ownership of the Las Vegas I plant violated the qualifying facility regulations under PURPA. In addition, the SEC recently issued an initial decision concluding that Enron is an electric utility and is thus not exempt from regulations under PUHCA, that, among other things, prohibit electric utilities from owning more than 50 percent of a qualifying facility. Enron is appealing this decision.

The FERC investigation does not relate to the 224 megawatt gas-fired Las Vegas II power plant owned and operated by Las Vegas Cogeneration II, LLC and located on the same site in North Las Vegas, Nevada. This plant is not now, and never was certified as a qualifying facility under PURPA.

If FERC determines that Enron violated the qualifying facility rules with respect to the Las Vegas I plant, we, as a partner in the entity that now owns that plant, could be liable for any refunds, fines or other penalties FERC imposes. We could also be subject to additional liabilities resulting from third party claims. We have the right to seek indemnification from the prior owner. While the prior owner does not appear among the Enron subsidiaries and affiliates currently in bankruptcy, the Enron bankruptcy could impair our ability to enforce a claim for indemnification. Because FERC has only recently begun its investigation, we cannot predict the outcome of FERC's investigation. However, based upon information currently available, we do not believe that any refunds, fines or penalties resulting from the investigation will adversely affect our financial condition or results of operations.

Other Proceedings

We have received a request for information from the U.S. Commodity Futures Trading Commission (CFTC) relating to its industry-wide investigation of trading practices of energy and power marketing firms. We will provide information to the CFTC regarding our trading and trade reporting activities.

In addition to the above proceedings, we are involved in numerous legal proceedings, claims and litigation in the ordinary course of business. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect our consolidated financial position or results of operations.

There are currently no pending material legal proceedings to which an officer or director is a party or has a material interest, that is adverse to us or our subsidiaries. There are also no material administrative or judicial proceedings arising under environmental quality or civil rights statutes pending or known to be contemplated by governmental agencies to which we are or would be a party.

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

No matter was submitted to a vote of security holders during the fourth quarter of 2002.

PART II

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

Our common stock is traded on The New York Stock Exchange under the symbol BKH. As of January 31, 2003, we had 5,350 common shareholders of record and approximately 16,000 beneficial owners, representing all 50 states, the District of Columbia and 8 foreign countries.

We have paid a regular quarterly cash dividend each year since the incorporation of our predecessor company in 1941 and expect to continue paying a regular quarterly dividend for the foreseeable future. At its January 2003 meeting, our board of directors raised the quarterly dividend to $0.30 per share, equivalent to an annual dividend of $1.20 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our credit facilities and our future business prospects. Our credit facilities contain restrictions on the payment of cash dividends, the most restrictive of which prohibit the payment of cash dividends if our fixed charge coverage ratio, as calculated in our credit agreements, is less than 1.5:1.0, our recourse leverage ratio exceeds 0.65:1.00 or our consolidated net worth does not exceed the sum of $425 million and 50 percent of our aggregate consolidated net income since April 1, 2002.

Quarterly dividends paid and the high and low common stock prices, as reported in the New York Stock Exchange Composite Transactions, for the last two years were as follows:

ITEM 6. SELECTED FINANCIAL DATA

*Excludes the non-cash acquisition of Indeck Capital, Inc.

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

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
                OPERATIONS AND QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a diversified energy company operating principally in the United States with three major business groups – integrated energy, electric utility and communications. Our unregulated and regulated businesses have expanded significantly in recent years. Our integrated energy group, Black Hills Energy, Inc., engages in the production of electric power through ownership of a diversified portfolio of generating plants and the sale of electric power and capacity primarily under long-term contracts, the production of coal, natural gas and crude oil primarily in the Rocky Mountain region, and the marketing and transportation of fuel products. The integrated energy group consists of four segments: power generation, oil and gas exploration and production, coal mining and energy marketing and transportation. Our electric utility, Black Hills Power, Inc., generates, transmits and distributes electricity to approximately 60,000 customers in South Dakota, Wyoming and Montana. Our communications group provides broadband telecommunication services to over 24,700 residential and business customers in Rapid City and the northern Black Hills region of South Dakota through Black Hills FiberCom, LLC.

