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

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

        For the fiscal year ended December 31, 2002

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

        For the transition period from ___________________ to __________________

        Commission File Number 1-7978

BLACK HILLS POWER, INC.

     Incorporated in South Dakota                                                                                                     IRS Identification Number 46-0111677

625 Ninth Street
Rapid City, South Dakota 57701

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

Securities registered pursuant to Section 12(b) of the Act:           None

Securities registered pursuant to Section 12(g) of the Act:           None

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

YES    X     NO____

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

        This paragraph is not applicable to the Registrant.                                                X

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).

YES ______NO      X     

State the aggregate market value of the voting stock held by non-affiliates of the Registrant.

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

                    Class                                                                                                                       Outstanding at March 28, 2003

     Common stock, $1.00 par value                                                                                                      23,416,396 shares

Reduced Disclosure

TABLE OF CONTENTS

PART I

ITEMS 1 AND 2.   BUSINESS AND PROPERTIES

General

We are an electric utility serving customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and began providing electric utility service in 1941. In 2000, we became a wholly owned subsidiary of Black Hills Corporation through a “plan of exchange” between us and Black Hills Corporation. Our power generation group produces and sells electricity in a number of markets, with a strong emphasis on the western United States.

Unless the context otherwise requires, references in this Form 10-K to “Black Hills Power,” “we,” “us” and “our” refer to Black Hills Power, Inc. and all of its subsidiaries collectively.

Electric Utility

We engage in the generation, transmission and distribution of electricity. We have a solid foundation of revenues, earnings and cash flow that support our capital expenditures, dividends, and overall performance and growth.

Our 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 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 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 Western Electricity Coordinating Council, or “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.
  

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 in 2003, we will provide 20 megawatts of unit contingent energy and capacity to the Municipal Energy Agency of Nebraska.

Our utility 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.

Independent Power

Our independent power unit acquires, develops and expands unregulated power plants. We hold varying interests in operating gas-fired and hydroelectric independent power plants in California, Colorado, Massachusetts, Nevada and New York. We have a total net ownership interest of 886 megawatts, (including the 224 MW expansion at the Las Vegas cogeneration power plant, which went into service January 3, 2003) as well as minority interests in several power-related funds with a net ownership interest of 24 megawatts.

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 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 $1.1 billion, of which approximately $0.1 billion is due before December 31, 2004 and approximately $0.5 billion is due to affiliates and classified as current liabilities. Our substantial indebtedness may:

• limit our ability to borrow funds or increase the cost to borrow additional funds;
  
  
• hinder our ability to pay dividends;
  
  
• 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.
  

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 Baa2 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.

A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.

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 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.

Construction, expansion, refurbishment and operation of power generating and transmission 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 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 The Public Utility Regulatory Policies Act of 1978 (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 the Federal Energy Regulatory Commission (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 Securities Exchange Commission (SEC) recently issued an initial decision concluding that Enron is an electric utility and is thus not exempt from regulations under the Public Utility Holding Company Act of 1935 (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 us 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 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, 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 the Company.

On September 6, 2002, the State of South Dakota commenced litigation against us, 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 us, 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

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.

PART II

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

All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.

ITEM 7.      MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

Consolidated Results

Overview

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

2002 Compared to 2001

Consolidated income from continuing operations for 2002 was $40.3 million compared to $43.3 million in 2001. The decrease in income from continuing operations is due to a substantial decrease in prevailing prices for wholesale electricity compared to 2001, partially offset by earnings from an increase in power generation capacity. Unusual energy market conditions existed in the first half of 2001 stemming primarily from gas and electricity shortages in the West. 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.

In addition, 2001 earnings were impacted by several non-recurring items including a $4.4 million after-tax charge for a financial exposure to Enron Corporation and a $2.1 million after-tax charge for the funding of a non-profit foundation.

Consolidated revenues were $287.5 million in 2002 compared to $287.0 million in 2001. Revenues were affected by a $52.9 million decrease in electric wholesale off-system sales partially offset by increased revenues from expanded power generation capacity.

Operating expenses decreased $9.4 million in 2002 compared to 2001. A decrease in fuel and purchased power of $16.4 million and operation and maintenance expenses of $6.9 million was offset by an increase of $12.2 million in depreciation expense related to the increase in power generation capacity.

2001 Compared to 2000

Consolidated income from continuing operations for 2001 was $43.3 million compared to $40.3 million in 2000. Consolidated revenues, expenses and operating income increased 49 percent, 54 percent and 24 percent, respectively, in 2001 compared to 2000.

