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 X        EXCHANGE ACT OF 1934
        For the fiscal year ended December 31, 20002002
   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.
                   (formerly known as Black Hills Corporation)
     Incorporated in South Dakota                                                                                                     IRS Identification Number 46-0111677
625 Ninth Street
Rapid City, South Dakota 57701

               Registrant's
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______

  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'sRegistrant’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.

All outstanding shares are held by the Registrant's
All outstanding shares are held by the Registrant’s parent company, Black Hills Corporation. Accordingly, the aggregate market value of the voting common stock of the Registrant held by non-affiliates is $0.

Indicate the number of shares outstanding of each of the Registrant'sRegistrant’s classes of common stock, as of the latest practicable date.
ClassOutstanding at March 30,  200128, 2003
     Common stock, $1.00 par value                                                                                                      23,416,396 shares
Reduced Disclosure
1.
The Registrant meets the conditions set forth in General Instruction I (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

TABLE OF CONTENTS
Page

ITEMS 1 &  2
BUSINESS AND PROPERTIES
3
    General
3
    Electric Utility
3
    Independent Power
4
    Risk Factors
5

ITEM 3
LEGAL PROCEEDINGS
10

ITEM 5

MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS

12

ITEM 7
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
12

ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
16
    Market Risk Disclosures
16
    Energy Activities
17
    Financing Activities
17
    Credit Risk
18
    Safe Harbor for Forward Looking Information
18

ITEM 8
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
21

ITEM 9

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
47

ITEM 14
CONTROLS AND PROCEDURES
47

ITEM 15

EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
48

SIGNATURES
50

CERTIFICATIONS
51

INDEX TO EXHIBITS
53
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
 
2001
 
2000
 
Revenue:
 
 
 
 
 
 
 
 
  Electric utility
 
 
 
56
%
 
74
%
 
90
%
  Independent power
 
 
 
44
 
 
26
 
 
10
 
 
 
 
 
100
%
 
100
%
 
100
%
Income (loss) from continuing
 
 
  operations:
 
 
  Electric utility
 
 
 
75
%
 
105
%
 
92
%
  Independent power
 
 
 
25
 
 
(5
)
 
8
 
 
 
 
 
100
%
 
100
%
 
100
%
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
2002
 
2001
 
2000
 
(in thousands)

Revenue
 
 
$
162,186
 
$
213,210
 
$
173,308
 
Operating expenses
 
 
 
104,026
 
 
129,102
 
 
105,100
 
Operating income
 
 
$
58,160
 
$
84,108
 
$
68,208
 
Net income
 
 
$
30,217
 
$
45,238
 
$
37,105
 
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

2002
 
2001
 
2000*
 
(in thousands)

Revenue
 
 
$
125,267
 
$
73,750
 
$
19,925
 
Expenses
 
 
 
77,628
 
 
61,980
 
 
19,135
 
 
 
 
 
47,639
 
 
11,770
 
 
790
 
Equity in unconsolidated
 
 
  subsidiaries
 
 
 
4,339
 
 
14,061
 
 
19,577
 
Operating income
 
 
$
51,978
 
$
25,831
 
$
20,367
 
Net income (loss)
 
 
$
10,962
 
$
(1,964
)
$
3,173
 
_________________
*
Year 2000 results are for the partial period July 7, 2000, the date of our acquisition of Indeck Capital, Inc., through December 31, 2000.

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 disclosure format.



                           FORWARD-LOOKING STATEMENTS

     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:
2001*
 
2000
 
(in thousands)

Revenue
 
 
$
197,274
 
$
1,425,675
 
Income before income taxes
 
 
 
7,849
 
 
20,345
 
Federal income taxes
 
 
 
3,017
 
 
7,775
 
Net income
 
 
 
4,832
 
 
12,570
 
_________________
*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 theBlack 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):
December 31, 2002
 
Notional
Weighted
Average
Fixed
Interest
Rate
Maximum
Terms in
Years
Current
Assets
Non-
current
Assets
Current
Liabilities
Non-
current
Liabilities
Accumulated
Other
Comprehensive
Income (Loss)

Swaps on project
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  financing
 
 
$
212,256
 
 
5.98
%
 
4
 
$ --
 
 
$ --
 
 
$
9,345
 
$
7,844
 
$
(17,189
)
December 31, 2001
 
 

Swaps on project
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  financing
 
 
$
316,397
 
 
5.85
%
 
4
 
$ --
 
 
$
5,746
 
$
10,212
 
$
5,949
 
$
(14,415
)
We anticipate a portion of unrealized losses recorded in accumulated other comprehensive income will be realized as increased interest expense in 2003. Based on December 31, 2002 market interest rates, $9.3 million will be realized as additional interest expense during 2003. Estimated and realized amounts will likely change during 2003 as market interest rates change.
At December 31, 2002, we had $871.9 million of outstanding, variable-rate debt of which $454.8 million was due to an affiliate and $212.3 million was offset with interest rate swap transactions that effectively convert the debt to a fixed rate. A 100 basis point increase in interest rates would cause our interest expense to increase by $6.6 million.
The table below presents principal (or notional) amounts and related weighted average interest rates by year of maturity for our short-term investments and long-term debt obligations, including current maturities (in thousands).
2003
 
2004
 
2005
 
2006
 
2007
 
Thereafter
 
Total

Cash equivalents
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
     Fixed rate
 
 
$
45,042
 
$
--
 
$
--
 
$
--
 
$
--
 
$
--
 
$
45,042
 

Long-term debt
 
 
     Fixed rate
 
 
$
3,095
 
$
1,986
 
$
1,991
 
$
1,996
 
$
2,002
 
$
201,213
 
$
212,283
 
     Average interest rate
 
 
 
9.28
%
 
9.44
%
 
9.45
%
 
9.46
%
 
9.47
%
 
7.87
%
 
7.95
%

     Variable rate (a)
 
 
$
19,036
 
$
22,213
 
$
23,631
 
$
136,065
 
$
123,334
 
$
42,764
 
$
367,043
 
     Average interest rate
 
 
 
3.21
%
 
3.21
%
 
3.21
%
 
3.28
%
 
3.18
%
 
3.17
%
 
3.22
%

     Total long-term debt
 
 
$
22,131
 
$
24,199
 
$
25,622
 
$
138,061
 
$
125,336
 
$
243,977
 
$
579,326
 
     Average interest rate
 
 
 
4.06
%
 
3.72
%
 
3.69
%
 
3.37
%
 
3.28
%
 
7.04
%
 
4.95
%

(a)

Approximately 58 percent of the variable rate long-term debt has been hedged with interest rate swaps moving the floating rates to fixed rates with an average interest rate of 5.98 percent.

Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. We have adopted the Black Hills Corporation Credit Policy (BHCCP) that establishes guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. In addition, we have a formalized Executive Credit Committee composed of senior executives that meets on a regular basis to review the Company’s credit activities and to ensure that these activities are conducted within our policies.
For our generation activities, we attempt to mitigate our credit risk by conducting a majority of our business with investment grade companies, setting tenor and credit limits commensurate with counterparty financial strength, obtaining netting agreements, and securing our credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit, and asset security agreements.
We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of their current credit information. We maintain a provision for estimated credit losses based upon our historical experience and any specific customer collection issue that we have identified. While most credit losses have historically been within our expectations and provisions established, we cannot guarantee that we will continue to experience the same credit loss rates that we have in the past or that an investment grade counterparty will not default sometime in the future.
Safe Harbor for Forward Looking Information
This Form 10-K includes "forward-looking  statements"“forward-looking statements” as defined by the Securities and Exchange Commission.   TheseCommission, or SEC. We make these forward-looking statements concern  our  plans,
expectations and objectives for future  operations.in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements.  The words  "believe,"
"plan," "intend,"  "anticipate,"  "estimate,"  "project" and similar expressions
are also intended to identify forward-looking statements.  These forward-looking
statements include, among others, such things as:

         o  expansion  and  growth  of our  business  and  operations;
         o  future financial  performance;
         o  future acquisition and development of power plants;
         o  future  production  of coal,  oil and natural gas;
         o  reserve estimates; and
         o  business strategy. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties whichthat, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including:
the effects on our business resulting from the financial difficulties of other energy companies, including the following factors:

         o    effects on liquidity and the perceptions of the energy business;

the effects on our business resulting from a lowering of our credit rating (or actions we may take in response to changing credit ratings criteria), including demands for increased collateral by our current or new counterparties, refusal by our current or potential counterparties or customers to enter into transactions with us and our inability to obtain credit or capital in amounts or on terms favorable to us;

capital market conditions;

unanticipated developments in the western power markets, including unanticipated governmental intervention, deterioration in the financial condition of counterparties, defaults on amounts due from counterparties, adverse changes in current or future litigation, market disruption and adverse changes in energy and commodity supply, volume and pricing and interest rates;

pricing and transportation of commodities;

population changes and demographic patterns;

prevailing governmental policespolicies and regulatory actions with respect to allowed rates of return, industry and rate structure, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased power and other capital investments, and present or prospective wholesale and retail competition;
         o    

the continuing efforts by or on behalf of the State of California to restructure its long-term power purchase contracts and efforts by regulators and private parties in several western states to recover refunds for alleged price manipulation;

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

weather conditions;
         o    counterparty credit risk;
         o    population growth and demographic patterns;
         o    

competition for retail and wholesale customers;
         o    pricing and transportation of commodities;
         o    

market demand, including structural market changes;
         o    

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

changes in project costs;
         o    

unanticipated changes in operating expenses or capital expenditures;
         o    capital market conditions;
         o    

technological advances;
         o    advances by competitors;

competition for new energy development opportunities;

the cost and oother effects of legal and administrative proceedings that influence our business;

the effects on our business, including the availability of insurance, resulting from terrorist actions or responses to such actions; and profitability.



                                TABLE OF CONTENTS
                                                                           Page

ITEMS
1 & 2.     BUSINESS AND PROPERTIES............................................4
                 General......................................................4
                 Electric Utility.............................................4
                 Independent Energy...........................................5
                 Communications...............................................5

ITEM 3.    LEGAL PROCEEDINGS..................................................6

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
           STOCKHOLDER MATTERS................................................7

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

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........14

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................18

ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
           ON ACCOUNTING AND FINANCIAL DISCLOSURE............................43

ITEM 14.   EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K...43

           SIGNATURES........................................................46



PART I

ITEMS 1 AND 2.  BUSINESS AND PROPERTIES

General

We are an  electric  utility  serving  customers

other factors discussed from time to time in South  Dakota,  Wyoming and
Montana.  We are  incorporated  in South  Dakota  and began  providing  electric
utility service in 1941. We began selling and marketing  various forms of energy
on an  unregulated  basis in 1956.  Our  independent  energy group  produces and
markets power and fuel. We produce and sell  electricity in a number of markets,
with a strong  emphasis on the western United States.  We produce coal,  natural
gas and crude oil  primarily  in the  Rocky  Mountain  region  and  market  fuel
products nationwide.  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.

During 2000,  we became a  wholly-owned  subsidiary  of Black Hills  Corporation
(formerly Black Hills Holding  Corporation) through a "plan of exchange" between
us and Black Hills Corporation.  The "plan of exchange" provided that each share
of our common  stock  would be  exchanged  for one share of common  stock of the
holding company. As a result:

o    all common  shareholders of Black Hills Power,  Inc.  (formerly Black Hills
     Corporation) became shareholders of Black Hills Corporation (formerly Black
     Hills Holding Corporation), the holding company;

o    Black Hills Power,  Inc.  became a  wholly-owned  subsidiary of Black Hills
     Corporation; and

o    The debt securities and other  financial  obligations of Black Hills Power,
     Inc. continue to be obligations of Black Hills Power, Inc.

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 to
approximately 58,600 customers in South Dakota,  Wyoming and Montana. We control
458  megawatts  of  generating  capacity,  including  65  megawatts  of capacity
purchased from others under  long-term  power contracts at rates which currently
are significantly lower than prevailing market prices.  Approximately 53 percent
of our generating  capacity consists of coal-fired plants and 33 percent is gas-
or oil-fired,filings with the remaining 14 percent purchasedSEC.
New factors that could cause actual results to differ materially from others.

Our revenue mixthose described in forward-looking statements emerge from time to time, and it is not possible for 2000 was comprised of 29 percent  wholesale  off-system,  26
percent commercial,  20 percent residential,  14 percent industrial,  10 percent
contract  wholesale and 1 percent  municipal  sales.  In 2000,  our South Dakota
customers  accounted for 92 percent of our retail electric revenues.  Our retail
electric  rates in South  Dakota are subject to a five-year  freeze  expiring on
January 1, 2005. Because our generation capacity typically exceeds our peak load
demands,  we rarely  purchase  power on the spot market  during  periods of peak
usage,  permitting us to preserve our low-cost  rate  structure  for our retail
customers.  Off-system  sales offer a meanspredict all such factors, or the extent to optimize the  utilizationwhich any such factor or combination of our
power supply  sources by  permitting usfactors may cause actual results to sell capacity and energydiffer from those contained in excess of
our native load  requirementsany forward-looking statement. We assume no obligation to wholesale  customers  at market  prices which
sometimes  exceed our regulated  retail rates.  Wholesale  off-system sales have
represented an increasing  percentage of our total  revenues and net income.  We
added 40 megawatts of additional capacity to our system with the addition of the
Neil Simpson combustion turbine, which we placed into operation in June 2000.



We operate a  transmission  system of 447 miles of high voltage and 541 miles of
lower voltage  lines.  Our system has the capability of connecting to either the
midwestern  or western  transmission  grids.  This provides us with an important
strategic  opportunity to shift  off-system  power to areas of higher demand and
profitability as market conditions warrant.

Independent Energy

Our independent  power unit acquires,  develops and operates  unregulated  power
plants,  primarily in the Rocky Mountain  region of the United  States.  In July
2000, we expanded our presence in the  independent  power  business by acquiring
Indeck Capital,  Inc. This acquisition and subsequent  additions provide us with
varying interests in 13 operating  gas-fired and  hydroelectric  power plants in
California,  Colorado,  Massachusetts  and New York,  of which we operate 12, as
well as  minority  interests  in several  power-related  funds.  We have a total
ownership interest of approximately 250 net megawatts.  We are in the process of
acquiring or constructing an additional net ownership  interest of approximately
470 megawatts of generation  capacity,  approximately  330 megawatts of which we
expect to be brought into service in 2001.

As of December 31, 2000,  we had 275 million tons of  low-sulfur  sub-bituminous
coal reserves at our Wyodak mine located near Gillette,  Wyoming.  Substantially
all of our coal production is sold under  long-term  contracts with our electric
utility  and with  PacifiCorp.  Our Wyodak mine will also  provide  coal to a 90
megawatt  mine-mouth  power plant which is being  developed for our  independent
power unit and is scheduled for completion in 2003. Our oil and gas  exploration
and production unit owns and operates  approximately  298 oil and gas wells, all
in Wyoming,  and owns working  interests in another 341 wells operated by others
located  in  California,  Montana,  North  Dakota,  Texas,  Wyoming,  Louisiana,
Oklahoma  and offshore in the Gulf of Mexico.  As of December  31, 2000,  we had
proved  reserves of 4.4 million  barrels of oil and 18.4  billion  cubic feet of
natural gas, with approximately 62 percent of our current production  consisting
of natural gas.

Our fuel  marketing  and  transportation  unit  supplies  wholesale  natural gas
marketing and risk  management  products and services  primarily to customers in
the Rocky  Mountain and West Coast  regions of the United  States.  In addition,
this  unit  markets  oil in the  south and coal in the  eastern  and  midwestern
regions of the United States.  Our customers  include  natural gas  distribution
companies,  municipalities,  industrial  users, oil and gas producers,  electric
utilities  and coal mines.  Our average daily  marketing  volumes for the twelve
months  ended  December  31, 2000 were  approximately  860,800  million  British
thermal units of natural gas,  44,300 barrels of oil and 4,400 tons of coal. Our
power  marketing  activities  involve  marketing of capacity and energy from our
existing power generation facilities.

Communications

Our communications group, known as Black Hills FiberCom,  offers a full suite of
local and long distance  telephone service,  expanded cable television  service,
cable  modem  Internet   access  and  high-speed  data  and  video  services  to
residential  and  business  customers.  We have  completed a 210 mile inter- and
intra-city fiber optic network and currently operate nearly 600 miles of two-way
interactive  hybrid fiber  coaxial  cable in Rapid City and the  northern  Black
Hills region of South Dakota. The construction of our communications  network is
approximately  75  percent  complete,  and we expect to  substantially  complete
construction in 2001.



ITEM 3.  LEGAL PROCEEDINGS

PacifiCorp Litigation

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

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

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

Other Litigation

On July 14,  2000,  the South Coast Air  Quality  Management  District  known as
SCAQMD sent a letter to our affiliate,  now called Black Hills  Ontario,  L.L.C,
the operator of a 12 megawatt natural-gas fired cogeneration facility located in
Ontario,  California,  stating that the SCAQMD had determined, as a result of a
facility audit  completed for the compliance  year ended June 1, 1999,  that the
facility's  nitrogen  oxide,new information, future events, or Nox,  emissions  were  28,958  pounds  over the
facility's NOx allocation  established by the SCAQMD's RECLAIM emissions trading
program.  As a  result,  the  SCAQMD  indicated  that it would be  reducing  the
facility's  NOx  allocation by the same number of allowances  for the compliance
year subsequent to a final determination on this issue. If a final determination
is reached prior to June 30, 2001, the NOx allowances would be deducted from the
facility's  allocation for the compliance year ended June 30, 2002.  Black Hills
Ontario  has  provided  documentation  to the  SCAQMD  disputing  this  proposed
reduction.  In  addition to this  proposed  reduction,  which  could  affect the
facility's  compliance with RECLAIM  requirements  for the 2001-2002  compliance
period,  Black  Hills  Ontario  also  projects  that its NOx  emissions  for the
compliance year ended June 30, 2001 may be approximately  30,000 pounds over its
current NOx allocation.  There is currently significant  volatility in the price
and supply of  RECLAIM  NOx  allowances;  although  the  SCAQMD  has  proposed a
revision to its  regulations  to  stabilize  the RECLAIM  market,  it is unclear
whether such rules will 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, 2001, or, if allowances are available, as to the cost of
those  allowances.  Black Hills Ontario may also be subject to administrative or
civil  penalties with respect to alleged  violations of the SCAQMD's  regulation
for the  compliance  year  ended  June 30,  1999,  although  no  notice  of such
penalties has been issued.



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

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

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

We  reported  record  earnings  in 2000,  primarily  due to strong  natural  gas
marketing  activity,  increased fuel  production,  expanded power generation and
increased  wholesale  off-system  electric utility sales.  Strong results in our
independent  energy  business  group in 2000 were  partially  offset by start-up
losses in our communications business. Unusual energy market conditions stemming
primarily from gas and  electricity  shortages in California  contributed to our
strong  financial  performance in 2000.  There was  approximately a $9.0 million
contribution  to 2000 earnings due to prevailing  prices of gas and  electricity
and unusually wide gas trading margins that may not recur in the future.