In 2002, we discontinued operations of our coal marketing business due to difficulties in marketing our Wyodak coal from the Powder River Basin of Wyoming to East Coast markets. The non-strategic assets were sold effective August 1, 2002.

Business Strategy

Our long-term growth strategy is to add and augment revenue streams from our diverse integrated energy operations. We have implemented a balanced, integrated approach to fuel production, energy marketing and power generation, supported by disciplined risk management practices. Building on the strength of our electric utility, we have enhanced our local operations by providing broadband communications to our customers in South Dakota. Our diverse operations avoid reliance on any single element to achieve our growth objective. This diversity provides a measure of stability in volatile or cyclical periods.

Prospective Information

We continue to advance our ongoing business strategy. We expect long-term growth through the expansion of integrated, balanced and diverse competitive energy operations supplemented by the strength and stability of our electric utility and improving results from our communication business. We recognize that sustained growth requires continued capital deployment, particularly in our integrated energy operations. We strongly believe that we are strategically positioned to take advantage of opportunities to acquire and develop energy assets consistent with our prudent investment criteria and consistent with a prudent capitalization structure.

Our strategy includes the following key elements:

• grow our power generation segment by developing and acquiring power generating assets in targeted western markets and, in particular, by expanding the generation capacity of our existing sites through a strategy known as “brownfield development;"
  
• sell a large percentage of our production from new independent power projects through long-term contracts in order to secure a stable revenue stream and attractive returns;
  
• preserve our electric utility’s low-cost rate structure for our retail customers while retaining the flexibility to allocate excess generating capacity to maximize returns in changing market environments;
  
• increase our reserves of natural gas and crude oil and expand our fuel production;
  
• manage the risks inherent in energy marketing by maintaining position limits that minimize price risk exposure;
  
• conduct business with a diversified group of creditworthy counterparties;
  
• exploit our fuel cost advantages and our operating and marketing expertise to remain a low-cost power producer;
  
• increase margins from our coal production through an expansion of mine-mouth generation and increased coal sales;

• build and maintain strong relationships with wholesale energy customers;
  
• create a strong “super local” service company by capitalizing on our utility’s established market presence, relationships and customer loyalty to expand our local communications business, integrating our electric and telecommunication products around the same customer base; and
  
• organize our lines of business into retail and wholesale energy components. The retail component will consist of electric and telecommunications products in the same footprint as our electric utility exists today. The wholesale component will consist of fuel production, marketing, mid-stream assets and power production facilities.

Our integrated energy group was our largest contributor to revenue and earnings in 2002 and 2001. We expect that earnings from this group over the next few years will be driven primarily by our continued expansion in the power generation and oil and gas production segments. In October 2002, we entered into a definitive merger agreement with Mallon Resources Corporation to acquire Mallon. Mallon is an energy company engaged in oil and natural gas exploration, development and production primarily in the San Juan Basin of New Mexico. The merger was completed in March 2003 and is expected to double our oil and gas reserves, and increase our production by approximately 50 percent over current levels. Although we believe our integrated energy group will continue to grow as our largest business group, we cannot predict the price environment, regulation or growth in the energy markets.

Our electric utility’s retail business remained healthy in 2002, even though two of our largest and oldest customers, the Homestake Mining Company and Federal Beef Processors, discontinued operations in 2002. We believe that our electric utility will produce modest growth in revenue, and absent unplanned plant outages, it will continue to produce modest growth in earnings for the next several years due to the extension of our electric utility’s rate freeze until January 1, 2005. (See Rate Regulation.) We forecast firm energy sales in our retail service territory to increase over the next 10 years at an annual compound growth rate of approximately one percent, with the system demand forecasted to increase at a rate of two percent. These forecasts are derived from studies conducted by us whereby we examined and analyzed our service territory to estimate changes in the needs for electrical energy and demand over a 20-year period. These forecasts are only estimates, and the actual changes in electric sales may be substantially different. Weather deviations can also affect energy sales significantly when compared to forecasts based on normal weather. The portion of the utility’s future earnings that will result from wholesale off-system sales will depend on many factors, including native load growth, plant availability, electricity demand and commodity prices in the western markets.