Increased revenues, expenses and strong earnings in 2001 were primarily due to increased wholesale off-system electric utility sales and expanded power generation. 2001 was the first full year of operations for our independent power generation subsidiary. Unusual market conditions stemming from electricity shortages in the West also contributed to our strong financial performance in 2001.

Earnings in 2001 included a $4.4 million after-tax charge for financial exposure to Enron Corporation and certain of its subsidiaries now in bankruptcy. The exposure is primarily related to the value of a long-term swap to provide natural gas to a power plant. Earnings in 2001 also were impacted by a $2.1 million after-tax charge for the funding of a non-profit foundation to advance our charitable and philanthropic endeavors.

Electric Utility

We currently have a winter peak of 344 megawatts established in December 1998 and a summer peak of 392 megawatts established in August 2001. We own 435 megawatts of electric utility generating capacity and purchase an additional 60 megawatts under a long-term agreement (decreasing to 55 megawatts in 2003).

2002 Compared to 2001

Electric revenue decreased 24 percent in 2002 compared to 2001. The decrease in electric revenue in 2002 was due to a $52.9 million decrease in wholesale off-system sales at an average price that was 63 percent lower than the average price in 2001.

Firm kilowatt-hour sales decreased 2 percent in 2002. Residential and commercial sales increases of 5 percent and 3 percent, respectively, in 2002 accounted for a $2.9 million increase in revenue which was partially offset by a $3.6 million decrease in industrial sales, primarily due to discontinued operations at two of our largest and oldest customers, Homestake Gold Mine and Federal Beef Processors. Degree days, a measure of weather trends, were one percent above normal in 2002 and four percent above 2001.

Revenue per kilowatt-hour sold was 5.3 cents in 2002 compared to 7.0 cents in 2001. The number of customers in the service area at December 31, 2002 increased to 59,948 from 59,237 in 2001. The decrease in the revenue per kilowatt-hour sold in 2002 is due to a 63 percent decrease in average wholesale off-system prices.

Electric utility operating expenses decreased $25.1 million or 19 percent in 2002. The decrease was primarily due to a $22.0 million decrease in fuel and purchased power costs and a $5.0 million decrease in operations and maintenance expenses partially offset by higher depreciation expense related to the addition of the Lange combustion turbine in early 2002.

The decrease in fuel and purchased power costs was primarily due to the high spot market price for gas and electricity in the first half of 2001. The decrease in operations and maintenance expense was primarily due to a $3.2 million expense of a temporary generator lease in 2001 and a $3.1 million decrease in incentive compensation in 2002 offset by a $1.8 million increase in pension expense in 2002.

Net interest expense increased $2.3 million due to the issuance of $75 million of first mortgage bonds issued in August 2002.

In addition, 2001 earnings included a $2.0 million after-tax charge related to the formation of a non-profit foundation.

2001 Compared to 2000

Electric revenue increased 23 percent in 2001 compared to 2000. The increase in electric revenue in 2001 was primarily due to a 78 percent increase in wholesale off-system sales at an average price that was 27 percent higher than the average price in 2000. The increase in off-system sales was driven by high spot market prices for energy in early 2001, which enabled us to generate more energy from our combustion turbine facilities, including the Neil Simpson combustion turbine, which we placed into commercial operation in June 2000. Megawatt-hours generated from our oil-fired diesel and natural gas-fired combustion turbines were 440,368 in 2001, compared to 305,767 in 2000. Historically, market prices were not sufficient to support the economics of generating from these facilities, except to meet peak demand and as standby use for native load requirements.

Firm kilowatt-hour sales increased 2 percent in 2001. Residential and commercial sales increases of 3 percent in 2001 were partially offset by a slight decrease in industrial sales, primarily due to load reductions at Homestake Gold Mine. Degree days, a measure of weather trends, were 3 percent below normal in 2001 and 4 percent below 2000.

Revenue per kilowatt-hour sold was 7.0 cents in 2001 compared to 6.4 cents in 2000. The number of customers in the service area increased to 59,237 from 58,601 in 2000. The increase in the revenue per kilowatt-hour sold in 2001 is due to a 41 percent increase in wholesale off-system sales to 965,030 megawatt-hours and strong wholesale power prices.

Electric utility operating expenses increased 23 percent in 2001 primarily due to a 29 percent increase in purchased power costs and a 14 percent increase in the average cost of generation. The increase in the average cost of generation was primarily associated with the operation of certain gas-fired combustion turbines.

In addition, 2001 results include a $2.0 million after-tax charge related to a contribution to a newly formed non-profit foundation. This Foundation was created to enhance our longstanding practice of giving back to our communities. Through the Foundation, we may strengthen our service to our valued customers and fellow citizens for generations to come.