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

In 1998, we recorded an $8.8 million (after tax) charge to earnings related to a
write-down of certain oil and natural gas  properties.  Absent this charge,  our
earnings  for 1998  would have been $34.6  million,  and our return on  year-end
common equity would have been 16.1 percent.  The write-down was primarily due to
historically  low crude oil  prices,  lower  natural gas prices and a decline in
value of certain unevaluated properties.

Consolidated  revenues were $1,623.8 million,  $791.9 million and $679.3 million
in 2000,  1999 and 1998,  respectively,  representing a 105 percent  increase in
2000 and a 17 percent increase in 1999.

The growth in revenues in 2000 was a result of high energy  commodity prices and
increased  volumes of fuel  marketed,  primarily  as a result of  extreme  price
volatility in the western  markets,  acquisitions  and growth in the independent
energy business group and increases in off-system sales by our electric utility.
Prices of natural gas  marketed  increased  from an average of  $1.97-$2.15  per
million  British  thermal  units in 1998 and 1999 to $4.19 per  million  British
thermal  units in 2000.  Daily  volumes of natural  gas  marketed  increased  35
percent from 635,500  million  British  thermal units per day in 1999 to 860,800
million British thermal units in 2000.

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



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


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

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


Net income from the  independent  energy  group is expected to exceed net income
derived from utility operations in 2001. We expect that earnings growth from the
independent energy group over the next few years will be driven primarily by our
continued expansion in the independent power production segment. We also believe
that continued  strength in commodity prices and energy markets will provide the
opportunity  for strong results in our fuel marketing and oil and gas production
operations.

We have  continued to produce  modest  growth in revenue and  earnings  from the
retail electric  business over the past two years. We believe that this trend is
stable and that, absent unplanned system outages,  it will continue for the next
several  years due to the extension of our electric rate freeze until January 1,
2005.  The share of our future  earnings  generated  from  wholesale  off-system
electric sales will depend on many factors  including native load growth,  plant
availability and commodity prices in the western markets.

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

The  following  business  group and segment  information  includes  intercompany
eliminations.

Electric Utility


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


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

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

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

Our  electric  utility  operating  expenses  increased  by 30  percent  in 2000,
primarily due to increased fuel,  purchased power, and operating and maintenance
expenses, partially offset by lower depreciation.  Fuel expense in 2000 included
the cost associated with the additional combustion turbine generation. Operating
expenses  increased  2.0 percent in 1999,  primarily  due to increased  purchase
power expense,  operations and maintenance expenses and depreciation,  partially
offset by lower fuel expense.

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 1 percent,
with the  system  demand  forecasted  to  increase  at a rate of 2  percent.  We
currently have a winter peak of 344 megawatts established in December 1998 and a
summer peak of 372 megawatts  established  in August 2000.  These  forecasts are
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.





Independent Energy

                                                          2000                       1999                        1998
                                                          ----                       ----                        ----
                                                                   (in thousands)
       
       Revenue:
         Fuel marketing                                $1,353,795                   $614,228                   $506,043
         Coal production                                   30,530                     31,095                     31,413
         Oil and gas production                            19,183                     13,052                     12,562
         Independent power                                 39,331                          -                          -
                                                       ----------                   --------                   --------
            Total revenue                               1,442,839                    658,375                    550,018
       Expenses                                         1,381,991                    644,196                    536,048*
                                                       ----------                   --------                   --------
       Operating income                                $   60,848                   $ 14,179                   $ 13,970*
                                                       ==========                   ========                   ========
       Net income                                      $   28,946                   $ 11,882                   $ 10,068*
                                                       ==========                   ========                   ========
       EBITDA**                                        $   65,184                   $ 25,016                   $ 22,530
                                                       ==========                   ========                   ========


- ---------------
  * Excludes $13.5 million pre-tax,  $8.8 million after tax, non-cash write-down
    relating to oil and gas properties due to historically low crude oil prices,
    lower  natural  gas  prices  and a  decline  in  the  value  of  unevaluated
    properties.
**  EBITDA represents earnings before interest, income taxes,  depreciation and
    amortization  and any  non-recurring  or non-cash  items.  EBITDA is used by
    management  and some  investors as an  indicator  of a company's  historical
    ability to service debt.  Management  believes that an increase in EBITDA is
    an  indicator  of  improved  ability to service  existing  debt,  to sustain
    potential  future  increases  in debt and to satisfy  capital  requirements.
    However,  EBITDA is not intended to represent cash flows for the period, nor
    has it been  presented as an  alternative  to either  operating  income,  as
    determined by generally accepted accounting  principles,  or as an indicator
    of  operating  performance  or cash  flows  from  operating,  investing  and
    financing  activities,   as  determined  by  generally  accepted  accounting
    principles,  and is thus  susceptible  to  varying  calculations.  EBITDA as
    presented may not be comparable to other similarly  titled measures of other
    companies.

The following is a summary of coal, oil and natural gas production:


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


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


                                                            2000                       1999                        1998
                                                            ----                       ----                        ----
          
          Natural gas - MMBtus                            860,800                      635,500                    524,800
          Crude oil - barrels                              44,300                       19,270                     19,000
          Coal - tons                                       4,400                        4,500                      4,400*


- ------------
* Since the acquisition date

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




The independent  energy business  group's total operating  expenses,  EBITDA and
operating  income  increased  over 115  percent,  160 percent  and 329  percent,
respectively,  in 2000 compared to 1999. Net income of this group  increased 144
percent in 2000.  These  increases  resulted  primarily  from our gas  marketing
operations,  which  experienced a dramatic  increase in both trading volumes and
margins,  a significant  increase in fuel  production  volumes,  record fuel and
power prices and expanded power  generation.  The  independent  energy  business
group's 1999 net income  improved over 1998  (excluding  the non-cash  charge in
1998)  primarily  due to record  gas  production,  improved  oil  prices,  lower
depletion  expense and the sale of certain  retail gas  marketing  operations in
1999,  partially offset by a non-cash  write-down of certain  intangible  assets
relating to our wholesale gas marketing office in Houston.

Coal Mining

Coal mining results were as follows:


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



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

Oil and Gas

Oil and gas operating results were as follows:


                                                            2000                   1999                  1998
                                                            ----                   ----                  ----
                                                                            (in thousands)
        
        Revenue                                            $19,183                $13,052              $ 12,562
        Operating income                                     7,900                  4,000                 1,200*
        Net income                                           5,000                  2,500                   800*
        EBITDA                                              11,900                  6,900                 6,400

- ------------
*Excludes $13.5 million  pre-tax,  $8.8 million after tax,  non-cash  write-down
relating to oil and gas  properties  due to  historically  low crude oil prices,
lower natural gas prices and a decline in the value of unevaluated properties.

Record net income in 2000 was  primarily a result of record  natural gas prices,
higher  crude oil prices  and a  significant  increase  in  production  volumes.
Operating  results for 1998 decreased  primarily as a result of historically low
crude oil prices,  which not only reduced  revenue but also increased  depletion
expense (lower oil and gas prices reduce the  economically  recoverable  reserve
amounts,  causing an increase in depletion expense). We recognized approximately
$3.7 million,  $2.6 million and $4.9 million of depletion expense (excluding the
write-down  in 1998) related to gas and oil  production in 2000,  1999 and 1998,
respectively.



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

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


These reserves are based on reports prepared by Ralph E. Davis Associates, Inc.,
an independent  consulting and engineering firm.  Reserves were determined using
constant  product  prices  at the  end of the  respective  years.  Estimates  of
economically  recoverable reserves and future net revenues are based on a number
of variables, which may differ from actual results. The increase in oil reserves
at  December  31,  2000 was due to  improved  product  prices.  The  increase in
reserves  at  December  31,  1999 was due to strong  drilling  results,  reserve
acquisitions and improved  product prices.  We intend to increase our net proved
reserves by selectively  increasing our oil and gas  exploration and development
activities and by acquiring producing properties.

Fuel Marketing

Our fuel marketing companies produced the following results:


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


Record volumes  marketed and strong  margins  contributed to the increase in net
income from fuel  marketing in 2000 compared to 1999 and 1998.  During 1999, the
fuel marketing companies sold certain of their retail gas marketing  operations,
resulting in after-tax gains of approximately $1.8 million. In 1999, revenue and
the  related  cost  of  sales  increased  primarily  due to a full  year of coal
marketing operations (acquired in September 1998),  increased product prices and
increased  oil  volumes  marketed.  Operating  income in 1999 was  reduced  by a
non-cash  write-down of certain  intangible assets relating to the wholesale gas
marketing office in Houston in the amount of  approximately  $1.2 million (after
tax).

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



Independent Power Production

Our independent power segment produced the following results:


                                                          2000                  1999                   1998
                                                          ----                  ----                   ----
                                                                           (in thousands)
        
        Revenue                                          $39,331              $     -               $      -
        Operating income (loss)                           20,400                 (160)                  (160)
        Net income                                         3,200                 (110)                  (120)
        EBITDA                                            10,751                 (160)                  (160)


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

Communications

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


In  September   1998,   we  formed  our   communications   business  to  provide
facilities-based  communications  services for Rapid City and the northern Black
Hills of South Dakota.  We began serving  communications  customers in late 1999
and market our  services to schools,  hospitals,  cities,  economic  development
groups,  and business and residential  customers.  Operating losses in 2000 were
attributable  to  increased  interest,   depreciation  and  operating  expenses.
Operating  losses in 1999 were primarily due to start-up  organizational  costs,
increased  depreciation  expense and increased  interest expense associated with
capital deployment.

As of December 31, 2000,  we had 8,368  residential  customers  and 646 business
customers.  Our goal is to double the number of our customers,  and to attain 50
percent  residential  market  penetration  within our  service  territory  while
serving 35 percent of all broadband business customers in that territory.  If we
are unable to attract  additional  customers or technological  advances make our
network  obsolete,  we could  have a  write-down  of our assets  which  could be
material.





ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Price Risk Management

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

We have adopted risk management  policies and procedures,  approved by our board
of  directors,  and reviewed  routinely  by the audit  committee of the board of
directors.  Our risk  management  policies and procedures  include,  but are not
limited to, risk tolerance  levels relating to authorized  derivative  financial
instruments, position limits, authorization of transactions and credit exposure.

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

Effective  January 1, 1999, we adopted the  provisions  of Emerging  Issues Task
Force  Issue No.  98-10,  "Accounting  for Energy  Trading  and Risk  Management
Activities" (EITF 98-10).  The resulting effect of adoption of the provisions of
EITF  98-10  was  to  alter  our   comprehensive   method  of   accounting   for
energy-related contracts, as defined in that statement.

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

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

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



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

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

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

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

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


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



Instrument                                                 Asset                     Liability                 Gain (loss)
- ----------                                                 -----                     ---------                 -----------

Natural gas basis swaps                                    $13,391                    $23,963                   $(10,572)

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

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

Coal transactions                                            5,370                      4,460                        910

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

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



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

Non-trading Energy Activities

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



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

Financing Activities

To reduce risk from  fluctuations in interest rates, we enter into interest rate
swap  transactions.  We use these  transactions  to hedge interest rate risk for
variable  rate  debt  financing.   For  such  transactions,   we  utilize  hedge
accounting.  At December  31, 2000,  we had interest  rate swaps with a notional
amount  of $127.4  million,  which  have a maximum  term of six years and a fair
value of $(7.5)  million.  These  amounts are not  reflected in our December 31,
2000 consolidated balance sheet, but will be recorded as part of the adoption of
SFAS No. 133 on January 1, 2001.

Credit Risk

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

Interest Rate Risk

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

We mitigate  default risk on short-term  investments by investing in high credit
quality securities  consisting primarily of tax-exempt federal,  state and local
agency  obligations,  by  periodically  monitoring  the  credit  rating  of  any
investment issuer or guarantor and by limiting the amount of exposure to any one
issuer.  Our portfolio  includes only securities with active secondary or resale
markets to ensure portfolio  liquidity.  All short-term  investments  mature, by
policy,  in two  years or less.  The  effect of a 100  basis  point (1  percent)
increase  in interest  rates would not have a material  effect to our results of
operations  or  financial  condition,  due to  the  short-term  duration  of the
investment portfolio.

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



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



                                       2001        2002        2003         2004          2005        Thereafter        Total

Cash equivalents
    Fixed rate                       $ 24,913     $     -    $      -      $     -       $     -        $     -       $  24,913
    Average interest rate              6.23%            -           -            -             -              -           6.23%
  rate

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

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

       Total long-term debt           $13,960     $29,984     $16,090       $16,397       $17,586       $227,035         $321,052
       Average interest rate           8.44%        7.46%        8.41%        8.35%         8.35%          8.22%          8.18%
otherwise.
ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

         Report of Independent Public Accountants                            18

         Consolidated Statements of Income
           for the three years ended December 31, 2000                       19

         Consolidated Balance Sheets as of December 31, 2000 and 1999        20

         Consolidated Statements of Cash Flows
            for the three years ended December 31, 2000                      21

         Consolidated Statements of Common Stockholder's Equity
            for the three years ended December 31, 2000                      22

         Notes to Consolidated Financial Statements                       23-42
Independent Auditors' Report
21

Consolidated Statements of Income
  for the three years ended December 31, 2002
22

Consolidated Balance Sheets as of December 31, 2002 and 2001
23

Consolidated Statements of Cash Flows
   for the three years ended December 31, 2002
24

Consolidated Statements of Common Stockholder's Equity and Comprehensive Income
   for the three years ended December 31, 2002
25

Notes to Consolidated Financial Statements
26-47
INDEPENDENT AUDITORS’ REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the ShareholderStockholder of Black Hills Power, Inc.:
We have audited the accompanying consolidated balance sheets of Black Hills Power, Inc. (formerly Black Hills Corporation,  a South Dakota  corporation) and Subsidiariessubsidiaries as of December 31, 20002002 and 1999,2001, and the related consolidated statements of income, common stockholder'sstockholder’s equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2000.2002. Our audits also included the financial statement schedule listed in the Table of Contents at Item 15. These financial statements and financial statement schedule are the responsibility of the Company'sCorporation’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States.States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, thesuch consolidated financial statements  referred to above present fairly, in all material respects, the financial position of Black Hills Power, Inc. and Subsidiariessubsidiaries as of December 31, 20002002 and 1999,2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000,2002, in conformity with accounting principles generally accepted in the United States.

Arthur AndersenStates of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
As explained in Note 1 to the consolidated financial statements, effective January 1, 2002, the Corporation adopted Statement of Financial Accounting Standards No. 142 “Goodwill and Other Intangible Assets” and as discussed in Note 1 to the consolidated financial statements, effective January 1, 2001, the Corporation adopted Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
January 26, 2001



March 10, 2003
BLACK HILLS POWER, INC.
                                      (formerly Black Hills Corporation)
                                       
CONSOLIDATED STATEMENTS OF INCOME


Years ended December 31,                                            2000               1999               1998
                                                                    ----               ----               ----
                                                                                  (in thousands)


Operating revenues                                               $1,623,836          $ 791,875         $  679,254
                                                                 ----------          ---------         ----------

Operating expenses:
    Fuel and purchased power                                      1,370,841            637,302            531,518
    Operations and maintenance                                       46,054             36,463             32,701
    Administrative and general                                       44,423             18,272             15,747
    Depreciation, depletion and amortization                         32,864             25,067             24,037
    Oil and gas ceilings test write-down                                  -                  -             13,546
    Taxes, other than income taxes                                   14,904             12,880             12,472
                                                                 ----------          ---------          ---------
                                                                  1,509,086            729,984            630,021
                                                                 ----------          ---------          ---------

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

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

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

          Net income                                                 52,848             37,067             25,808
Preferred stock dividends                                               (78)                 -                 -
                                                                 ----------         ----------          ---------
Net income available for common stock                            $   52,770          $  37,067           $ 25,808
                                                                 ==========         ==========          =========
Years ended December 31,
2002
 
2001
 
2000
 
(in thousands)

Operating revenues
 
 
$
287,453
 
$
286,960
 
$
193,233
 
Operating expenses:
 
 
     Fuel and purchased power
 
 
 
60,620
 
 
77,055
 
 
57,584
 
     Operations and maintenance
 
 
 
35,069
 
 
41,999
 
 
26,258
 
     Administrative and general
 
 
 
31,691
 
 
28,700
 
 
14,721
 
     Depreciation and amortization
 
 
 
43,933
 
 
31,703
 
 
18,612
 
     Taxes, other than income taxes
 
 
 
10,341
 
 
11,625
 
 
7,060
 
 
 
 
 
181,654
 
 
191,082
 
 
124,235
 
Equity in earnings of unconsolidated subsidiaries
 
 
 
4,339
 
 
14,061
 
 
19,577
 
Operating income
 
 
 
110,138
 
 
109,939
 
 
88,575
 
Other (expense) income:
 
 
     Interest expense
 
 
 
(47,865
)
 
(44,584
)
 
(25,329
)
     Interest income
 
 
 
825
 
 
5,239
 
 
5,758
 
     Other expense
 
 
 
(312
)
 
(4,758
)
 
(540
)
     Other income
 
 
 
2,334
 
 
5,641
 
 
5,735
 
 
 
 
 
(45,018
)
 
(38,462
)
 
(14,376
)
Income from continuing operations before minority
 
 
   interest, income taxes and change in accounting
 
 
   principle
 
 
 
65,120
 
 
71,477
 
 
74,199
 
Minority interest
 
 
 
(3,162
)
 
(4,186
)
 
(11,338
)
Income taxes
 
 
 
(21,675
)
 
(24,017
)
 
(22,583
)
         Income from continuing operations before
 
 
            change in accounting principle
 
 
 
40,283
 
 
43,274
 
 
40,278
 
Discontinued operations, net of income taxes
 
 
   (Note 2)
 
 
 
--
 
 
4,832
 
 
12,570
 
Change in accounting principle
 
 
 
896
 
 
--
 
 
--
 
Net income
 
 
$
41,179
 
$
48,106
 
$
52,848
 
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS POWER, INC.
                       (formerly Black Hills Corporation)
                           
CONSOLIDATED BALANCE SHEETS


At December 31,                                                                      2000                 1999
                                                                                     ----                 ----
                                                                                (in thousands, except share amounts)
                                   ASSETS

Current assets:
    Cash and cash equivalents                                                     $  24,913            $  16,482
    Securities available-for-sale                                                     2,113                7,586
    Receivables (net of allowance for doubtful accounts of $3,631
         and $278, respectively) -
      Customers                                                                     278,434               84,331
      Other                                                                          21,283               55,694
    Materials, supplies and fuel                                                     16,545               14,278
    Prepaid expenses                                                                  7,428                2,828
    Derivatives at market value                                                      68,292                5,158
                                                                               ------------           ----------
                                                                                    419,008              186,357
                                                                               ------------            ---------

Investments                                                                          73,032               10,444
                                                                               ------------            ---------