Although our broadband communications business significantly increased residential and business customers in 2002, we expect it will sustain approximately $3.5 to $4.0 million in net losses in 2003, with profitability expected in 2004. The recovery of capital investment and future profitability are dependent primarily on our ability to sustain our customer base and control expenses, and is subject to the risk that technological advances may render our network obsolete. If we determine that we will be unable to recover our investment, we would be required to take a non-cash charge to earnings in an amount that could be material in order to write down a portion of our investment. While we do not anticipate being regulated in the local markets, we are unable to predict future markets, future government impositions or future economic and competitive conditions that could affect the profitability of the communications operations.

Results of Operations

Consolidated Results

Overview

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

During the second quarter of 2002, we adopted a plan to dispose of our coal marketing subsidiary, Black Hills Coal Network due primarily to difficulties in marketing our Wyodak coal from the Powder River Basin of Wyoming to midwestern and eastern coal markets. We sold the non-strategic assets effective August 1, 2002. Results of operations have been restated to reflect the discontinued operations.

2002 Compared to 2001

Consolidated income from continuing operations for 2002 was $63.2 million, compared to $87.6 million in 2001, or $2.33 per share in 2002, compared to $3.40 per share in 2001. Income (loss) from discontinued operations was $(2.6) million or $(0.10) per share in 2002 compared to $0.5 million, or $0.02 per share, in 2001. This equates to an 11.6 percent and 17.2 percent return on year-end common equity in 2002 and 2001, respectively.

The decrease in income from continuing operations was a result of a substantial decrease in prevailing prices for natural gas and wholesale electricity and in gross margins from natural gas marketing activities compared to 2001. Unusual energy market conditions existed in the first half of 2001 stemming primarily from gas and electricity shortages in the West. Approximately $1.40 per share of the 2001 income from continuing operations was attributable to the unusual market conditions that existed at the time. Average wholesale electric average peak prices at Mid-Columbia were approximately $143 per megawatt-hour in 2001 compared to approximately $24 per megawatt-hour in 2002. Average spot market gas prices in the West Coast region were approximately $7 per MMBtu in 2001 compared to $3 per MMBtu in 2002. While these factors negatively impacted income from continuing operations in 2002, they were offset in part by an increase in the production of coal, oil, gas, power generation capacity, and a decrease in the net loss at our communications business group, primarily attributable to the continued expansion of its customer base.

Consolidated revenues were $423.9 million in 2002 compared to $461.9 million in 2001. The decrease in revenues was a result of the high energy commodity prices in 2001, slightly offset by increased revenue in the communications business group and power generation segment; increased production in coal, oil and gas and increased marketing volumes.

Consolidated operating expenses decreased from $306.9 million in 2001 to $295.9 million in 2002. The decrease was primarily due to a $13.9 million decrease in fuel costs and a $10.5 million decrease in administrative expenses offset by a $15.9 million increase in depreciation expense related to our increased investment in power generation. Administrative and general expenses decreased due to a decrease in commissions and incentive compensation partially offset by increased pension and administrative expenses.

Consolidated income taxes decreased $20.5 million as a result of the decrease in pre-tax earnings and a lower effective tax rate. Our effective tax rate decreased from 36.4 percent in 2001 to 31.9 percent in 2002 primarily due to a lower overall effective state income tax rate and the recognition of research and development credits in 2002.

In addition, 2001 earnings were impacted by several non-recurring items including a $0.17 per share charge for a financial exposure to Enron Corporation, a $0.12 per share charge for employee stock bonus awards and the funding of the Black Hills Corporation Foundation, a $0.06 per share benefit for the sale of coal mining equipment and a $0.13 per share benefit for a gain on a coal contract settlement.

2001 Compared to 2000

Consolidated income from continuing operations for 2001 was $87.6 million, compared to $52.8 million in 2000, or $3.40 per share in 2001, compared to $2.37 per share in 2000. Income from discontinued operations was $0.5 million or $0.02 per share in 2001 compared to $36,000 in 2000. This equates to a 17.2 percent and 19.0 percent return on year-end common equity in 2001 and 2000, respectively. The return on year-end common equity in 2001 was diluted due to the net proceeds of $163 million from the public stock offering in 2001.