Independent Power

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2002 Compared to 2001

Earnings from the power generation segment increased $12.9 million primarily due to increased capacity that went into service during 2002 and the second half of 2001. During 2002, we had 686 net megawatts of independent power capacity in service, contributing to operations, compared to 577 net megawatts at December 31, 2001. Approximately 300 megawatts of the 577 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 due to the adoption of Statement of Financial 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 70 percent with a corresponding 25 percent increase to operating expenses. Approximately 46 percent of the revenue and 70 percent of the operating expenses increase was attributed 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 $5.4 million due to approximately a $183.3 million increase in debt outstanding related to the expansion of our generation portfolio, partially offset by lower interest rates.

2001 Compared to 2000

The year 2001 reflects the first full year of operations of our power generation group and our continued expansion of generation facilities. Revenues were over three times higher in 2001 compared to 2000. We owned 577 net megawatts in currently operating plants compared to 250 net megawatts at December 31, 2000. An additional 274 megawatts of generating capacity was under construction. Substantially all of this output is sold pursuant to existing long-term contracts.

Expenses increased more than three times in 2001 compared to 2000 due to the expansion of the generating capacity, reserves taken for exposure to western power markets and a $4.4 million after-tax charge for the Enron exposure.

Earnings in 2001 decreased $5.1 million in 2001 compared to 2000. The increased production capacity was offset by the charge taken for the Enron exposure, reserves for exposure to the western power markets and reduced water flow at hydro power plants in New York.

Discontinued Operations

During the quarter ended March 31, 2001, we distributed a non-cash dividend to our parent company, Black Hills Corporation (the Parent). The dividend included 50,000 common shares of Wyodak Resources Development Corporation (Wyodak), which represents 100 percent ownership of Wyodak. We therefore no longer operate in the coal production segment, oil and natural gas production segment, energy marketing segment or communications as we had indirectly owned the companies operating in these segments through our ownership of Wyodak. As a result, our only subsidiary is Black Hills Energy Capital and its subsidiaries. Our investment in Wyodak at the time of the distribution was $89.6 million.

The consolidated financial statements and notes to consolidated financial statements have been restated to reflect our continuing operations for all periods presented. The net operating results of discontinued operations are included in the Consolidated Statements of Income under the caption “Discontinued operations, net of income taxes” and are summarized as follows:

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*Includes only one month of operations

ITEM 7A.     QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk Disclosures

Our activities in the regulated and unregulated energy sector expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and counterparty risk. We have developed policies, processes, systems, and controls to manage and mitigate these risks.

Market risk is the potential loss that might occur as a result of an adverse change in market price or rate. We are exposed to the following market risks:

• commodity price risk associated with our fuel procurement for our gas fired generation assets; and
  
  
• interest rate risk associated with our variable rate credit facilities and our project financing floating rate debt as described in Notes 7 and 8 of our Notes to Consolidated Financial Statements.

Our exposure to these market risks is affected by a number of factors including the size, duration, and composition of our energy portfolio, the absolute and relative levels of interest rates and commodity prices, the volatility of these prices and rates, and the liquidity of the related interest rate and commodity markets.

To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures (BHCRPP). These policies have been approved by our Board of Directors and are routinely reviewed by its Audit Committee. We have a formalized Executive Risk Committee composed of senior level executives that meets on a regular basis to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.

Energy Activities

We have a portfolio of gas-fired fueled generation assets located throughout several western states. Most of these generation assets are sold under long-term tolling contracts with third parties whereby any fuel price risk is transferred to the third party. However, we do have some gas-fired generation assets under long term contracts and a few merchant plants that do possess market risk for fuel purchases.

It is our policy that fuel price risk, to the extent possible, will be hedged.

A potential risk related to power sales is the risk arising from the sale of wholesale power that exceeds our generating capacity. These short positions can arise from unplanned plant outages or from unanticipated load demands. To control such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities exceed our anticipated load requirements plus a required reserve margin.

Financing Activities

We engage in activities to manage risks associated with changes in interest rates. We have entered into floating-to-fixed interest rate swap agreements to reduce our exposure to interest rate fluctuations associated with our floating rate debt obligations. At December 31, 2002, these hedges met effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2002, we had $212.3 million of notional amount floating-to-fixed interest rate swaps, having a maximum term of four years and a fair value of $(17.2) million. These hedges are substantially effective and any ineffectiveness was immaterial.

On December 31, 2002 and 2001, our interest rate swaps and related balances were as follows (in thousands):