Property and equipment                                                            1,072,129              700,044
    Less accumulated depreciation and depletion                                    (277,848)            (246,299)
                                                                               ------------            ---------
                                                                                    794,281              453,745
                                                                               ------------            ---------
Other assets:
    Regulatory asset                                                                  4,134                3,944
    Other, principally goodwill                                                      38,930               14,002
                                                                               ------------            ---------
                                                                                     43,064               17,946
                                                                               ------------            ---------
                                                                                 $1,329,385             $668,492
                                                                               ============            =========
                    LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
    Current maturities of long-term debt                                        $    13,960           $    1,330
    Notes payable                                                                   211,679               97,579
    Accounts payable                                                                247,596               80,355
    Accrued liabilities                                                              49,661               26,088
    Derivatives at market value                                                      65,960                5,158
                                                                               ------------           -----------
                                                                                    588,856              210,510
                                                                               ------------           ----------
Long-term debt, net of current maturities                                           307,092              160,700
                                                                               ------------           ----------

Deferred credits and other liabilities:
    Investment tax credits                                                            2,530                3,022
    Federal income taxes                                                             62,679               47,668
    Reclamation and regulatory liability                                             22,340               22,494
    Other                                                                            16,516                7,492
                                                                               ------------           ----------
                                                                                    104,065               80,676
                                                                               ------------           ----------
Minority interest in subsidiaries                                                    37,961                    -
                                                                               ------------           ----------
Commitments and contingencies (Notes 10, 11 and 14)

Common stock equity:
    Common stock $1 par value; 50,000,000 shares authorized;
      Issued: 23,416,396 shares in 2000 and 21,739,030 shares in 1999                23,416               21,739
    Additional paid-in capital                                                       77,326               40,658
    Retained earnings                                                               191,482              162,239
    Treasury stock                                                                        -               (8,030)
    Accumulated other comprehensive income (loss)                                      (813)                   -
                                                                               ------------           ----------
                                                                                    291,411              216,606
                                                                               ------------           ----------
                                                                                 $1,329,385             $668,492
                                                                               ============           ==========
At December 31,
2002
 
2001
 
(in thousands, except share amounts)
                                      ASSETS
 
 
 
 
 
 

Current assets:
 
 
     Cash and cash equivalents
 
 
$
45,042
 
$
14,832
 
     Restricted cash
 
 
 
1,070
 
 
--
 
     Receivables (net of allowance for doubtful accounts of $1,771
 
 
         and $2,677, respectively) -
 
 
       Customers
 
 
 
35,942
 
 
26,352
 
       Affiliates
 
 
 
53,984
 
 
9,457
 
       Other
 
 
 
5,596
 
 
5,982
 
     Materials, supplies and fuel
 
 
 
16,206
 
 
10,399
 
     Prepaid expenses
 
 
 
2,372
 
 
9,822
 
     Deferred income taxes
 
 
 
2,709
 
 
3,855
 
     Other
 
 
 
325
 
 
--
 
 
 
 
 
163,246
 
 
80,699
 
Investments
 
 
 
14,531
 
 
51,543
 
Property and equipment
 
 
 
1,504,898
 
 
1,249,800
 
     Less accumulated depreciation
 
 
 
(301,054
)
 
(240,472
)
 
 
 
 
1,203,844
 
 
1,009,328
 
Other assets:
 
 
     Regulatory asset
 
 
 
4,350
 
 
4,071
 
     Goodwill
 
 
 
30,562
 
 
25,566
 
     Intangible assets
 
 
 
77,661
 
 
85,983
 
     Other
 
 
 
16,864
 
 
16,239
 
 
 
 
 
129,437
 
 
131,859
 
 
 
 
$
1,511,058
 
$
1,273,429
 
                       LIABILITIES AND STOCKHOLDER'S EQUITY
 
 
Current liabilities:
 
 
     Current maturities of long-term debt
 
 
$
22,131
 
$
35,881
 
     Notes payable
 
 
 
50,000
 
 
450
 
     Notes payable - affiliate
 
 
 
454,824
 
 
447,125
 
     Accounts payable
 
 
 
28,653
 
 
13,271
 
     Accounts payable - affiliate
 
 
 
2,990
 
 
4,385
 
     Accrued liabilities
 
 
 
22,796
 
 
16,929
 
     Derivative liabilities
 
 
 
9,345
 
 
10,212
 
 
 
 
 
590,739
 
 
528,253
 
     Long-term debt, net of current maturities
 
 
 
557,195
 
 
415,314
 

Deferred credits and other liabilities:
 
 
     Deferred income taxes
 
 
 
101,046
 
 
65,094
 
     Regulatory liability
 
 
 
5,395
 
 
6,249
 
     Derivative liabilities
 
 
 
7,844
 
 
5,949
 
     Other
 
 
 
24,154
 
 
11,306
 
 
 
 
 
138,439
 
 
88,598
 
Minority interest in subsidiaries
 
 
 
6,457
 
 
19,536
 
Commitments and contingencies (Notes 11, 12 and 16)
 
 

Stockholder's equity:
 
 
     Common stock $1 par value; 50,000,000 shares authorized;
 
 
        Issued: 23,416,396 shares in 2002 and 2001
 
 
 
23,416
 
 
23,416
 
     Additional paid-in capital
 
 
 
80,961
 
 
80,961
 
     Retained earnings
 
 
 
131,906
 
 
121,875
 
     Accumulated other comprehensive loss
 
 
 
(18,055
)
 
(4,524
)
 
 
 
 
218,228
 
 
221,728
 
 
 
 
$
1,511,058
 
$
1,273,429
 
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS POWER, INC.
                       (formerly Black Hills Corporation)
                      
CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31,                                                 2000              1999             1998
                                                                         ----              ----             ----
                                                                                      (in thousands)

Operating activities:
    Net income available for common stock                               $52,770           $37,067           $25,808
    Principal non-cash items-
        Depreciation, depletion and amortization                         32,864            25,067            24,037
        Oil and gas ceilings test write-down                                  -                 -            13,546
        Derivative fair value adjustment, net                            (2,332)                -                 -
        Gain on sales of assets                                          (3,736)           (2,541)                -
        Deferred income taxes and investment tax credits                  1,937             2,291            (2,535)
        Minority interest                                                11,273            (1,935)                -
     Change in operating assets and liabilities-
        Accounts receivable                                            (201,307)            2,232           (46,821)
        Materials, supplies, fuel and other current assets               (3,513)           (4,003)           (2,954)
        Accounts payable                                                165,394             6,268            41,465
        Accrued liabilities                                              18,678             4,013             2,244
        Other, net                                                        2,444             5,284               (60)
                                                                     ----------         ---------          --------
                                                                         74,472            73,743            54,730
                                                                     ----------         ---------          --------
Investing activities:
    Property additions                                                 (134,855)         (102,290)          (25,265)
    Increase in investments                                             (13,646)          (52,319)           (1,960)
    Payment for acquisition of net assets, net of cash acquired         (28,688)                -                 -
    Proceeds from sales of assets                                         5,500             3,463                 -
    Available-for-sale securities purchased                                   -            (7,870)          (22,361)
    Available-for-sale securities sold                                    4,660            22,959            13,655
                                                                     ----------        ----------         ---------
                                                                       (167,029)         (136,057)          (35,931)
                                                                     ----------        ----------         ---------
Financing activities:
    Dividends paid                                                      (23,527)          (22,602)          (21,737)
    Treasury stock purchased                                             (1,037)           (4,949)           (3,081)
    Common stock issued                                                   3,852               424               273
    Increase in short-term borrowings                                    73,848            92,489             5,067
    Long-term debt - issuance                                            60,082                 -                 -
    Long-term debt - repayments                                          (1,330)           (1,330)           (1,331)
    Subsidiary distributions to minority interests                      (10,900)                -                 -
                                                                      ----------       ----------         ---------
                                                                        100,988            64,032           (20,809)
                                                                      ----------       ----------         ---------

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

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

Supplemental disclosure of cash flow information:

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

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

Non-cash exchange of treasury stock and preferred stock
for common stock (Note 1)                                               $13,067           $     -           $     -
Years ended December 31,
2002
 
2001
 
2000
 
(in thousands)
Operating activities:
 
 
 
 
 
 
 
 
     Net income
 
 
$
41,179
 
$
48,106
 
$
52,848
 
     Income from discontinued operations
 
 
 
--
 
 
(4,832
)
 
(12,570
)
     Adjustments to reconcile net income to net cash
 
 
       provided by operating activities-
 
 
       Depreciation and amortization
 
 
 
43,933
 
 
31,703
 
 
18,612
 
       Provision for valuation allowances
 
 
 
(906
)
 
8,135
 
 
279
 
       Gain on sales of assets
 
 
 
--
 
 
--
 
 
(3,736
)
       Deferred income taxes
 
 
 
22,993
 
 
4,522
 
 
1,293
 
       Undistributed earnings in associated companies
 
 
 
(3,964
)
 
--
 
 
--
 
       Minority interest
 
 
 
3,162
 
 
4,186
 
 
11,338
 
       Accounting change
 
 
 
(896
)
 
--
 
 
--
 
     Change in operating assets and liabilities-
 
 
       Accounts receivable and other current assets
 
 
 
(55,951
)
 
2,436
 
 
(14,186
)
       Accounts payable and other current liabilities
 
 
 
46,477
 
 
(3,289
)
 
12,213
 
       Other operating activities
 
 
 
1,854
 
 
(1,044
)
 
(6,718
)
 
 
 
 
97,881
 
 
89,923
 
 
59,373
 
Investing activities:
 
 
     Property, plant and equipment additions
 
 
 
(178,981
)
 
(316,809
)
 
(46,975
)
     Payment for acquisition of net assets, net of cash acquired
 
 
 
(13,243
)
 
(199,001
)
 
(28,688
)
     Payment for acquisition of minority interest
 
 
 
(13,800
)
 
(16,676
)
 
--
 
     Notes receivable from associated companies, net
 
 
 
--
 
 
81,134
 
 
(87,835
)
     Other investing activities
 
 
 
(19
)
 
--
 
 
468
 
 
 
 
 
(206,043
)
 
(451,352
)
 
(163,030
)
Financing activities:
 
 
     Dividends paid on common stock
 
 
 
(31,148
)
 
(28,070
)
 
(23,527
)
     Increase in short-term borrowings, net
 
 
 
49,550
 
 
262,944
 
 
84,379
 
     Long-term debt - issuance
 
 
 
160,632
 
 
144,103
 
 
60,082
 
     Long-term debt - repayments
 
 
 
(32,501
)
 
(13,960
)
 
(1,330
)
     Other financing activities
 
 
 
(8,161
)
 
(1,453
)
 
(7,048
)
 
 
 
 
138,372
 
 
363,564
 
 
112,556
 
       Increase in cash and cash equivalents
 
 
 
30,210
 
 
2,135
 
 
8,899
 
Cash and cash equivalents:
 
 
     Beginning of year
 
 
 
14,832
 
 
12,697
 
 
3,798
 
     End of year
 
 
$
45,042
 
$
14,832
 
$
12,697
 
Supplemental disclosure of cash flow information:
 
 
     Cash paid during the period for-
 
 
       Interest
 
 
$
50,134
 
$
44,820
 
$
26,258
 
       Income taxes paid (refunded)
 
 
$
(23,325
)
$
22,891
 
$
16,427
 
Non-cash net assets acquired through issuance of common
 
 
  stock (Note 11)
 
 
$
3,826
 
$
3,635
 
$
34,493
 
Stock dividend distribution to Black Hills Corporation, the
 
 
  parent company of Black Hills Power, Inc. (Note 2)
 
 
$
--
 
$
89,643
 
$
--
 
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
BLACK HILLS POWER, INC.
                       (formerly Black Hills Corporation)
             
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'SSTOCKHOLDER’S EQUITY


                                                                                                               Accumulated
                                       Common Stock        Additional                    Treasury Stock           Other
                                   ----------------------    Paid-In       Retained     ------------------    Comprehensive
                                    Shares      Amount       Capital       Earnings     Shares     Amount     Income (loss)  Total
                                    ------      ------       -------       --------     ------     ------     -------------  -----
                                                                               (in thousands)

Balance at
December 31, 1997                    21,705    $ 21,705     $   39,995     $  143,703          -   $      -     $      -   $205,403
                                   --------    --------     ----------     ----------   --------- ----------   ----------  --------
Comprehensive Income:
   Net income                             -           -              -         25,808          -          -            -     25,808
                                   --------    --------     ----------     ----------   --------- ----------   ----------  --------
                                          -           -              -         25,808          -          -            -     25,808

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

Balance at
December 31, 1998                    21,719      21,719         40,254        147,774       (141)    (3,081)           -   $206,666
                                   --------    --------     ----------     ----------   --------  ---------    ----------  --------
Comprehensive Income:
   Net income                             -           -              -         37,067          -          -             -    37,067
                                   --------    --------     ----------     ----------   --------  ---------    ----------  --------
                                          -           -              -         37,067          -          -             -    37,067

Dividends on common stock                 -           -              -        (22,602)         -          -             -   (22,602)
Issuance of common stock                 20          20            404              -          -          -             -       424
Treasury stock acquired, net              -           -              -              -       (227)    (4,949)            -    (4,949)
                                   --------    --------     ----------     ----------   --------  ---------    ----------  --------


Balance at
December 31, 1999                    21,739      21,739         40,658        162,239       (368)    (8,030)            -  $216,606
                                   --------    --------     ----------     ----------   --------  ---------    ----------  --------
Comprehensive Income:
   Net income                             -           -              -         52,848          -          -             -    52,848
   Unrealized loss on available
   for sale securities                    -           -              -              -          -          -          (813)     (813)
                                   --------    --------     ----------     -----------  --------  ---------    ----------  --------
                                          -           -              -         52,848          -          -          (813)   52,035

Dividends on preferred stock              -           -              -            (78)         -          -             -       (78)
Dividends on common stock                 -           -              -        (23,527)         -          -             -   (23,527)
Issuance of common stock                140         140          4,428              -          -          -             -     4,568
Issuance of common stock
  for acquisition                     1,537       1,537         32,240              -          -          -             -    33,777
Treasury stock acquired, net              -           -              -              -        368      8,030             -     8,030
                                   --------    --------     ----------     -----------  --------  ---------    ----------  --------

Balance at
December 31, 2000                    23,416    $ 23,416     $   77,326     $   191,482         -  $       -    $     (813) $291,411
                                     ======    ========     ==========     ===========  ========  =========    ==========  ========

AND COMPREHENSIVE INCOME
Accumulated
 
Common Stock
 
Additional
 
Other
 
 
Paid-In
 
Retained
 
Comprehensive
 
Shares
 
Amount
 
Capital
 
Earnings
 
Loss
 
Amount
 
(in thousands)

Balance at December 31, 1999
 
 
 
21,739
 
$
21,739
 
$
40,658
 
$
162,239
 
$
--
 
$
224,636
 
Comprehensive Income:
 
 
   Net income
 
 
 
--
 
 
--
 
 
--
 
 
52,848
 
 
--
 
 
52,848
 
     Total comprehensive income
 
 
 
--
 
 
--
 
 
--
 
 
52,848
 
 
--
 
 
52,848
 
Dividends on preferred stock
 
 
 
--
 
 
--
 
 
--
 
 
(78
)
 
--
 
 
(78
)
Dividends on common stock
 
 
 
--
 
 
--
 
 
--
 
 
(23,527
)
 
--
 
 
(23,527
)
Issuance of common stock
 
 
 
140
 
 
140
 
 
4,428
 
 
--
 
 
--
 
 
4,568
 
Issuance of common stock
 
 
  for acquisition
 
 
 
1,537
 
 
1,537
 
 
32,240
 
 
--
 
 
--
 
 
33,777
 
Balance at December 31, 2000
 
 
 
23,416
 
 
23,416
 
 
77,326
 
 
191,482
 
 
--
 
 
292,224
 
Comprehensive Income:
 
 
   Net income
 
 
 
--
 
 
--
 
 
--
 
 
48,106
 
 
--
 
 
48,106
 
   Unrealized loss on mark to
 
 
     market interest rate swaps
 
 
 
--
 
 
--
 
 
--
 
 
--
 
 
(1,597
)
 
(1,597
)
   Initial impact of adoption of
 
 
     SFAS 133, net of minority
 
 
       interest
 
 
 
--
 
 
--
 
 
--
 
 
--
 
 
(2,927
)
 
(2,927
)
     Total comprehensive income
 
 
 
--
 
 
--
 
 
--
 
 
48,106
 
 
(4,524
)
 
43,582
 
Dividends on common stock
 
 
 
--
 
 
--
 
 
--
 
 
(28,070
)
 
--
 
 
(28,070
)
Earnout consideration on
 
 
  acquisition
 
 
 
--
 
 
--
 
 
3,635
 
 
--
 
 
--
 
 
3,635
 
Stock distribution to parent
 
 
 
--
 
 
--
 
 
--
 
 
(89,643
)
 
--
 
 
(89,643
)
Balance at December 31, 2001
 
 
 
23,416
 
 
23,416
 
 
80,961
 
 
121,875
 
 
(4,524
)
 
221,728
 
Comprehensive Income:
 
 
   Net income
 
 
 
--
 
 
--
 
 
--
 
 
41,179
 
 
--
 
 
41,179
 
   Other comprehensive loss,
 
 
     net of tax
 
 
 
--
 
 
--
 
 
--
 
 
--
 
 
(13,531
)
 
(13,531
)
     Total comprehensive income
 
 
 
--
 
 
--
 
 
--
 
 
41,179
 
 
(13,531
)
 
27,648
 
Dividends on common stock
 
 
 
--
 
 
--
 
 
--
 
 
(31,148
)
 
--
 
 
(31,148
)
Balance at December 31, 2002
 
 
 
23,416
 
$
23,416
 
$
80,961
 
$
131,906
 
$
(18,055
)
$
218,228
 
The accompanying notes to consolidated financial statements are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2000, 19992002, 2001 and 1998

2000
(1)     BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Power, Inc. and its subsidiaries (the Company) operate in threetwo primary operating groups: regulated electric utility and non-regulated independent
energy and  communications.power generation. Black Hills Power operates the public utility operations. The Company operates its independent  energy businessespower generation business through its direct and indirect subsidiaries:  Wyodak Resources related to coal, Black Hills
Exploration and Production related to oil and natural gas, Enserco Energy, Black
Hills Energy Resources and Black Hills Coal Network related to fuel marketing of
natural gas, oil and coal, respectively,  andsubsidiary, Black Hills Energy Capital and its
subsidiaries and Black Hills Generation related to independent power activities,
all  consolidated  for reporting  purposes as Black Hills Energy  Ventures;  and
operates its communications  operations through its indirect  subsidiaries Black
Hills Fiber Systems,  Black Hills FiberCom and Daksoft. For further descriptions(BHEC). The Company is a wholly owned subsidiary of the Company's business segments see Note 13.