We reported record earnings in 2001, primarily due to strong natural gas marketing activity, increased fuel production, expanded power generation and increased wholesale off-system electric utility sales. Strong results in our integrated energy group and electric utility group were partially offset by losses in our communications group. Unusual energy market conditions related primarily to gas and electricity shortages in the West contributed to our strong financial performance in 2001 and 2000. There was an approximately $1.40 and $0.40 contribution to 2001 and 2000 earnings per share, respectively, due to high prevailing prices of gas and electricity and unusually wide gas trading margins in the last half of 2000 and first half of 2001.

Consolidated revenues were $461.9 million in 2001 compared to $292.1 million in 2000. Revenue increased in all segments. Daily volumes of natural gas marketed increased 22 percent from 860,800 million British thermal units per day in 2000 to 1,047,700 million British thermal units in 2001. Prices of financial and physical natural gas marketed decreased from an average of $2.77 per million British thermal units in 2000 to $2.14 per million British thermal units in 2001.

Earnings in 2001 included a $4.4 million after-tax charge ($0.17 per share) for a financial exposure to Enron Corporation and certain of its subsidiaries now in bankruptcy. The exposure is primarily related to the value of long-term swaps that hedged the price of natural gas to a power plant. We have taken action to mitigate this exposure. We are seeking authority to “net,” or offset, certain obligations with Enron and its subsidiaries, both payable and receivable, among our subsidiaries. If we are successful in these efforts, substantially all of the financial value of the fuel swap could be recovered, and we would not have any remaining exposure to Enron and its bankrupt subsidiaries.

Earnings in 2001 also reflect a $0.12 per share charge for employee stock bonus awards and the funding of a non-profit foundation to advance our charitable and philanthropic endeavors. Both of these transactions were funded with Black Hills Corporation common stock.

The following business group and segment information does not include discontinued operations and intercompany eliminations.

Integrated Energy Group

The following is a summary of sales volumes of our coal, oil and natural gas production and our power generation capacity:

The following is a summary of energy marketing average daily volumes:

2002 Compared to 2001

Net income of our integrated energy group decreased 24 percent in 2002 compared to 2001. Earnings decreased primarily due to a substantial decline in energy prices partially offset by growth in the power generation segment. The power generation segment had a substantial increase in earnings primarily due to results from increased capacity that went into service during 2002 and the second half of 2001, additional ownership interest in an energy partnership and a $1.9 million after-tax benefit relating to the collection of receivables reserved for in 2001 from California operations. In addition, 2001 was impacted by a $4.4 million after-tax charge for an exposure to Enron Corporation, a $1.7 million after-tax gain on the sale of coal mining equipment and a $3.4 million after-tax gain on the settlement of a coal contract.

The integrated energy group’s revenues declined slightly due to lower commodity prices and margins offset by increased power generation revenues due to an increase in capacity and acquisition of additional power generation partnership interests.

The integrated energy group’s total operating expenses increased 11 percent due to expanded power production, and increased costs of sales related to higher volumes of fuel production and tons of coal sold, partially offset by lower incentive compensation in our energy marketing segment.

2001 Compared to 2000

Net income of our integrated energy group nearly doubled in 2001 compared to 2000. These strong earnings resulted primarily from the unusually high prices of natural gas and high gas trading margins received in western markets during the first half of 2001, an increase in volumes marketed and fuel production, and expanded power generation.

In addition, in 2001, we reached a settlement of ongoing litigation with PacifiCorp concerning rights and obligations under a coal supply agreement under which PacifiCorp purchased coal from our coal mine to meet the coal requirements of the Wyodak power plant. As a result of this settlement, we recognized $5.6 million pre-tax non-operating income. In addition, we sold the “North Conveyor System” which resulted in a $2.6 million pre-tax gain. See Note 12 of Notes to Consolidated Financial Statements.

The integrated energy business group’s revenues more than doubled to $229 million in 2001 compared to $111 million in 2000. The increase was driven by the full year effect of independent power operations revenues related to the July 2000 acquisition of Indeck Capital and an increase in revenue from fuel production and gas marketing. Daily volumes of natural gas marketed increased 22 percent.