During  2000,  the  Company  became a  wholly-owned  subsidiary  ofpublicly traded Black Hills Corporation (formerly  Black  Hills  Holding  Corporation)  through  a "plan(the Parent).
Use of exchange"  betweenEstimates
The preparation of financial statements in conformity with accounting principles generally accepted in the CompanyUnited States of America requires management to make estimates and Black  Hills  Corporation.  The  "planassumptions that affect the reported amounts of exchange"  provided  that each  shareassets and liabilities and disclosure of contingent assets and liabilities at the date of the Company's  common  stock  would be
exchangedfinancial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to allowance for one shareuncollectible accounts receivable, realization of common stockmarket value of the holding company. As a result:

o    all common  shareholders of Black Hills Power,  Inc.  (formerly Black Hills
     Corporation) became shareholders of Black Hills Corporation (formerly Black
     Hills Holding Corporation), the holding company;

o    Black Hills Power,  Inc.  became a  wholly-owned  subsidiary of Black Hills
     Corporation;

o    The debt securitiesderivatives due to commodity risk, intangible asset valuations and other  financial  obligations of Black Hills Power,
     Inc. continue to be obligations of Black Hills Power, Inc.

useful lives, long-lived asset values and useful lives, employee benefits plans and contingencies. Actual results could differ from those estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of the Company and its wholly-ownedwholly owned and majority-owned subsidiaries.subsidiaries and certain subsidiaries in which the Company’s ownership interest may be less than 50 percent but represents voting control. Generally, the Company uses equity method accounting for investments of which it owns between 20 and 50 percent and investments in partnerships under 20 percent if the Company exercises significant influence. All significant intercompany balances and transactions have been eliminated in consolidation except for revenues and expenses associated with intercompany coal
sales in accordance  with the  provisions  of Statement of Financial  Accounting
Standards  (SFAS)  No. 71,  "Accounting  for the  Effects  of  Certain  Types of
Regulation."  Total  intercompany  coal sales not eliminated  were $9.7 million,
$7.7 million and $10.3 million in 2000, 1999 and 1998, respectively.

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

consolidation.
As noteddiscussed in Note 14,16, Black Hills Energy Capital made several acquisitions during 2000.2002 and 2001. The Company'sCompany’s consolidated statements of income include operating activity of these companies beginning with their acquisition date.
The Company  uses the  proportionate  consolidation  method to account  for its
working interests in oilconsolidated financial statements also include assets, liabilities and gas properties.

income from discontinued operations (see Note 2).
Minority Interest in Subsidiaries
Minority interest in resultsthe accompanying Consolidated Statements of operations  of  consolidated   subsidiariesIncome represents the  minority  shareholders' share of the income or loss of variouscertain consolidated subsidiaries attributable to the minority shareholders of those subsidiaries. The minority interest in the consolidated  balance
sheetsaccompanying Consolidated Balance Sheets reflect the amount of the underlying net assets of variousthose certain consolidated subsidiaries attributable to the minority shareholders.

shareholders of those subsidiaries.
Earnings attributable to minority ownership in certain subsidiaries are generally shown on the accompanying consolidated statement of income on a pre-tax basis as the subsidiaries with minority investors are typically limited liability companies or partnerships which pay no tax at the corporate or partnership level.
Regulatory Accounting
The Company'sCompany’s regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the Federal Energy Regulatory Commission (FERC). These accounting policies differ in some respects from those used by the Company'sCompany’s non-regulated businesses.
The Company'sCompany’s electric operations follow the provisions of SFASStatement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71), and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating its electric operations. As a result of the Company'sCompany’s 1995 rate case settlement, a 50-year depreciable life for Neil Simpson II is used for financial reporting purposes. If the Company were not following SFAS 71, a 35 to 40 year life would be more appropriate, which would increase depreciation expense by approximately $0.6 — $1.0 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to the Company'sCompany’s regulated generation operations. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company would be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that give rise to the discontinuance of SFAS 71 include increasing competition that could restrict the Company'sCompany’s ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews these criteria to ensure the continuing application of SFAS 71 is appropriate.
Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Available-for-sale Securities

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

Inventory
Materials, supplies and fuel are generally stated at the lower of cost or market on a first-in, first-out basis.
Property, Plant and Equipment
The components of property, plant and equipment are as follows, at December 31:

                                            2000                     1999
                                                   (in thousands)

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

2002
 
2001
 
(in thousands)
Electric utility
 
 
$
613,925
 
$
580,090
 
Independent power
 
 
 
890,973
 
 
669,710
 
 
 
 
$
1,504,898
 
$
1,249,800
 
Additions to property, plant and equipment are recorded at cost when placed in service. Included in the cost of regulated construction projects is an allowance for funds used during construction (AFUDC) which represents the approximate composite cost of borrowed funds and a return on capital used to finance the project. The AFUDC was computed at an annual composite rate of 9.7, 8.39.1, 10.2 and 10.19.7 percent during 2000,  19992002, 2001 and 1998,2000, respectively. In addition, the Company capitalizes interest, when applicable, on certain non-regulated construction projects. The amount of AFUDC and interest capitalized was $2.0$11.4 million, $1.2$6.8 million and $0.2$0.9 million in 2000,  19992002, 2001 and 1998,2000, respectively. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, together with removal cost less salvage, is charged to accumulated depreciation. Retirement or disposal of all other assets, except for oil and gas properties as described below, resultresults in gains or losses recognized as a component of income. Repairs and maintenance of property are charged to operations as incurred.
Depreciation provisions for regulated electric property, plant and equipment is computed on a straight-line basis using an annual composite rate of 3.1 percent in 2002, 3.0 percent in 2001 and 2.8 percent in 2000,  3.1 percent in 1999 and 3.0 percent in 1998.2000. Non-regulated property, plant and equipment is depreciated on a straight-line basis using estimated useful lives ranging from 3 to 3940 years.  Depletion  of  coal,  oil  and gas
properties is computed
Deferred Financing Costs
Deferred financing costs are amortized using the cost method.

The Company  periodically  evaluates assets under SFAS No. 121,  "Accounting foreffective interest method over the Impairmentterm of Long-Lived  Assets and  Long-Lived  Assets to Be Disposed Of,"
which  requires that such assets be probable of future  recovery at each balance
sheet date. As of December 31, 2000 and 1999, no  significant  write-downs  were
required.

the related debt.
Goodwill and Intangible Assets
Goodwill represents the excess of acquisition costs over the fair market value of the net assets of acquired businesses and is  beingthrough 2001 was amortized on a straight-line basis over the estimated useful lives of such assets, which range from 8 to 25 years. Goodwill expense was $0.7 million and $1.0 million for the years ended December 31, 2001 and 2000, respectively.
The cost of other acquired intangibles is amortized on a straight-line basis over their estimated useful lives. Amortization expense was $3.1$4.1 million, $2.7$2.5 million and $0.7$1.5 million in 2000,   19992002, 2001 and 1998,2000, respectively. Accumulated amortization was $6.7$14.9 million, $3.6$4.0 million and $0.9$1.5 million at December 31, 2002, 2001 and 2000, 1999respectively.
Impairment of Long-Lived Assets and 1998, respectively.

Intangible Assets
The Company periodically evaluates whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of its long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, the Company would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, the Company would recognize an impairment loss. No impairment loss was recorded during 2002, 2001 or 2000.
Income Taxes
The Company uses the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized, at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. ToThe Company classifies deferred tax assets and liabilities into current and non-current amounts based on the extent suchclassification of the related assets and liabilities.
The Company files a consolidated federal income tax return with other affiliates. For financial statement purposes, consolidated federal income taxes are recoverableallocated to the individual companies based on amounts calculated on a separate return basis.
Revenue Recognition
Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or payable  through  future  rates,   regulatory  assets  and
liabilitiesdeterminable price, delivery has occurred or services have been recorded in the accompanying consolidated balance sheets.

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



Revenue Recognition

Generally,reasonably assured. For long-term non-utility power sales agreements revenue is recognized ateither in accordance with Emerging Issues Task Force (EITF) Issue No. 91-6, “Revenue Recognition of Long-Term Power Sales Contracts” (EITF 91-6), or in accordance with SFAS No. 13, “Accounting for Leases,” (SFAS 13) as appropriate. Under EITF 91-6, revenue is generally recognized as the time  products  and  services  are
delivered.  Fuel  marketing  businesses  also use the  mark-to-market  method of
accounting. Under that method all energy trading activities are recorded at fair
value aslower of the balance  sheet date and net gainsamount billed or losses  resulting  from the revaluationaverage rate expected over the life of these  contracts to fair valuethe agreement. Under SFAS 13, revenue is generally levelized over the life of the agreement. For its Investment in Associated Companies (see Note 4), which are recognized  currentlyinvolved in the
results of  operations.  In the  fourth  quarter of 2000,power generation, the Company adopted
Securities and Exchange  Commission Staff Accounting  Bulletin No. 101, "Revenue
Recognition" (SAB 101), which provides guidance onuses the recognition, presentation
and disclosure of revenue in financial  statements.  The adoption of SAB 101 did
not have a material impact on the financial statements.

Oil and Gas Operations

The Company  accounts forequity method to recognize as earnings its oil and gas activities under the full cost method.
Under the full cost method,  all productive and  nonproductive  costs related to
acquisition,  exploration and development  drilling  activities are capitalized.
These costs are  amortized  using a  unit-of-production  method based on volumes
produced and proved reserves. Any conveyances of properties,  including gains or
losses on abandonments of properties,  are treated as adjustments to the costpro rata share of the properties with no gainnet income or loss recognized.  Under the full cost method, net
capitalized costs may not exceed the present value of proved reserves.

Use of Estimates

The preparation of financial  statements in conformity  with generally  accepted
accounting principles in the United States requires management to make estimates
and assumptions  that affect the reported  amounts of assets and liabilities and
disclosure of  contingent  assets and  liabilities  at the date of the financial
statementsassociated company.
Reclassifications
Certain 2001 and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Ultimate results could differ from those estimates.

Reclassifications

Certain 1999 and 19982000 amounts in the financial statements have been reclassified to conform to the 20002002 presentation. These reclassifications had no effect on the Company'sCompany’s common stockholder'sstockholder’s equity or results of operations, as previously reported.
Recently Adopted Accounting Pronouncements
In June 1998,2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 133141, “Business Combinations,” (SFAS 133),141) and No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). The Company has adopted SFAS 141, which requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method of accounting. Under SFAS 142, goodwill and intangible assets with indefinite lives are no longer amortized but the carrying values are reviewed annually (or more frequently if impairment indicators arise) for impairment. Intangible assets with a defined life will continue to be amortized over their useful lives (but with no maximum life). The amortization provisions of SFAS 142 apply to goodwill and intangible assets acquired after June 30, 2001. With respect to goodwill and intangible assets acquired prior to July 1, 2001, the Company was required to adopt SFAS 142 effective January 1, 2002. The cumulative effect of the change in accounting principle, net of tax at January 1, 2002, was a $0.9 million benefit. If the carrying value exceeds the fair value, an impairment loss will be recognized. A discounted cash flow approach was used to determine fair value of the Company’s businesses for the purposes of testing for impairment. Intangible assets with a defined life will continue to be amortized over their useful lives (but with no maximum life). The Company adopted SFAS 142 on January 1, 2002.
The pro forma effects of adopting SFAS No. 142 for the years ended December 31, 2002, 2001 and 2000 are as follows (in thousands):
2002
 
2001
 
2000
 
Net income as reported
 
 
$
41,179
 
$
48,106
 
$
52,848
 
Cumulative effect of change in
 
 
  accounting principle, net of tax
 
 
 
(896
)
 
--
 
 
--
 
Income excluding cumulative effect of change in
 
 
  accounting principle
 
 
 
40,283
 
 
48,106
 
 
52,848
 
Add: goodwill amortization
 
 
 
--
 
 
695
 
 
1,008
 
Net income excluding cumulative effect of change in
 
 
  accounting principle and goodwill amortization
 
 
$
40,283
 
$
48,801
 
$
53,856
 
The cumulative effect adjustment recognized upon adoption of SFAS 142 was $0.9 million (after tax). The adjustment consisted of income from the after-tax write-off of negative goodwill from prior acquisitions in our Independent Power segment.
The Company's goodwill and intangible assets are contained within the Independent Power segment. Changes to goodwill and intangible assets during the year ended December 31, 2002, including the effects of adopting SFAS No. 142, are as follows (in thousands):
Goodwill
 
Other Intangible Assets
 
Balance at December 31, 2001, net of
 
 
 
 
 
 
   accumulated amortization
 
 
$
25,566
 
$
85,983
 
Change in accounting principle
 
 
 
1,493
 
 
--
 
Additions
 
 
 
3,826
 
 
9,640
 
Adjustments
 
 
 
(323
)
 
(13,854
)
Amortization expense
 
 
 
--
 
 
(4,108
)
Balance at December 31, 2002, net of
 
 
   accumulated amortization
 
 
$
30,562
 
$
77,661
 
Intangible assets totaled $77.7 million, net of accumulated amortization of $14.9 million at December 31, 2002 and $86.0 million, net of accumulated amortization of $4.0 million at December 31, 2001. Intangible assets are primarily related to site development fees and above-market long-term contracts, and all have definite lives ranging from 7 to 40 years, over which they continue to be amortized. Amortization expense for intangible assets for the next five years is expected to be approximately $4.1 million a year.
Goodwill additions during the year ended December 31, 2002, were from contingent consideration related to the July 7, 2000 acquisition of Indeck Capital, Inc. (see Note 11).
Intangible asset additions during the year ended December 31, 2002 were primarily the result of a $9.3 million addition related to preliminary purchase allocations in the acquisition of additional ownership interest in the Harbor Cogeneration Facility (See Note 16). This intangible asset primarily relates to an acquired ownership of additional interest in a contract termination payment stream at the facility.
Adjustments of intangible assets during the year ended December 31, 2002 primarily relate to final adjustments to the preliminary purchase price allocation of the Company's third quarter 2001 Las Vegas Cogeneration acquisition.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS 144). SFAS 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions" (APB 30). SFAS 144 establishes a single accounting model for long-lived assets to be disposed of by sale and resolves implementation issues related to SFAS 121. The Company adopted SFAS 144 effective January 1, 2002. Adoption did not have a material impact on the Company's consolidated financial position, results of operations or cash flows.
Recently Issued Accounting Pronouncements
In June 2001, the FASB issued Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred with the associated asset retirement costs being capitalized as part of the carrying amount of the long-lived asset. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company adopted SFAS 143 on January 1, 2003. Adoption did not have an effect on the Company's consolidated financial statements.
Derivatives and Hedging Activities
The Company accounts for its derivative and hedging activities in accordance with Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities."Activities" (SFAS 133). SFAS 133 as amended,  establishes  accounting and reporting standards requiringrequires that every  derivative instrumentinstruments be recorded in the balance sheet as either an asset or liability measured at its fair value. The  StatementSFAS 133 requires that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
SFAS 133 allows special hedge accounting for qualifying fair value and cash flow hedges. The  StatementSFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.
The Company adopted SFAS 133 requires that on date of initial  adoption,  an entity shall  recognize
all freestanding derivative instruments in the balance sheet as either assets or
liabilities  and  measure  them  at  fair  value.   The  difference   between  a
derivative's  previous carrying amount and its fair value shall be reported as a
transition  adjustment.  The transition  adjustment resulting from adopting this
Statement  shall be reported  in net income or other  comprehensive  income,  as
appropriate,  as the effect of a change in  accounting  principle in  accordance
with  paragraph  20 of  Accounting  Principles  Board  Opinion  No. 20 (APB 20),
"Accounting Changes."



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

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

At December 31, 2000,January 1, 2001. On January 1, 2001, the Company had interest rate swaps documented as cash flow hedges. These contracts arewere defined as derivatives under SFAS 133 and meetmet the requirements for cash flow hedges. Because thesethe contracts were documented as hedges prior to adoption, the transition adjustment will bewas reported in accumulated other comprehensive income. The interest rate swap transactions have
a notional  amount of $127.4aggregated entry for these derivatives identified as cash flow hedges increased derivative assets by $0.3 million, and the associated  transition  adjustments
will increaseincreased derivative liabilities by $7.5$7.8 million and decreasedecreased accumulated other comprehensive income by $7.5 million.

million pre-tax.
(2)      PRICENON-CASH DIVIDEND AND DISCONTINUED OPERATIONS
During the quarter ended March 31, 2001, the Company distributed a non-cash dividend to its 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. The Company therefore no longer operates in the coal production segment, oil and natural gas production segment, energy marketing segment or communications as the Company had indirectly owned the companies operating in these segments through its ownership of Wyodak. As a result, the Company's only subsidiary is Black Hills Energy Capital and its subsidiaries. The Company's 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 the continuing operations of the Company 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:
2001*
 
2000
 
(in thousands)
Revenue
 
 
$
197,274
 
$
1,425,675
 
Income before income taxes
 
 
 
7,849
 
 
20,345
 
Federal income taxes
 
 
 
3,017
 
 
7,775
 
Net income
 
 
 
4,832
 
 
12,570
 
_________________
*Includes only one month of operations
(3)      RISK MANAGEMENT ACTIVITIES
The Company’s activities in the regulated and unregulated energy sector expose it to a number of risks in the normal operations of its businesses. Depending on the activity, the Company is exposed to varying degrees of market risk and counterparty risk. The Company has 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. The Company is exposed to the following market risks:
commodity price risk primarily associated with its fuel procurement for its gas fired generation assets; and

interest rate risk associated with variable rate credit facilities and project financing floating rate debt as described in Notes 7 and 8.

Energy Activities
The Company has a portfolio of natural gas-fired generation assets located throughout several western states. Most of these generation assets are locked into long-term tolling contracts with third parties whereby any commodity price risk is transferred to the third party. However, the Company does have some natural gas fueled generation assets under long term contracts and a few merchant plants that do possess market risk stemmingfor fuel purchases.
A potential risk related to power sales is the risk arising from changes in commodity prices.the sale of wholesale power that exceeds the Company’s generating capacity. These changes could cause fluctuations in the Company's earnings and cash flows.
In the normal course of business,short positions can arise from unplanned plant outages or from unanticipated load demands. To control such risk, the Company actively managesrestricts wholesale off-system sales to amounts by which the Company’s anticipated generating capabilities exceed its exposure to
these market  risks by entering  into various  hedging  transactions,  which are
authorized  under its policies  that place clear  controls on these  activities.
Hedging  transactions  involve  the use ofanticipated load requirements plus a variety  of  derivative  financial
instruments.

Effective  January 1, 1999,required reserve margin.
In 2001, the Company adoptedacquired several natural gas swaps when it completed the provisions of EITF 98-10,
pursuant toLas Vegas Cogeneration acquisition on August 31, 2001 (Note 16). The project’s 53 megawatt Las Vegas I plant has a long-term fixed price power sales agreement and an index-priced natural gas purchase contract for 5,000 MMBtus per day through April 30, 2010. These swaps fixed the implementation requirements stated therein. The resulting effect
of  adoptionlong-term purchase price of the provisionsindex-priced natural gas purchase contract. At acquisition close, the fair value of EITF  98-10these swaps was to  alter$6.0 million. These swaps were executed with Enron North America Corp. (Enron), which is currently in bankruptcy proceedings.
These swaps met the Company's
comprehensive methoddefinition of accounting for energy-related  contracts,  as defined in
that Statement.derivatives under SFAS 133. The Company accounts for all energy trading  activities at fair valueelected to treat these derivatives as of the
balance sheet date and  recognizes  currently the netcash flow hedges so that any gains or losses resulting
from the  revaluation  of  these  contracts  to fair  value  in its  results  of
operations.  As a result,  substantially all of the energy trading activities of
the Company's gas marketing,  crude oil marketing, and coal marketing operations
are accounted for under fair value accounting  methodology as prescribed in EITF
98-10.

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

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



The quantities and maximum terms of derivative  financial  instruments  held for
trading purposes at December 31, 2000 and 1999 are as follows:

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

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

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

                                                                                                                Max. Term
December 31, 1999                                                            Volume Covered                      (Years)
- -----------------                                                            --------------                      -------
(MMBtus)
Natural gas futures contracts purchased                                            860,000                          1
Natural gas basis swaps purchased                                               17,741,500                          4
Natural gas basis  swaps sold                                                   18,390,517                          4
Natural gas fixed-for-float swaps purchased                                      9,490,486                          1
Natural gas fixed-for-float swaps sold                                          10,994,521                          1
Natural gas collar transactions; puts purchased, calls sold                        408,500                          1
Natural gas collar transactions; calls purchased, puts sold                        318,500                          1



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

Instrument                                               Asset                    Liability                   Gain (loss)
- ----------                                               -----                    ---------                   ----------

Natural gas basis swaps                                 $13,391                    $23,963                     $(10,572)

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

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

Coal transactions                                         5,370                      4,460                          910

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

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


There were no  significant  differences  between the fair values of derivative
assetsthe swaps could be deferred and liabilities at December 31, 1999.

Non-trading Energy Activities

To  reduce  risk from  fluctuationssubsequently recognized when the underlying hedged natural gas was consumed in the priceplant. The swaps were properly documented and met the criteria for cash flow hedges.
During the fourth quarter of oil and  natural  gas,2001, the Company enters into swaps and costless collar transactions. The transactions are
useddetermined that it was probable that Enron would default on its obligations to hedge price risk from sales of the  Company's  forecasted  crude oil and
natural  gas  production.  For such  transactions, the Company utilizes  hedge
accounting.

in conjunction with these swaps. Upon that determination, the Company ceased to account for these swaps as cash flow hedges. In addition, the Company recognized a $6.0 million pre-tax valuation reserve in recognition of Enron’s probable performance default and resulting consequence that the Company would not receive payment for these amounts.
Financing Activities
The Company engages in activities to manage risks associated with changes in interest rates. The Company has entered into floating-to-fixed interest rate swap agreements to reduce its exposure to interest rate fluctuations associated with its floating rate debt obligations. At December 31, 2000,2002, these hedges met effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2002, the Company had fixed-for-float  swaps for 17,000 barrels
per month for the year 2001 to hedge its crude oil price  risk with a fair value
that approximates cost. The Company had fixed-for-float swaps for 10,000 barrels
per month for the year 2002 to hedge its crude oil price  risk with a fair value$212.3 million of $0.4 million.  The Company also had costless  collars  (purchased puts - sold
calls) for 10,000  barrels per month for 2001 with a fair value of $0.3 million.
The  Company   hedged  its   forecasted   2001  natural  gas   production   with
fixed-for-float  swaps.  The Company  had  fixed-for-float  swaps for  1,581,000
MMBtus with a fair value of $(3.4)  million.  These amounts are not reflected in
the Company's December 31, 2000 consolidated balance sheet, but will be recorded
as part of the adoption of SFAS 133 on January 1, 2001.

Financing Activities

To reduce risk from  fluctuations  in interest  rates,  the Company  enters intonotional amount floating-to-fixed interest rate swap  transactions.  These transactions are used to hedge interest
rate risk for variable rate debt financing.  For such transactions,  the Company
utilizes hedge  accounting.  At December 31, 2000, the Company had interest rate
swaps, with a notional  amount of $127.4  million, having a maximum term of sixfour years and a fair value of $(7.5)$(17.2) million. These hedges are substantially effective and any ineffectiveness was immaterial.
On December 31, 2002 and 2001, the Company’s interest rate swaps and related balances were as follows (in thousands):
December 31, 2002
 
Notional
Weighted
Average
Fixed
Interest
Rate
Maximum
Terms in
Years
Current
Assets
Non-
current
Assets
Current
Liabilities
Non-
current
Liabilities
Accumulated
Other
Comprehensive
Income (Loss)

Swaps on project
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  financing
 
 
$
212,256
 
 
5.98
%
 
4
 
$ --
 
 
$ --
 
 
$
9,345
 
$
7,844
 
$
(17,189
)
December 31, 2001
 
 

Swaps on project
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  financing
 
 
$
316,397
 
 
5.85
%
 
4
 
$ --
 
 
$
5,746
 
$
10,212
 
$
5,949
 
$
(14,415
)
The Company anticipates a portion of unrealized losses recorded in accumulated other comprehensive income will be realized as increased interest expense in 2003. Based on December 31, 2002 market interest rates, $9.3 million will be realized as additional interest expense during 2003. Estimated and realized amounts will likely change during 2003 as market interest rates change.
At December 31, 2000,2002, the Company had $162.2$871.9 million of outstanding, floating-ratevariable-rate debt of which $34.8$659.6 million was not offset with interest rate swap transactions that effectively convert the debt to a fixed rate. Credit Risk

A 100 basis point increase in interest rates would cause interest expense to increase $6.6 million.
During 2002, the Company entered into a $50 million treasury lock to hedge a portion of the Company’s $75 million First Mortgage Bond offering completed in August 2002. The treasury lock cash settled on August 8, 2002, the bond pricing date, and resulted in a $1.8 million loss. This treasury lock was treated as a cash flow hedge and accordingly the resulting loss is carried in Accumulated other comprehensive loss on the Consolidated Balance Sheet and amortized over the life of the related bonds as additional interest expense.
In addition, at December 31, 2001, the Company had a $100 million forward starting floating-to-fixed interest rate swap to hedge the anticipated floating rate debt financing related to the risk  associated  with price  movements,  credit risk is also
inherentCompany’s Las Vegas II Plant. This swap terminated during the second quarter 2002 and resulted in a $1.1 million gain. This swap was treated as a cash flow hedge and accordingly in the Company's risk management activities. second quarter of 2002 the resulting gain was carried in Accumulated other comprehensive income on the Consolidated Balance Sheet and was to be amortized over the life of the anticipated long-term financing. In the third quarter of 2002, this cash flow hedge was determined to be ineffective due to uncertainties about the eventual timing and form of financing for this project. As a result, $1.1 million was taken into earnings. The gain was offset by the expensing of approximately $1.0 million of deferred financing costs related to the anticipated financing.
Credit Risk
Credit risk relates to the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. WhileThe Company maintains credit policies with regard to its counterparties that the Company has not experienced  significant  losses duebelieves limit its overall credit risk.
The Company attempts to themitigate its credit risk associatedby conducting a majority of its business with these arrangements,  the Company has off-balance
sheet risk to the extent that theinvestment grade companies, obtaining netting agreements where possible and securing its exposure with less creditworthy counterparties to these transactions may fail
to perform as required by the termsthrough parental guarantees, prepayments and letters of each such contract.

(3)credit.
(4)     INVESTMENTS IN ASSOCIATED COMPANIES
Included in Investments on the Consolidated Balance Sheets are the following investments that have been recorded on the equity method of accounting:

o    
A 33.3312.6 percent, interest in  Millennium  Pipeline  Company,  L.P., a Texas
     limited  partnership  which owns and  operates an oil  pipeline in the Gulf
     Coast region of Texas.  The Company has a carrying amount in the investment
     of $6.9  million  and $4.8  million  as of  December  31,  2000  and  1999,
     respectively.  The  partnership  had  assets  of $22.0  million  and  $15.7
     million,  liabilities  of $1.0  million  and $1.6  million,  and net income
     (loss) of $2.8  million  and $(0.2)  million as of, and for the years ended
     December 31, 2000 and 1999, respectively.

o    As part of the Indeck Capital, Inc.  acquisition,  the Company acquired a 5
     percent,  66.9 percent and 55.3 percent interest in Energy Investors Fund, L.P., Energy Investors Fund II, L.P., and Project Finance Fund III, L.P., respectively, which in turn have investments in numerous electric generating facilities in the United States and elsewhere. The Company has a carrying amount in the investment of $8.4$11.0 million and $10.0 million at December 31, 2000.2002 and 2001, respectively, which includes $1.9 million that represents the cost of the investment over the underlying net assets of the funds. As of and for the year ended December 31, 2000,2002, the funds had assets of $186.8$160.7 million, liabilities of $16.0$0.7 million and net income of $27.1$25.8 million. o    As part of, and for the Indeck  Capital  acquisition,year ended December 31, 2001, the Company  acquired  afunds had assets of $215.1 million, liabilities of $0.7 million and net income of $37.2 million.

A 50 percent financial interest in two natural gas-fired cogenerationco-generation facilities located in Rupert and Glenns Ferry, Idaho. At  December  31,  2000 the
     Company'sThe Company’s carrying amount in the investment is $4.1$3.4 million and $3.9 million as of December 31, 2002 and 2001, respectively, which includes $0.5$0.6 million that represents the cost of the investment over the value of the underlying net assets of the projects. This excess is being  amortized
     over 19 years.  As of and for the year ended December 31, 2000,2002, these projects had assets of $26.0$24.5 million, liabilities of $18.7$17.1 million and net income of $0.9$0.7 million.

o    As part  of the  Indeck  Capital  acquisition,  the  Company  directly  and
     indirectly  acquired   approximately  32  percent  of  Harbor  Cogeneration
     Company,  which in turn owns an 80 megawatt  cogeneration  facility located
     near the City of Long Beach in Los Angeles County,  California. At December
     31, 2000 the Company's  carrying amount in the investment is $42.2 million,
     which  includes  $13.7 million that  represents  the cost of the investment
     over the value of the underlying net assets of Harbor. This excess is being
     amortized over 15 years. As of, and for the year ended December 31, 2000,
     Harbor2001, these projects had assets of $41.7$25.6 million, liabilities of $0.8$19.0 million and a net loss of $(0.4) million.
(5)     MINORITY INTEREST
The partnership agreements for two of the Company’s consolidated subsidiaries contain certain performance targets that result in the Company earning additional partnership equity in those subsidiaries when those targets are met. In 2002 certain targets were met by the subsidiaries resulting in a transfer of approximately $1.0 million of partnership equity from the minority interest to the Company. Of this amount, approximately $1.6 million was recorded as a reduction to “Minority interest” expense on the consolidated statement of income and approximately $(0.6) million was recorded as an item of $28.8 million.

(4)Other comprehensive loss (see Note 13) on the consolidated statement of stockholder’s equity and comprehensive income.
(6)     COMMON STOCK

During  2000,  the
The Company becameis a wholly-ownedwholly owned subsidiary of Black Hills Corporation. See Note 1 - Business Description.  Black Hills Corporation assumed
all  of the  Company's  stock  option,  employee  stock  purchase  and  dividend
reinvestment and stock purchase plans.

(5)  PREFERRED STOCK

During 2000,  the Company  issued 4,000  preferred  shares in the Indeck Capital
acquisition.  The preferred  shares issued were non-voting,  cumulative,  no par
shares with a dividend rate equal to 1 percent per annum per share,  computed on
the basis of $1,000  per share  plus an amount  equal to any  dividend  declared
payable with respect to the common stock,  multiplied by the number of shares of
common stock into which each share of preferred stock is convertible.

In the "plan of exchange" with Black Hills Corporation, the preferred stock held
by the Indeck  shareholders  was exchanged  for  preferred  stock of the holding
company and the Company converted all of its preferred stock held by the holding
company into shares of common stock.

(6)
(7) LONG-TERM DEBT
Long-term debt outstanding at December 31, is as follows (in thousands):
follows:
2002
2001
(in thousands)
First mortgage bonds:
 
 
 
 
 
 
     6.50% due 2002
 
 
$
--
 
$
15,000
 
     9.00% due 2003
 
 
 
1,113
 
 
2,176
 
     8.06% due 2010
 
 
 
30,000
 
 
30,000
 
     9.49% due 2018
 
 
 
4,550
 
 
4,840
 
     9.35% due 2021
 
 
 
31,635
 
 
33,300
 
     8.30% due 2024
 
 
 
45,000
 
 
45,000
 
     7.23% due 2032
 
 
 
75,000
 
 
--
 
 
 
 
 
187,298
 
 
130,316
 
Other long-term debt:
 
 
     Pollution control revenue bonds at 6.7% due 2010
 
 
 
12,300
 
 
12,300
 
     Pollution control revenue bonds at 7.5% due 2024
 
 
 
12,200
 
 
12,200
 
     GECC Financing at 3.41% due 2010 (a)(b)(c)
 
 
 
4,500
 
 
--
 
     Other
 
 
 
3,339
 
 
3,363
 
 
 
 
 
32,339
 
 
27,863
 
Project financing floating rate debt (b):
 
 
     Fountain Valley project at 3.3% (c) due 2006
 
 
 
138,661
 
 
144,581
 
     Hudson Falls at 3.15% (c) due 2010
 
 
 
64,278
 
 
69,479
 
     South Glens Falls at 3.15% (c) due 2009
 
 
 
21,750
 
 
24,008
 
     Valmont and Arapahoe at 3.1% (c) due 2008
 
 
 
135,000
 
 
54,948
 
 
 
 
 
359,689
 
 
293,016
 
Total long-term debt
 
 
 
579,326
 
 
451,195
 
Less current maturities
 
 
 
(22,131
)
 
(35,881
)
Net long-term debt
 
 
$
557,195
 
$
415,314
 
_________________

                                                                                     2000                      1999
                                                                                     ----                      ----

First mortgage bonds:
     6.50% due
(a)
Floating rate debt secured by a spare LM6000 turbine.

(b)
Approximately 58 percent of the December 31, 2002 $  15,000                 $ 15,000
     9.00% due 2003                                                                    3,215                    4,255
     8.06% due 2010                                                                   30,000                   30,000
     9.49% due 2018                                                                    5,130                    5,420
     9.35% due 2021                                                                   35,000                   35,000
     8.30% due 2024                                                                   45,000                   45,000
                                                                                   ---------                 --------
                                                                                     133,345                  134,675
                                                                                   ---------                 --------

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

Project financing debt:
     Floating-rate term loans atbalance has been hedged with an interest rate swap moving the floating rates to fixed rates with a weighted average interest rate of 8.05%
       at5.98 percent (see Note 3-Risk Management Activities).

(c)
Interest rates are presented as of December 31, 2000 due 2009 through 2010 (a)                                159,296                        -
                                                                                   ---------                ---------
Total long-term debt                                                                 321,052                  162,030
Less current maturities                                                              (13,960)                  (1,330)
                                                                                   ---------                ---------
Net long-term debt                                                                 $ 307,092                 $160,700
                                                                                   =========                =========
2002.


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

Substantially all of the Company'sCompany’s utility property is subject to the lien of the indenture securing its first mortgage bonds. First mortgage bonds of the Company may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.
Project financing debt is non-recourse debt collateralized by a mortgage on each respective project'sproject’s land and facilities, leases and rights, including rights to receive payments under long-term purchase power contracts.
Certain debt instruments of the Company and its subsidiaries contain restrictive covenants, all of which the Company and its subsidiaries arewere in compliance with at December 31, 2000.

2002. Some of the subsidiary debt agreements provide that approximately $23.3 million of the subsidiary’s cash balance at December 31, 2002 may not be distributed to the parent company.
Scheduled maturities for the next five years are: $14.0 million in 2001,  $30.0
million in 2002, $16.0$22.1 million in 2003, $16.4$24.2 million in 2004, and $17.6$25.6 million in 2005.

(7)2005, $138.1 million in 2006, and $125.3 million in 2007.
(8)      NOTES PAYABLE
On August 26, 2002, the Company closed a secured $50.0 million credit agreement. The credit agreement, as amended, has an expiration date of May 26, 2003 and a variable interest rate. The credit agreement is secured by the Company’s 224 megawatt plant at the Las Vegas facility and has a “backstop” guaranty provided by the Parent. The interest rate was 4.42 percent at December 31, 2002.
In addition, the Company had committed  lineshas an unsecured line of credit with various banksBlack Hills Generation, a wholly-owned indirect subsidiary of $290.0the Parent, which is due on demand; however, Black Hills Generation has agreed not to demand payment until such time as outside financing is obtained. Borrowings under the note bear interest at prime rate (4.25 percent at December 31, 2002) and interest is payable monthly. Borrowings were $454.8 million and $447.2 million at December 31, 20002002 and $115.0  million at  December  31,  1999,  which were
available to support bank borrowings or to provide for letters of credit.  There
were $211.0  million of borrowings and $20.6 million of letters of credit issued
under these lines of credit at December 31, 2000,  and there were $96.6  million
of borrowings  and no letters of credit issued at December 31, 1999. The Company
has no compensating balance requirements  associated with these lines of credit.
The lines of credit are subject to periodic  review and renewal  during the year
by the banks.

In addition  to the above  lines of credit,  Enserco  Energy,  Inc.  has a $90.0
million  uncommitted,  discretionary  line of credit to provide  support for the
purchases of natural gas. The Company and its subsidiaries  provide no guarantee
to the lender. At December 31, 2000 and 1999, there were outstanding  letters of
credit   issued  under  the  facility  of  $69.8   million  and  $19.9   million
respectively, with no borrowing balances on the facility.

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

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

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

(8)2001, respectively.
(9)     FAIR VALUE OF FINANCIAL INSTRUMENTS

Cash
The estimated fair values of the Company is invested in money  market  investments  suchCompany’s financial instruments at December 31, are as municipal
put  bonds,   money  market  preferreds,   commercial  paper,   Eurodollars  and
certificates of deposit.

follows (in thousands):
2002
2001
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Cash and cash equivalents
 
 
$
45,042
 
$
45,042
 
$
14,832
 
$
14,832
 
Restricted cash
 
 
 
1,070
 
 
1,070
 
 
--
 
 
--
 
Derivative financial
 
 
  instruments - liabilities
 
 
 
9,345
 
 
9,345
 
 
10,212
 
 
10,212
 
Notes payable
 
 
 
504,824
 
 
504,824
 
 
447,575
 
 
447,575
 
Long-term debt
 
 
 
579,326
 
 
603,000
 
 
451,195
 
 
469,009
 
The following methods and assumptions were used to estimate the fair value of each class of the Company'sCompany’s financial instruments.
Cash and Cash Equivalents and Restricted Cash
The carrying amount approximates fair value due to the short maturity of these instruments.

Available-for-sale Securities

Derivative Financial Instruments
These instruments are carried at fair value. Descriptions of the various instruments the Company uses and the valuation method employed are available in Note 3 of the Consolidated Financial Statements.
Notes Payable
The carrying amount approximates fair value due to their variable interest rates with short reset periods.
Long-Term Debt
The fair value of the Company's  investments equals the quoted market price when
available  and a quoted  market price for similar  securities if a quoted market
price  is not  available.  The  Company  has  classified  all of its  marketable
securities as available-for-sale as of December 31, 2000 and 1999. An unrealized
loss on the  Company's  investments  of $0.8 million was recorded as of December
31, 2000. At December 31, 1999 fair value approximated cost.