The integrated energy business group’s total operating expenses increased 153 percent due to expanded power production and increased volumes of fuel production and energy marketed. Operating income increased over 68 percent from 2000 levels due to higher production volumes.

Power Generation

Our power generation segment produced the following results:

2002 Compared to 2001

Earnings from the power generation segment increased $16.5 million primarily due to increased capacity that went into service during 2002 and the second half of 2001. During 2002 we had 726 net megawatts of independent power capacity in service, contributing to operations, compared to 617 net megawatts at December 31, 2001. Approximately 300 megawatts of the 617 megawatts of capacity at December 31, 2001 were brought on-line during the third quarter of 2001. Earnings for 2002 also reflect a $1.9 million after-tax benefit relating to the collection of receivables reserved for in prior periods and a $0.9 million benefit, net of taxes from a change in accounting principle related to the adoption of Statement of Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangibles” (SFAS 142). In addition, 2001 was impacted by a $4.4 million after-tax charge for an exposure to Enron Corporation.

Revenue increased 66 percent with a corresponding 48 percent increase to operating expenses. Approximately 43 percent of the revenue and operating expense increases were attributable to the purchase of an additional 30 percent interest in the Harbor Cogeneration Facility (Harbor) on March 15, 2002. Harbor is a 98-megawatt gas-fired plant located in Wilmington, California. Our investment in Harbor prior to this acquisition of an additional 30 percent interest was accounted for under the equity method of accounting. This acquisition gave us majority ownership and voting control of Harbor, therefore we now consolidate Harbor into our financial statements. As a result, this consolidation was partially offset by a $6.4 million decrease in equity in earnings of unconsolidated subsidiaries. The remaining increase in revenue and operating expenses was due to the additional generating capacity.

Interest expense increased $1.9 million due to a $170 million increase in debt outstanding related to the expansion of our generation portfolio, partially offset by lower interest rates.

2001 Compared to 2000

2001 reflects the first full year of operations of our power generation segment and our continued expansion of generation facilities. At December 31, 2001 we owned 617 net megawatts in currently operating plants. Improved financial results due to increased production capacity was offset by a $4.4 million after-tax charge for Enron exposure, additional reserves for exposure to western power markets and reduced water flow at hydro power plants in New York.

Energy Marketing

Our energy marketing companies produced the following results:

2002 Compared to 2001

Earnings from the energy marketing segment decreased $21.8 million due substantially to high gas margins received in the first half of 2001, partially offset by a 4 percent increase in natural gas average daily volumes marketed, a 57 percent increase in average daily volumes of crude oil marketed and lower commissions and incentive compensation.

Revenues decreased 55 percent from 2001 primarily due to lower gas margins. Unusual energy marketing conditions existed in the first six months of 2001 stemming primarily from gas and electricity shortages in the west. Average spot market gas prices in the West Coast region were approximately $7 per MMBtu in 2001 compared to $3 per MMBtu in 2002. The substantial increase in average daily volumes of crude oil marketed was due to oil marketing contracts that we entered into in 2002 that do not extend beyond January 2003.

As a result of changing commodity prices, net income was impacted by unrealized gains recognized through mark-to-market accounting treatment. Unrealized pre-tax mark-to-market gains (losses) were $(0.9) million in 2002 compared to $1.8 million in 2001, resulting in a year-over-year decrease of $(2.7) million pre-tax.

Operating expenses decreased 35 percent primarily due to a $17.1 million decrease in commissions and incentive compensation related to the decrease in profitability in this segment partially offset by additional expenses associated with our additional ownership interests in oil pipelines.

2001 Compared to 2000

Earnings from the energy marketing segment increased $20.6 million primarily due to high gas margins received in the first half of 2001, as well as a 22 percent increase in natural gas average daily volumes marketed in 2001 compared to 2000. Revenues increased 109 percent from 2000 primarily due to higher daily volumes and high gas margins.

The unusual energy market conditions related primarily to natural gas and electricity shortages in California and our ability to capture the higher margins contributed significantly to the strong financial performance.

Oil and Gas

Oil and gas operating results were as follows:

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