Long-Term Debt

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

The estimated fair values of the Company's financial instruments are as follows:

                                                           2000
                                                           ----
                                                      (in thousands)
                                          Carrying Amount           Fair Value
                                          ---------------           ----------

      Cash and cash equivalents               $ 24,913               $ 24,913
      Securities available-for-sale              2,113                  2,113
      Long-term debt                           321,052                337,446
                                                            1999
                                                            ----
                                                       (in thousands)
                                          Carrying Amount           Fair Value
                                          ---------------           ----------
      Cash and cash equivalents                $ 16,482              $ 16,482
      Securities available-for-sale               7,586                 7,586
      Long-term debt                            162,030               165,958

(9)     WYODAK PLANT

(10)     JOINTLY OWNED FACILITY
The Company owns a 20 percent interest and Pacific Power owns an 80 percent interest in the Wyodak plantPlant (Plant), a 330 megawatt coal-fired electric generating station located in Campbell County, Wyoming. Pacific Power is the operator of the Plant. The Company receives 20 percent of the Plant'sPlant’s capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 2000,2002, the Company'sCompany’s investment in the Plant included $71.8$71.5 million in electric plant and $22.4$26.5 million in accumulated depreciation.depreciation, and is included in the corresponding captions in the accompanying Consolidated Balance Sheets. The Company'sCompany’s share of direct expenses of the Plant was $5.6$5.5 million, $4.9$5.9 million and $5.8$5.6 million for the years ended December 31, 2000,  19992002, 2001 and 1998,2000, respectively, and is included in the corresponding categories of operating expenses in the accompanying consolidated statementsConsolidated Statements of income.  Wyodak Resources supplies coal toIncome.
(11)     COMMITMENTS AND CONTINGENCIES
Acquisition Earn-out Agreement
On July 7, 2000, the Plant underCompany acquired Indeck Capital, Inc. and merged it into its subsidiary, Black Hills Energy Capital, Inc. The acquisition was a stock transaction resulting in a purchase price of $37.8 million. Additional consideration may be paid in the form of an agreement expiringearn-out over a four-year period beginning in 2013 with a Pacific  Power option to renew the agreement for an additional 10
years.  This coal  supply  agreement  is  collateralized  by a mortgage on and a
security  interest in some2000. As of Wyodak  Resources' coal reserves.  At December 31, 2000,  approximately  17,966,000 tons of coal were covered2001, $3.6 million has been paid under this agreement.
Wyodak Resources' sales to the Plant were $23.2 million, $24.9 million and $23.2
million, for the years endedearn-out. On December 31, 2000, 19992002, additional consideration of $3.8 million was earned and 1998, respectively.

(10)    COMMITMENTS AND CONTINGENCIESpayable. Additional consideration paid out under the earn-out is recorded as an increase to goodwill. The earn-out consideration is based on the acquired company’s earnings during such period and cannot exceed $35.0 million in total.
Power Agreement – Pacific Power's Power Sales Agreement

In 1983, the Company entered into a 40 year power agreement with Pacific PowerPacifiCorp providing for the purchase by the Company of 75 megawatts of electric capacity and energy from Pacific Power'sPacifiCorp’s system. An amended agreement signed in October 1997 reduces the contract capacity by 25 megawatts (5 megawatts per year starting in 2000). The price paid for the capacity and energy is based on the operating costs of one of Pacific Power'sPacifiCorp’s coal-fired electric generating plants. Costs incurred under this agreement were $10.9 million in 2002, (net of a $1.3 million refund for prior years) $13.9 million in 2001 and $14.6 million $17.8 million and $17.5
million in 2000, 1999 and 1998, respectively.



Reclamation

Under2000.
Long Term Power Sales Agreements
The Company, through its mining permit,  Wyodak Resources is required to reclaim all land where
itsubsidiaries, has mined coal  reserves.  the following significant long-term power sales contracts:
The costCompany has long-term power sales contracts with the Public Service Company of reclaimingColorado (PSCC) for the land is accrued as the
coal is mined.  While the reclamation  process takes place on a continual basis,
muchoutput of several of its plants. All of the reclamation  occursoutput of the Company’s Fountain Valley, Arapahoe and Valmont gas-fired facilities, totaling 450 megawatts is included under the contracts which expire in 2012. The contracts are treated as leases under generally accepted accounting principles and establish capacity and availability payments over an extendedthe lives of the contracts. The contracts are tolling arrangements in which the Company assumes no fuel price risk.

The Company has secured long-term contracts for the output of the 277 megawatt Las Vegas facility. The 53 megawatt Las Vegas I power plant is contracted with Nevada Power through 2024. The 224 megawatt Las Vegas II power plant was completed at year end and is under a tolling arrangement with Allegheny Energy Supply that expires in 2017.

Various long-term contracts with Niagara Mohawk Power Corporation have been entered into to sell the output of several of the Company’s hydroelectric projects located in upstate New York. The Company’s net ownership of capacity under contract is approximately 21 megawatts with contracts expiring between 2029 and 2035. There are additional contracts on plants with a net ownership capacity of approximately 21 megawatts that expire during 2003.

The Company has entered into a 5 year tolling agreement with Southern California Edison for 100 megawatts of capacity and power from the Company’s gas-fired Harbor Cogeneration plant. The agreement is seasonal and runs from June through October of each year. The agreement expires in 2007.
The Company has a ten year power sales contract with the Municipal Energy Agency of Nebraska for 20 megawatts of contingent capacity from the Neil Simpson Unit #2 plant.

Ongoing Litigation
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 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. The Company’s 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. The Company has denied all claims and will vigorously defend this matter, the timing or outcome of which is uncertain.
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 afterof time. On July 16, 2002, the areaState 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 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 mined.
Approximately  $0.7  millionasserted with respect to the claim for injury to timber. The total amount of alleged damages is charged to  operations  as  reclamation  expense
annually.  Asnot specified.
On March 3, 2003 the United States of December 31, 2000, accrued reclamation costs were approximately
$17.7 million.

Legal Proceedings

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

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

Managementfor 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.
The Company is completing its own investigation of the opinionfire cause and origin and has requested access to the materials that Wyodak has properly  billed  PacifiCorp  underform the termsbasis for the assertions of state and federal fire investigators. The Company’s investigation is not complete, but based on information currently available, the Coal  Supply  AgreementCompany expects to deny all claims and Coal  Handling  Agreementvigorously defend any and PacifiCorp's  withholdingall claims brought by governmental or private parties.
Although we cannot predict the outcome of payment  constitutes a breachour investigation or the viability of contractpotential claims based on their
part.  Although  it  is  impossible  to  predict  whether  or  not  Black  Hills
Corporation  and Wyodak will ultimately be successful in defending the claim or,
if not, what the impact might be,information currently available, management believes that the  disposition of
this  matterany such claims, if determined adversely to us, will not have a material adverse effect on the  Company's
consolidatedour financial condition or results of operations.
Federal Energy Regulatory Commission (FERC) Investigation
In August 2001, the Company 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 Public Utility Regulatory Policies Act of 1978 (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 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, the Company, as a partner in the entity that now owns that facility, could be liable for any refunds, fines or other penalties FERC imposes. The Company could also be subject to variousadditional liabilities resulting from third party claims. The Company has 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 the Company’s ability to enforce a claim for indemnification. Because FERC has only recently begun its investigation, the Company cannot predict the outcome of FERC’s investigation. However, based upon information currently available, management does not believe that any refunds, fines or penalties resulting from the investigation will have a material affect on the Company’s financial condition or results of operations.
Other Proceedings
In addition to the above proceedings, the Company and its subsidiaries are involved in numerous legal proceedings, claims and claims
which ariselitigation in the ordinary course of operations.business. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the consolidated financial position or results of operations of the Company.

(11)
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.
(12)     EMPLOYEE BENEFIT PLANS
Defined Benefit Pension and Other Postretirement Plans

Plan
The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of Black Hills Power,  Wyodak Resources  Development  Corp., Black
Hills  Exploration  and  Production  and  Daksoft who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. The Company'sCompany’s funding policy is in accordance with the federal government'sgovernment’s funding requirements. The Plan'sPlan’s assets are held in trust and consist primarily of equity securities and cash equivalents.
Net pension income for the Plan was as follows:
2002
2001
2000
(in thousands)
Service cost
 
 
$
588
 
$
719
 
$
744
 
Interest cost
 
 
 
2,406
 
 
2,565
 
 
2,401
 
Expected return on assets
 
 
 
(3,345
)
 
(4,928
)
 
(4,465
)
Amortization of transition amount
 
 
 
--
 
 
--
 
 
(63
)
Amortization of prior service cost
 
 
 
184
 
 
199
 
 
199
 
Recognized net actuarial loss (gain)
 
 
 
96
 
 
(453
)
 
(452
)
Net pension income
 
 
$
(71
)
$
(1,898
)
$
(1,636
)
Actuarial assumptions:
 
 
   Used for net periodic pension cost
 
 
 
7.5
%
 
7.5
%
 
7.5
%
   Used to value pension (liability)/asset at
 
 
     year-end
 
 
 
6.75
*
 
7.5
%
 
7.5
%
   Expected long-term rate of return on assets
 
 
 
10.5
%**
 
10.5
%
 
10.5
%
   Rate of increase in compensation levels
 
 
 
5.0
%***
 
5.0
%***
 
5.0
%
_________________

                                                                   2000                    1999                    1998
                                                                   ----                    ----                    ----
                                                                                     (in thousands)


Service
*The discount rate used for net periodic pension cost $    967              $   1,174                $    895
Interest cost                                                       2,885                  2,598                   2,406
Estimated return on assets                                         (5,257)                (4,162)                 (4,146)
Amortizationwas changed from 7.50 percent in 2002 to 6.75 percent for the calculation of transition amount                                     (90)                   (90)                    (90)
Amortization of prior service cost                                    231                     89                      89
Recognized net actuarial gain                                        (537)                     -                    (272)
                                                                 --------              ---------                --------the 2003 Net Periodic Pension cost. This change is expected to increase pension income                                               $ (1,801)             $    (391)                $(1,118)
                                                                 ========              =========                ========

Actuarial assumptions:
   Discount rate                                                     7.5%                  6.75%                    7.5%
   Expected long-termcosts by approximately $0.3 million.

**The expected rate of return on plan assets 10.5%                 10.5%                    10.5%
   Ratewas changed from 10.5 percent to 10 percent for the calculation of the 2003 Net Periodic Pension Cost. This change is expected to increase pension costs in 2003 by approximately $0.1 million.

***The rate of increase in compensation levels 5.0%                  5.0%                     5.0%

changed in 2001 from a single rate assumption for all ages to an age- based salary scale assumption resulting in a weighted average increase of 5.0 percent.

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


                                                                        2000                        1999
                                                                        ----                        ----
                                                                                  (in thousands)
              
              Beginning projected benefit obligation                   $39,615                    $39,490
                                                                       -------                    -------
              Service cost                                                 967                      1,174
              Interest cost                                              2,885                      2,598
              Actuarial losses                                             (48)                    (3,590)
              Benefits paid                                             (2,105)                    (1,903)
              Plan amendments                                                -                      1,846
                                                                       -------                    -------
              Net increase                                               1,699                        125
                                                                       -------                    -------
              Ending projected benefit obligation                      $41,314                    $39,615
                                                                       =======                    =======
follows (in thousands):
2002
 
2001
 
Beginning projected benefit obligation
 
 
$
33,151
 
$
34,454
 
Service cost
 
 
 
588
 
 
719
 
Interest cost
 
 
 
2,406
 
 
2,565
 
Actuarial losses
 
 
 
571
 
 
183
 
Discount rate change
 
 
 
3,380
 
 
--
 
Benefits paid
 
 
 
(1,955
)
 
(1,933
)
Business divestiture
 
 
 
--
 
 
(2,837
)
Net increase (decrease)
 
 
 
4,990
 
 
(1,303
)
Ending projected benefit obligation
 
 
$
38,141
 
$
33,151
 
A reconciliation of the fair value of planPlan assets as of October 1 of each year is as follows:


                                                                        2000                        1999
                                                                        ----                        ----
                                                                                  (in thousands)
              
              Beginning market value of plan assets                    $51,212                    $40,638
              Benefits paid                                             (2,105)                    (1,903)
              Investment income                                          7,453                     12,477
                                                                     ---------                   --------
              Ending market value of plan assets                       $56,560                    $51,212
                                                                       =======                    =======
follows (in thousands):
2002
 
2001
 
Beginning market value of plan assets
 
 
$
32,938
 
$
47,993
 
Benefits paid
 
 
 
(1,955
)
 
(1,933
)
Investment loss
 
 
 
(5,153
)
 
(11,133
)
Asset transfer
 
 
 
--
 
 
(1,989
)
Ending market value of plan assets
 
 
$
25,830
 
$
32,938
 
Funding information for the Plan as of October 1 each year was as follows:


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

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

              Accumulated benefit obligation                           $33,374                    $31,914
                                                                       =======                    =======
follows (in thousands):
2002
 
2001
 
Fair value of plan assets
 
 
$
25,830
 
$
32,938
 
Projected benefit obligation
 
 
 
(38,141
)
 
(33,151
)
Funded status
 
 
 
(12,311
)
 
(213
)
Unrecognized:
 
 
   Net loss
 
 
 
17,075
 
 
4,721
 
   Prior service cost
 
 
 
1,253
 
 
1,437
 
Net amount recognized
 
 
$
6,017
 
$
5,945
 
Amounts recognized in statement of
 
 
  financial position consist of:
 
 
   Accrued pension (liability) asset
 
 
$
(6,370
)
$
5,945
 
   Intangible asset
 
 
 
1,326
 
 
--
 
   Accumulated other comprehensive
 
 
     loss
 
 
 
11,061
 
 
--
 
Net amount recognized
 
 
$
6,017
 
$
5,945
 
 Accumulated benefit obligation
 
 
$
32,254
 
$
28,505
 
The provisions of Statement of Financial Accounting Standards No. 87 "Employers' Accounting for Pensions" (SFAS 87) requires the Company to record an accrued pension liability of $6.4 million at December 31, 2002, and is included in Accrued liabilities on the accompanying Consolidated Balance Sheet. This liability represents the amount by which the accumulated benefit obligation exceeds the sum of the fair market value of plan assets and accrued amounts previously recorded. The additional liability may be offset by an intangible asset to the extent of previously unrecognized prior service cost, therefore an intangible asset of $1.3 million at December 31, 2002 is included in the line item Other in Other Assets on the accompanying Consolidated Balance Sheet. The remaining amount of $11.1 million is recorded as a component of stockholder's equity, net of related tax benefits of $4.0 million, in the line item Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheet at December 31, 2002.
Supplemental Nonqualified Defined Benefit Retirement Plan
The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. Expenses recognized under the plans were $0.5$0.2 million $0.4 millionin 2002 and $0.4 million in 2001 and 2000, 1999respectively.
The following table summarizes the projected benefit obligation and 1998, respectively.

accumulated benefit obligation of the unfunded plan at December 31, 2002 (in thousands):
2002
 
2001
 
Accumulated benefit obligation
 
 
$
1,445
 
$
806
 
Projected benefit obligation
 
 
$
1,676
 
$
1,282
 
The provisions of SFAS 87 required the Company to record an additional minimum liability of $0.4 million at December 31, 2002. This amount is included in Accrued liabilities on the accompanying Consolidated Balance Sheet. This liability represents the amount by which the accumulated benefit obligation exceeds the sum of the fair market value of plan assets and accrued amounts previously recorded. The amount of $0.4 million is recorded as a component of stockholder’s equity, net of related tax benefits of $0.1 million, in the line item Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheet at December 31, 2002.
Non-pension Defined Benefit Postretirement Plan
Employees who are participants in the Plan and who retire from the Company on or after attaining age 55 after completing at least five years of service to the Company are entitled to postretirement healthcare benefits  coverage.benefits. These benefits are subject to premiums, deductibles, copaymentco-payment provisions and other limitations. The Company may amend or change the planPlan periodically. The Company is not pre-funding its retiree medical plan.
The net periodic postretirement cost was as follows:

                                                             2000                       1999                      1998
                                                             ----                       ----                      ----
                                                                                   (in thousands)

Service cost                                                   $282                      $225                      $135
Interest cost                                                   523                       362                       290
Amortization of transition obligation                           150                       150                       150
(Gain)/loss                                                      68                         1                       (42)
                                                             ------                      ----                      ----
                                                             $1,023                      $738                      $533
                                                             ======                      ====                      ====
follows (in thousands):
2002
 
2001
 
2000
 
Service cost
 
 
$
160
 
$
208
 
$
204
 
Interest cost
 
 
 
402
 
 
414
 
 
427
 
Amortization of transition obligation
 
 
 
117
 
 
124
 
 
124
 
Amortization of prior service cost
 
 
 
(19
)
 
--
 
 
--
 
Loss
 
 
 
34
 
 
22
 
 
64
 
 
 
 
$
694
 
$
768
 
$
819
 
Funding information as of October 1 was as follows:

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

Accumulated postretirement benefit obligation:
     Retirees                                                                    $2,478                          $2,608
     Fully eligible active participants                                           1,203                           1,195
     Other active participants                                                    3,172                           3,278
                                                                                -------                         -------
Unfunded accumulated postretirement benefit obligation                            6,853                           7,081
Unrecognized net loss                                                            (1,001)                         (1,667)
Unrecognized transition obligation                                               (1,797)                         (1,947)
                                                                                -------                         -------
Accrued postretirement cost                                                      $4,055                          $3,467
                                                                                 ======                          ======
follows (in thousands):
2002
 
2001
 
Accumulated postretirement benefit obligation:
 
 
 
 
 
 
     Retirees
 
 
$
2,937
 
$
2,761
 
     Fully eligible active participants
 
 
 
1,472
 
 
1,585
 
     Other active participants
 
 
 
2,138
 
 
2,929
 
Unfunded accumulated postretirement benefit obligation
 
 
 
6,547
 
 
7,275
 
Unrecognized net loss
 
 
 
(1,830
)
 
(2,481
)
Unrecognized prior service cost
 
 
 
265
 
 
--
 
Unrecognized transition obligation
 
 
 
(1,167
)
 
(1,365
)
Contributions
 
 
 
(51
)
 
--
 
Accrued postretirement cost
 
 
$
3,764
 
$
3,429
 
For measurement purposes, an 8.5a 12.0 percent annual rate of increase in healthcare benefits was assumed for 2000;2002; the rate was assumed to decrease gradually to 65 percent in 20052009 and remain at that level thereafter. The healthcare cost trend rate assumption has a significant effect on the amounts reported. A one percent increase in the healthcare cost trend assumption would increase the service and interest cost $0.2$0.1 million or 21.819.5 percent and the net periodic postretirement cost $0.2$1.1 million or 24.117.0 percent. A one percent decrease would reduce the service and interest cost by $0.1 million or 16.916.0 percent and decrease the net periodic postretirement cost $0.2$0.9 million or 18.613.6 percent. The weighted-average discount rate used in determining the accumulated postretirement benefit obligation was 6.75 percent for 2002 and 7.5 percent.

percent for 2001.
Defined Contribution Plan
The Company also sponsors a 401(k) savings plan for eligible employees. Participants elect to invest up to 20 percent of their eligible compensation on a pre-tax basis. Effective January 1, 2000 (May 1, 2000 for employees covered by the collective bargaining agreement), the Company provides a matching contribution of 100 percent of the employee'semployee’s tax-deferred contribution up to a maximum 3 percent of the employee'semployee’s eligible compensation. Matching contributions vest at 20 percent per year and are fully vested when the participant has 5 years of service with the Company. The Company'sCompany’s matching contributions totaled $0.4 million for 2002, $0.6 million for 2001 and $0.3 million for 2000.

(12)
(13)     OTHER COMPREHENSIVE LOSS
The following tables display the related tax effects allocated to each component of Other Comprehensive Loss for the years ended December 31, (in thousands):
2002
Pre-tax
Amount
Tax Benefit
Net-of-tax
Amount
Net change in fair value of derivatives designated as cash flow
 
 
 
 
 
 
 
 
   hedges (net of minority interest share of $(164))
 
 
$
(9,762
)
$
3,669
 
$
(6,093
)
Minimum pension liability adjustment
 
 
 
(11,443
)
 
4,005
 
 
(7,438
)
Other comprehensive loss
 
 
$
(21,205
)
$
7,674
 
$
(13,531
)

2001
Pre-tax
Amount
Tax Benefit
Net-of-tax
Amount
Net change in fair value of derivatives designated as cash flow
 
 
 
 
 
 
 
 
   hedges (net of minority interest share of $2,875)
 
 
$
(7,540
)
$
3,016
 
$
(4,524
)
Items of other comprehensive income (loss) were not significant in 2000.
(14)     INCOME TAXES
Income tax expense (benefit) for the years indicated was:

                                                                           2000                 1999                  1998
                                                                           ----                 ----                  ----
                                                                                           (in thousands)
         
         Current                                                         $28,421               $13,498              $14,243
         Deferred                                                          2,576                 2,931               (1,886)
         Tax credits, net                                                   (639)                 (640)                (649)
                                                                         -------               -------              -------
                                                                         $30,358               $15,789              $11,708
                                                                         =======               =======              =======
ended December 31 was (in thousands):
2002
 
2001
 
2000
 
Current
 
 
$
(1,318
)
$
19,495
 
$
21,290
 
Deferred
 
 
 
22,993
 
 
4,522
 
 
1,293
 
 
 
 
$
21,675
 
$
24,017
 
$
22,583
 
The temporary differences which gave rise to the net deferred tax liability atwere as follows (in thousands):
Years ended December 31,
2002
 
2001
 
Deferred tax assets, current:
 
 
 
 
 
 
   Valuation reserve
 
 
$
311
 
$
2,789
 
   Employee benefits
 
 
 
2,259
 
 
3,103
 
   Items of other comprehensive income
 
 
 
7,203
 
 
--
 
   Other
 
 
 
972
 
 
946
 
 
 
 
 
10,745
 
 
6,838
 
Deferred tax liabilities, current:
 
 
   Employee benefits
 
 
 
2,106
 
 
2,041
 
   State income tax
 
 
 
5,609
 
 
--
 
   Items of other comprehensive income
 
 
 
--
 
 
911
 
   Other
 
 
 
321
 
 
31
 
 
 
 
 
8,036
 
 
2,983
 
Net deferred tax asset, current
 
 
$
2,709
 
$
3,855
 
Deferred tax assets, non-current:
 
 
   Accelerated depreciation and other plant related differences
 
 
 
6,760
 
 
--
 
   Regulatory asset
 
 
 
1,294
 
 
1,451
 
   ITC
 
 
 
571
 
 
717
 
   Items of other comprehensive income
 
 
 
3,488
 
 
3,927
 
   Net operating loss carryforward
 
 
 
1,490
 
 
2,198
 
   Other
 
 
 
4,286
 
 
1,904
 
 
 
 
 
17,889
 
 
10,197
 
Deferred tax liabilities, non-current:
 
 
   Accelerated depreciation and other plant related differences
 
 
 
103,690
 
 
64,656
 
   AFUDC
 
 
 
2,828
 
 
2,646
 
   Regulatory liability
 
 
 
1,523
 
 
1,425
 
   Other
 
 
 
10,894
 
 
6,564
 
 
 
 
 
118,935
 
 
75,291
 
     Net deferred tax liability, non-current
 
 
 
101,046
 
 
65,094
 
                  Net deferred tax liability
 
 
$
98,337
 
$
61,239
 
The following table reconciles the change in the net deferred income tax liability from December 31, 2000 and 1999 were as follows:

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


                                                                                                                  Net Deferred
                                                                                                                     Income
                                                                                                                   Tax Asset
         December 31, 1999                                                Assets             Liabilities          (Liability)
                                                                          ------             -----------          -----------
                                                                                           (in thousands)
         
         Accelerated depreciation and other plant-related
           differences                                                    $     -              $48,223             $(48,223)
         Regulatory asset                                                   1,792                    -                1,792
         Regulatory liability                                                   -                1,380               (1,380)
         Unamortized investment tax credits                                 1,058                    -                1,058
         Mining development and oil exploration                             3,605                6,893               (3,288)
         Employee benefits                                                  2,833                  695                2,138
         Other                                                              2,184                1,949                  235
                                                                          -------              -------             --------
                                                                          $11,472              $59,140             $(47,668)
                                                                          =======              =======             ========
2001, to December 31, 2002, to deferred income tax expense:
2002
 
(in thousands)
 

Net change in deferred income tax liability from the preceding table
 
 
$
37,098
 
Deferred taxes associated with 2001 Federal Income Tax Return True-up related to accelerated
 
 
  depreciation and other plant-related differences
 
 
 
(21,542
)
Deferred taxes associated with other comprehensive loss
 
 
 
7,675
 
Other
 
 
 
(238
)
Deferred income tax expense for the period
 
 
$
22,993
 
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:


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


(13)
2002
 
2001
 
2000
 
Federal statutory rate
 
 
 
35.0
%
 
35.0
%
 
35.0
%
Amortization of excess deferred and investment tax credits
 
 
 
(1.0
)
 
(1.0
)
 
(1.0
)
Research and development credit
 
 
 
(1.8
)
 
--
 
 
--
 
Other
 
 
 
2.8
 
 
1.7
 
 
1.9
 
 
 
 
 
35.0
%
 
35.7
%
 
35.9
%
At December 31, 2002, the Company had net operating loss carryforwards of $2.8 million which expire in the year 2020 and $1.1 million which expire in the year 2022.
(15) BUSINESS SEGMENTS
The Company'sCompany’s reportable segments are those that are based on the Company'sCompany’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of December 31, 2000,2002, substantially all of the Company'sCompany’s operations and assets are located within the United States. The Company'sCompany’s operations are conducted through sixtwo business segments that  include:groups: Electric, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; Independent  Energy consisting of: Mining,  which engages in the mining and sale
of coal from its mine  near  Gillette,  Wyoming;  Oil and Gas,  which  produces,
explores  and  operates  oil and gas  interests  located  in the Rocky  Mountain
region,  Texas,  California  and other  states;  Fuel  Marketing,  which markets
natural  gas,  oil,  coal and related  services to  customers in the East Coast,
Midwest,  Southwest,  Rocky Mountain,  West Coast and Northwest regions markets; Independent Power, which produces and sells power and capacity to wholesale customers;customers.
December 31:
2002
 
2001
 
(in thousands)
Total assets
 
 
 
 
 
 
Electric utility
 
 
$
502,157
 
$
432,966
 
Independent power
 
 
 
1,008,901
 
 
840,463
 
Total assets
 
 
$
1,511,058
 
$
1,273,429
 
Capital expenditures
 
 
Electric utility
 
 
$
31,251
 
$
41,313
 
Independent power
 
 
 
174,792
 
 
491,173
 
Total capital expenditures
 
 
$
206,043
 
$
532,486
 
2002
 
2001
 
2000
 
(in thousands)
Operating revenues
 
 
 
 
 
 
 
 
Electric utility
 
 
$
162,186
 
$
213,210
 
$
173,308
 
Independent power
 
 
 
125,267
 
 
73,750
 
 
19,925
 
Total operating revenues
 
 
$
287,453
 
$
286,960
 
$
193,233
 
Depreciation and amortization
 
 
Electric utility
 
 
$
17,499
 
$
15,773
 
$
14,966
 
Independent power
 
 
 
26,434
 
 
15,930
 
 
3,646
 
Total depreciation and amortization
 
 
$
43,933
 
$
31,703
 
$
18,612
 
Operating income
 
 
Electric utility
 
 
$
58,160
 
$
84,108
 
$
68,208
 
Independent power
 
 
 
51,978
 
 
25,831
 
 
20,367
 
Total operating income
 
 
$
110,138
 
$
109,939
 
$
88,575
 
Interest expense
 
 
Electric utility
 
 
$
13,663
 
$
15,780
 
$
17,411
 
Independent power
 
 
 
34,202
 
 
28,804
 
 
7,918
 
Total interest expense
 
 
$
47,865
 
$
44,584
 
$
25,329
 
Interest income
 
 
Electric utility
 
 
$
734
 
$
4,858
 
$
5,658
 
Independent power
 
 
 
91
 
 
381
 
 
100
 
Total interest income
 
 
$
825
 
$
5,239
 
$
5,758
 
  Income taxes
 
 
Electric utility
 
 
$
15,067
 
$
24,255
 
$
19,469
 
Independent power
 
 
 
6,608
 
 
(238
)
 
3,114
 
Total income taxes
 
 
$
21,675
 
$
24,017
 
$
22,583
 
Income (loss) from continuing operations
 
 
Electric utility
 
 
$
30,217
 
$
45,238
 
$
37,105
 
Independent power
 
 
 
10,066
 
 
(1,964
)
 
3,173
 
Total income from continuing operations
 
 
$
40,283
 
$
43,274
 
$
40,278
 
(16)      ACQUISITIONS
On March 15, 2002, BHEC paid $25.7 million to acquire an additional 30 percent interest in the Harbor Cogeneration Facility (Harbor), a 98 megawatt gas-fired plant located in Wilmington, California. In addition, during the fourth quarter of 2002, the Company paid $13.8 million to acquire the remaining ownership interest in Harbor and Communicationsthe Pepperell Facility (Pepperell), a 40 megawatt gas-fired plant located in Pepperell, Massachusetts. These transactions give the Company a 100 percent ownership interest in Harbor and Others,  which primarily markets  communicationsPepperell and software
development services.

Segment  information followswere funded by borrowings from affiliates.
The Company’s investment in the sameabove entity prior to the above acquisition was accounted for under the equity method of accounting policies as describedand was included in Note 1
- - BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT  ACCOUNTING POLICIES.  Segment
information  included  inInvestments on the accompanying Consolidated Balance Sheets  and
Consolidated Statements of Income is as follows (in thousands):




ASSETS                                              Independent Energy
                                     --------------------------------------------------
                                                 Oil and       Fuel       Independent    Communications
                          Electric     Mining       Gas       Marketing       Power          & Others      Eliminations    Total
                       ------------- ---------- ----------- ------------ -------------- ----------------- ------------- ------------

At December 31, 2000
Current assets          $ 133,542   $167,820     $ 3,452    $ 330,352     $   25,645    $     13,213       $  (255,016)  $   419,008
Total assets              627,930    251,136      36,396      346,333        375,811         132,722          (440,943)    1,329,385

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

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


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

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

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


                                                    Independent Energy
                                      --------------------------------------------------
Year ended                                        Oil and       Fuel       Independent    Communications
December 31, 1999         Electric     Mining       Gas      Marketing        Power          & Others      Eliminations     Total
                        ------------- ---------- ----------- ------------ -------------- ----------------- ------------- ----------

Electric revenues        $ 133,222    $     -     $      -   $         -       $      -      $     -           $     -    $ 133,222
Coal revenues                    -     31,095            -        39,212              -            -                 -       70,307
Gas revenues                     -          -        5,399       382,809              -            -                 -      388,208
Oil revenues                     -          -        4,676       192,207              -            -                 -      196,883
Other operating
 Revenues                        -          -        2,977             -              -        3,423            (3,145)       3,255
                        ------------- ---------- ----------- ------------ -------------- ----------------- ------------- -----------
Total operating
 Revenues               $ 133,222     $ 31,095   $  13,052   $   614,228       $      -      $ 3,423           $(3,145)   $ 791,875
                        ------------- ---------- ----------- ------------ -------------- ----------------- ------------- -----------

Depreciation, depletion
 and amortization       $  15,552     $ 3,259    $   2,953   $     2,757       $      -      $   546           $     -    $  25,067
Operating income (loss)    52,286      12,606        3,978        (2,248)          (157)      (4,574)                -       61,891
Interest expense           13,830       1,260          568           719            111        1,172            (2,200)      15,460
Income taxes (benefit)     12,446       3,439          968            50            (58)      (1,056)                -       15,789
Net income (loss)
available for common       27,362       9,715        2,462          (185)          (109)      (1,263)             (915)      37,067
Property additions,
investments and
acquisition of net assets  31,911       5,422        9,968         5,947         52,319       49,042                 -      154,609

                                                        Independent Energy
                                     ---------------------------------------------------
Year ended                                      Oil and       Fuel       Independent    Communications
December 31, 1998       Electric     Mining        Gas       Marketing       Power          & Others      Eliminations      Total
                       ------------- ---------- ------------ ------------ -------------- ----------------- ------------- ----------

Electric revenues        $ 129,236    $     -    $      -     $       -     $        -      $     -         $       -     $ 129,236
Coal revenues                    -     31,413           -        12,924              -            -                 -        44,337
Gas revenues                     -          -       4,073       375,136              -            -                 -       379,209
Oil revenues                     -          -       5,131       117,185              -            -                 -       122,316
Other operating
 Revenues                        -          -       3,358           798              -        2,437            (2,437)        4,156
                       ------------- ---------- ------------ ------------ -------------- ----------------- ------------- ----------
Total operating
 Revenues                $ 129,236   $ 31,413    $ 12,562     $ 506,043     $        -      $ 2,437         $  (2,437)    $ 679,254
                        ------------ ---------- ------------ ------------ -------------- ----------------- ------------- ----------

Depreciation, depletion
 and amortization
                        $  14,881    $ 3,252     $ 18,760**   $     690     $        -      $    -          $      -      $  37,583
Operating income
 (loss)                    49,896     12,723      (12,340)**         41              -      (1,087)                -         49,233
Interest income            13,572         10          355           731              -          39                 -         14,707
Income taxes (benefit)     12,612      4,126       (4,689)**       (116)           (64)       (161)                -         11,708
Net income (loss)
available for common       24,825      9,750       (7,976)**       (346)          (118)       (226)             (101)        25,808
Property additions,
investments and
acquisition of net
assets                     11,451      1,406       10,169         2,384              -       1,815                 -         27,225
**Includes the impact of a $13.5 million pre-tax write-down of certain oil and natural gas properties.


(14)      ACQUISITIONS

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

Thevoting control, therefore, after acquisition  was a stock  transaction  with the Company issuing  1,536,747
shares of common stock tohas consolidated the shareholders of Indeck priced at $21.98 per share
(approximately 7 percent of the Company's  common stock after the  transaction),
along with $4





millionentity in preferred stock, resulting in a purchase price of approximately $37.8
million. Additional consideration, consisting of common and preferred stock, may
be paid  in the  form of an  earn-out  over a  four-year  period.  its consolidated financial statements.
The earn-out
consideration  will be based on the  acquired  company's  earnings  during  such
period and cannot exceed $35.0 million in total.  Additional  consideration paid
out under the earn-out will be recorded as an increase to goodwill.

Theabove acquisition has been accounted for under the purchase method of accounting and, accordingly, the purchase price has been allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and the liabilities assumed as of the date of acquisition. The estimated purchase price allocations are subject to adjustment, generally within one year of the date of acquisition. The purchase price and related acquisition cost exceeded the fair value assigned to net intangible assets by approximately $9.3 million, and was recorded as long-lived intangible assets.
The impact of these acquisitions was not material in relation to the Company’s results of operations. Consequently, pro forma information is not presented.
On August 31, 2001, BHEC purchased a 277 megawatt gas-fired co-generation power plant project located in North Las Vegas, Nevada from Enron North America, a wholly owned subsidiary of Enron Corporation. At acquisition, the facility had a 53 megawatt co-generation power plant in operation, of which the Company owns 50 percent. Most of the power from that facility is under a long-term contract expiring in 2024. Although the Company only owns 50 percent of this plant, under generally accepted accounting principles the Company is required to consolidate 100 percent of this plant. The project also has a 224 megawatt combined-cycle expansion under construction of which the Company owns 100 percent. The facility became fully operational in January 2003 and utilizes LM-6000 technology. The power to be generated by the expansion project is also under a long-term sales contract that expires in 2017. This contract for the expansion requires the purchaser to provide fuel to the power plant when it is dispatched. Total cost for the entire facility is expected to be approximately $325 million of which $314 million was expended as of December 31, 2002.
The acquisition has been accounted for under the purchase method of accounting and, accordingly, the purchase price of approximately $205 million has been allocated to the acquired assets and liabilities based on preliminary estimates of the fair values of the assets purchased and the liabilities assumed as of the date of acquisition. Fair values in the allocation include assets acquired of approximately $151.1$150 million (excluding goodwill)goodwill and other intangibles) and liabilities assumed of approximately $138.7$2 million. As of
December 31, 2000, theThe purchase price and related acquisition costs exceeded the fair values assigned to net tangible assets by approximately $25.4$42 million, which was recorded as goodwilllong-lived intangible assets and is  being  amortized  over 25 years ongoodwill.
On April 11, 2001, BHEC purchased the Fountain Valley facility, a straight-line basis.

Prior to the closing240 megawatt generation facility located near Colorado Springs, Colorado, featuring six LM-6000 simple-cycle, gas-fired turbines. The facility came on-line mid third quarter of 2001. The facility was purchased from Enron Corporation. Total cost of the Indeck  Capital  transaction,  thereproject was no material
relationship  between its shareholdersapproximately $183 million and has been financed primarily with non-recourse project debt. The Company has obtained an 11-year contract with Public Service Company of Colorado to utilize the facility for peaking purposes. The contract is a tolling arrangement in which the Company or any ofassumes no fuel price risk. The transaction has been accounted for as an asset purchase recorded at cost.
In addition, during 2001, BHEC acquired an additional 31 percent interest and a 13 percent interest in its affiliates,
any director or officer of the Company or any of their  associates,  except that
the Company  through itsconsolidated majority-owned subsidiaries, and Indeck  Capital  jointly owned Black Hills  Colorado,  LLC and both parties held  interests in Indeck North American Power Partners,Fund, L.P. and Indeck North American Power Fund,  L.P. Black Hills
Colorado owns 111 megawatts of combustion turbine  generating  facilities in the
Front Range of Colorado.

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

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

o    Acquired a 39.6  percentrespectively, from minority shareholders. Total consideration paid was $15.9 million.
Pro forma financial interest in each of Northern  Electric
     Power  Company,   L.P.  and  South  Glens  Falls  Limited  Partnership  for
     approximately $4.2 million in cash.

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

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

                                            2000                 1999
                                            ----                 ----
                                            (Unaudited, in thousands)

Revenues                                 $1,668,851             $840,891
Operating income                           $139,053              $73,900
Net income available for common stock       $57,542              $34,310

(15)       OIL AND GAS RESERVES  (Unaudited)

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

The  following  table  summarizes  Black  Hills   Exploration  and  Production's
quantities  of proved  developed and  undeveloped  oil and natural gas reserves,
estimated using constant  year-end product prices, as of December 31, 2000, 1999
and 1998,  and a  reconciliation  of the  changes  between  these  dates.  These
estimates are based on reserve reports by Ralph E. Davis Associates,





Inc., an independent  engineering company selected by the Company.  Such reserve
estimates are based upon a number of variable factors and assumptions  which may
cause these estimates to differ from actual results.


                                                          2000                          1999                        1998
                                                          ----                          ----                        ----
                                                      Oil           Gas            Oil            Gas           Oil           Gas
                                                      ---           ---            ---            ---           ---           ---
                                                                 (in thousands of barrels of oil and MMcf of gas)

Proved developed and undeveloped reserves:
   Balance at beginning of year                      4,109        19,460          2,368        15,952           2,495        9,052
     Production                                       (352)       (3,285)          (309)       (2,801)           (353)      (2,068)
     Additions                                         625         4,228            376         7,718           1,149       10,721
     Property sales                                      -             -           (164)          (66)              -            -
     Revisions to previous estimates                    31        (1,999)         1,838        (1,343)           (923)      (1,753)
                                                   -------       -------        -------      --------         -------     --------

   Balance at end of year                            4,413        18,404          4,109        19,460           2,368       15,952
                                                   =======       =======        =======       =======         =======      =======

Proved developed reserves at end of
   year included above                               3,047        16,418          2,819        14,391           1,463       10,041
                                                   =======       =======        =======       =======         =======      =======

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


In December 1998,  Black Hills  Exploration  and  Production  recognized a $13.5
million  pre-tax  loss related to a write-down  of oil and gas  properties.  The
write-down was primarily due to historically low crude oil prices, lower natural
gas prices and decline in value of certain unevaluated properties.

(16)operations.
(17)     QUARTERLY HISTORICAL DATA (Unaudited)
The Company operates on a calendar year basis. The following table sets forth selected unaudited historical operating results and market data for each quarter of 20002002 and 1999.

                                                     First             Second             Third              Fourth
                                                    Quarter            Quarter           Quarter             Quarter
                                                    -------            -------           -------             -------
                                                                             (in thousands)
              
              2000:
                 Operating revenues                 $247,959           $336,978           $453,231           $585,668
                 Operating income                     16,872             15,200             42,519             40,159
                 Net income available
                  for common stock                     9,061              8,061             16,285             19,363

              1999:
                 Operating revenues                 $168,201           $186,195           $219,779           $217,700
                 Operating income                     15,980             13,786             16,675             15,450
                 Net income available
                  for common stock                     9,035              7,763              9,725             10,544



 (17)2001.
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(in thousands)
2002:
 
 
 
 
 
 
 
 
 
 
     Operating revenues
 
 
$
66,671
 
$
73,391
 
$
77,682
 
$
69,709
 
     Operating income
 
 
 
28,926
 
 
27,794
 
 
27,797
 
 
25,621
 
     Income from continuing operations
 
 
 
11,088
 
 
9,131
 
 
11,013
 
 
9,051
 
     Net income
 
 
 
11,984
 
 
9,131
 
 
11,013
 
 
9,051
 
2001:
 
 
     Operating revenues
 
 
$
85,684
 
$
78,516
 
$
63,167
 
$
59,593
 
     Operating income
 
 
 
34,230
 
 
40,524
 
 
22,916
 
 
12,269
 
     Income from continuing operations
 
 
 
16,249
 
 
19,971
 
 
8,258
 
 
(1,204
)
     Net income
 
 
 
21,081
 
 
19,971
 
 
8,258
 
 
(1,204
)
(18)     SUBSEQUENT EVENT (Unaudited)

On March 8, 2001,February 26, 2003, the Company’s parent filed an application with the Federal Energy Regulatory Commission (FERC) asking for authorization to implement a corporate restructuring. This application was approved by FERC. To effect this corporate restructuring, the Company declared a non-cash dividend, consisting of all the Company’s stock in its wholly-owned subsidiary, Black Hills Energy Capital,  Inc.,Capital. This dividend will be paid to the Company's  independent
power  subsidiary  announced it had signed a definitive  agreement to purchase a
240 megawatt  gas-fired turbine  generation  facility  (Fountain Valley) located
near Colorado  Springs,  Colorado from Enron  Corporation.  The  transaction  is
expected to close aroundParent on March 31, 2001.

The  Fountain  Valley  facility  features  six LM-6000  simple-cycle,  gas-fired
turbines,  a technology identical to existing Company facilities in Colorado and
Wyoming. All necessary permitting has been approved and2003. With the plant is expected to
phase in its  generation  capacity  beginning  in May  2001.  The  Company  also
announced that it has signed an 11-year contract with Public Servicecompletion of Colorado
to utilizethis restructuring, the plant for peaking purposes. The contract is a tolling arrangement
in which the Company assumes no fuel costs.  The costCompany’s business will consist solely of the project is expected
to be  approximately  $175 million.  The Company  expects to finance the project
primarily with  non-recourse  debt and negotiations are presently under way with
certain lenders.


electric utility operations.
ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL
DISCLOSURE
In May 2002, Black Hills Power, Inc. announced that the Board of Directors, upon recommendation of its Audit Committee, ended the engagement of Arthur Andersen LLP as the Company’s independent public accountants and in June 2002 engaged Deloitte & Touche LLP to serve as the Company’s independent auditors for the fiscal year ended December 31, 2002.
For more information, see the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 24, 2002.
In November 2002, Deloitte & Touche LLP completed re-audits of the Company’s 2000 and 2001 consolidated financial statements, which were previously audited by Arthur Andersen LLP.
PART III
ITEM 14.     CONTROLS AND FINANCIAL DISCLOSURE

No changePROCEDURES
Evaluation of accountantsdisclosure controls and procedures
Within 90 days prior to the filing date of the Form 10-K, our chief executive officer and chief financial officer evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-14(c) and 15d-14(c) of the Securities Exchange Act of 1934 (Exchange Act). Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is included in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.
Changes in internal controls
Our chief executive officer and chief financial officer have concluded that there were no significant changes in our internal controls or disagreements on any matterin other factors that could significantly affect these controls subsequent to the date of accounting principlestheir most recent evaluation of such controls, and that there were no significant deficiencies or practices or financial statement disclosure have occurred.

material weaknesses in our internal controls.
PART IV
ITEM 14.15.      EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)     1.           Consolidated Financial Statements

               Financial  statements required by Item 14
Financial statements required by Item 15 are listed in the index included in Item 8 of Part II.

          2.           Schedules
Schedule II – Consolidated Valuation and Qualifying Accounts for the years ended December 31, 2002, 2001 and 2000.

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

BLACK HILLS POWER, INC.
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
Additions
        Description
Balance at
beginning of year
Charged to costs
and expenses
Deductions
Balance at
end of year
(In thousands)
Allowance for
doubtful accounts:
2002
 
 
$
2,677
 
$
(731
)
$
(175
)
$
1,771
 
2001
 
 
 
542
 
 
2,611
 
 
(476
)
 
2,677
 
2000
 
 
 
263
 
 
416
 
 
(137
)
 
542
 
          3.           Exhibits

         Exhibit
         Number                                      Description

               2*          Plan of Exchange Between Black Hills  Corporation and
                           Black Hills Holding  Corporation (filed as an exhibit
                           to the Black Hills Holding Corporation's Registration
                           Statement on Form S-4 (No. 333-52664)).
               3.1*        Restated  Articles of Incorporation of the Registrant
                           (filed as an  exhibit  to the  Registrant's  Form 8-K
                           dated June 7, 1994 (No. 1-7978)).
               3.2         Articles   of    Amendment   to   the   Articles   of
                           Incorporation  of the  Registrant,  as filed with the
                           Secretary  of State of the  State of South  Dakota on
                           December 22, 2000.
               3.3*        Bylaws of the Registrant  (filed as an exhibit to the
                           Registrant's Registration Statement on Form S-8 dated
                           July 13, 1999).
               4.1*        Restated  and Amended  Indenture of Mortgage and Deed
                           of Trust of Black Hills Corporation (now called Black
                           Hills  Power,  Inc.)  dated as of  September  1, 1999
                           (filed  as  an   exhibit  to  Black   Hills   Holding
                           Corporation's Registration Statement on Form S-4 (No.
                           333-52664)).
              10.1*        Agreement for Transmission Service and the Common Use
                           of Transmission  Systems dated January 1, 1986, among
                           Black  Hills  Power,   Inc.,   Basin  Electric  Power
                           Cooperative,  Rushmore  Electric  Power  Cooperative,
                           Inc.,  Tri-County Electric  Association,  Inc., Black
                           Hills Electric  Cooperative,  Inc. and Butte Electric
                           Cooperative,  Inc.  (filed  as  Exhibit  10(d) to the
                           Registrant's Form 10-K for 1987).
              10.2*        Restated and Amended Coal Supply Agreement for NS II
                           dated February 12, 1993 (filed as Exhibit 10(c) to
                           the Registrant's Form 10-K for 1992).
              10.3*        Coal Leases between Wyodak Resources Development
                           Corp. and the Federal Government
                            -Dated May 1, 1959 (filed as Exhibit 5(i) to the
                             Registrant's Form S-7, File No. 2-60755)
                               -Modified  January  22,  1990  (filed as  Exhibit
                                10(h) to the Registrant's Form 10-K for 1989)
                            -Dated April 1, 1961 (filed  as  Exhibit 5(j) to the
                             Registrant's Form S-7, File No. 2-60755)
                               -Modified  January  22,  1990  (filed as  Exhibit
                                10(i) to  Registrant's  Form 10-K for  1989)
                            -Dated October 1, 1965 (filed as Exhibit 5(k) to the
                             Registrant's Form S-7, File No. 2-60755)
                               -Modified January 22, 1990 (filed as Exhibit
                                10(j) to the Registrant's Form 10-K for 1989).
              10.4*       Further Restated and Amended Coal Supply Agreement
                          dated May 5, 1987 between Wyodak Resources Development
                          Corp. and Pacific Power & Light Company (filed as
                          Exhibit 10(k) to the Registrant's Form 10-K for 1987).

              10.5*        Second  Restated  and Amended  Power Sales  Agreement
                           dated  September  29, 1997,  between  PacifiCorp  and
                           Black Hills Power,  Inc.  (filed as Exhibit  10(e) to
                           the Registrant's Form 10-K for 1997).
              10.6*        Coal  Supply  Agreement  for  Wyodak  Unit  #2  dated
                           February  3,  1983,  and  Ancillary  Agreement  dated
                           February   3,   1982,    between   Wyodak   Resources
                           Development Corp.,  Pacific Power & Light Company and
                           Black Hills Power,  Inc.  (filed as Exhibit  10(o) to
                           the  Registrant's  Form 10-K for 1983).  Amendment to
                           Agreement  for Coal Supply for Wyodak #2 dated May 5,
                           1987 (filed as Exhibit 10(o) to the Registrant's Form
                           10-K for 1987).
              10.7*        Reserve Capacity  Integration  Agreement dated May 5,
                           1987, between Pacific Power & Light Company and Black
                           Hills  Power,  Inc.  (filed as  Exhibit  10(u) to the
                           Registrant's Form 10-K for 1987).
              10.8*        Marketing, Capacity and Storage Service Agreement
                           between Black Hills Power, Inc. and PacifiCorp dated
                           September 1, 1995 (filed as Exhibit 10(ag) to the
                           Registrant's Form 10-K for 1995).
              10.9*        Assignment  of Mining  Leases and  Related  Agreement
                           effective  May 27,  1997,  between  Wyodak  Resources
                           Development  Corp.  and Kerr-McGee  Coal  Corporation
                           (filed as Exhibit 10(u) to the Registrant's Form 10-K
                           for 1997).
              10.10*       Rate Freeze Extension (filed as Exhibit 10(t) to the
                           Registrant's Form 10-K for 1999).
              10.11*+      Amended and Restated Pension Equalization Plan of
                           Black Hills Corporation dated January 6, 2000 (filed
                           as Exhibit 10.11 to Black Hills  Corporation's
                           Form 10-K for 2000).
              10.12*+      First Amendment to the Pension  Equalization  Plan of
                           Black Hills Corporation dated January 30, 2001 (filed
                           as Exhibit  10.12 to Black Hills  Corporation's  Form
                           10-K for 2000).
 .             10.13*+      Black Hills Corporation Nonqualified Deferred
                           Compensation Plan dated June 1, 1999 (filed as
                           Exhibit 10.13 to Black Hills Corporation's Form 10-K
                           for 2000).
              10.14*+      Black Hills Corporation 1999 Stock Option Plan (filed
                           as Exhibit 10.14 to Black Hills Corporation's Form
                           10-K for 2000).
              10.15*+      Agreement for Supplemental Pension Benefit for
                           Everett E. Hoyt dated January 20, 1992 (filed as
                           Exhibit 10(gg) to the Registrant's Form 10-K for
                           1992).
              10.16*+      Change in Control Agreements for various officers
                           (filed as Exhibit 10(af) to the Registrant's
                           Form 10-K for 1995).
              10.17*+      Black Hills Corporation 1996 Stock Option Plan (filed
                           as Exhibit 10(s) to the Registrant's Form 10-K for
                           1997).
              10.18*+      Outside Directors Stock Based Compensation Plan
                           (filed as Exhibit 10(t) to the Registrant's Form 10-K
                           for 1997).
              10.19*+      Officers Short-Term Incentive Plan (filed as Exhibit
                           10(s) to the Registrant's Form 10-K for 1999).
              10.20*       Agreement and Plan of Merger, dated as of January  1,
                           2000,  among  Black  Hills Corporation, Black Hills
                           Energy Capital, Inc., Indeck Capital, Inc., Gerald R.
                           Forsythe, Michelle R. Fawcett, Marsha Fournier,
                           Monica Breslow, Melissa S. Forsythe and John W.
                           Salyer, Jr. (Exhibit 2 to Schedule 13D filed on
                           behalf of the former shareholders of Indeck Capital,
                           Inc. consisting of Gerald R. Forsythe, Michelle R.
                           Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                           Forsythe and John W. Salyer, Jr., dated July 7, 2000)
              10.21*       Addendum to the Agreement  and Plan of Merger,  dated
                           as of April 6, 2000,  among Black Hills  Corporation,
                           Black Hills Energy  Capital,  Inc.,  Indeck  Capital,
                           Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                           Fournier,  Monica  Breslow,  Melissa S.  Forsythe and
                           John W. Salyer,  Jr. (Exhibit 3 to Schedule 13D filed
                           on  behalf  of  the  former  shareholders  of  Indeck
                           Capital,  Inc.  consisting  of  Gerald  R.  Forsythe,
                           Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
                           Melissa S.  Forsythe and John W. Salyer,  Jr.,  dated
                           July 7, 2000).
              10.22*       Supplemental  Agreement  Regarding  Contingent Merger
                           Consideration,  dated as of January  1,  2000,  among
                           Black Hills Corporation,  Black Hills Energy Capital,
                           Inc.,  Indeck  Capital,  Inc.,  Gerald  R.  Forsythe,
                           Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
                           Melissa S. Forsythe and John W. Salyer,  Jr. (Exhibit
                           4 to  Schedule  13D  filed on  behalf  of the  former
                           shareholders  of Indeck Capital,  Inc.  consisting of
                           Gerald  R.  Forsythe,  Michelle  R.  Fawcett,  Marsha
                           Fournier,  Monica  Breslow,  Melissa S.  Forsythe and
                           John W. Salyer, Jr., dated July 7, 2000).

              10.23*       Supplemental  Agreement  Regarding  Restructuring  of
                           Certain Qualifying  Facilities (Exhibit 5 to Schedule
                           13D  filed on behalf of the  former  shareholders  of
                           Indeck   Capital,   Inc.   consisting  of  Gerald  R.
                           Forsythe,   Michelle  R.  Fawcett,  Marsha  Fournier,
                           Monica  Breslow,  Melissa  S.  Forsythe  and  John W.
                           Salyer, Jr., dated July 7, 2000).
              10.24*       Addendum to the Agreement  and Plan of Merger,  dated
                           as of June 30, 2000,  among Black Hills  Corporation,
                           Black Hills Energy  Capital,  Inc.,  Indeck  Capital,
                           Inc., Gerald R. Forsythe, Michelle R. Fawcett, Marsha
                           Fournier,  Monica  Breslow,  Melissa S.  Forsythe and
                           John W. Salyer,  Jr. (Exhibit 6 to Schedule 13D filed
                           on  behalf  of  the  former  shareholders  of  Indeck
                           Capital,  Inc.  consisting  of  Gerald  R.  Forsythe,
                           Michelle R. Fawcett, Marsha Fournier, Monica Breslow,
                           Melissa S.  Forsythe and John W. Salyer,  Jr.,  dated
                           July 7, 2000).

- ----------
*       Previously filed as part of the filing indicated and incorporated by
        reference herein.

+       Indicates a board of director or management compensatory plan.


(b)      Reports on Form 8-K

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

         Form 8-K filed December 22, 2000.

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

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

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

Exhibit
Number

Description

2*

Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation's Registration Statement on Form S-4 (No. 333-52664)).
3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000).
3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999).
4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as an exhibit to Black Hills Holding Corporation's Registration Statement on Form S-4 (No. 333-52664)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarter ended September 30, 2002).
10.1*
Agreement for Transmission Service and the Common Use of Transmission Systems dated January 1, 1986, among Black Hills Power, Inc., Basin Electric Power Cooperative, Rushmore Electric Power Cooperative, Inc., Tri-County Electric Association, Inc., Black Hills Electric Cooperative, Inc. and Butte Electric Cooperative, Inc. (filed as Exhibit 10(d) to the Registrant's Form 10-K for 1987).
10.2*
Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant's Form 10-K for 1992).
10.3*
Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant's Form 10-K for 1997).
10.4*
Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1987).
10.5*
Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).
10.6*
Purchase and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc. dated June 18, 2001 to purchase Southwest Power, LLC.
99.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
_________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.
+
Indicates a board of director or management compensatory plan.

(b)

Reports on Form 8-K

The Registrant has not filed any reports on Form 8-K during the last quarter of the period covered by this report.

(c)

See (a) 3. Exhibits above.

(d)

See (a) 2. Schedules above.

SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.
The Registrant is not required to send an Annual Report or Proxy to its sole security holder and parent company, Black Hills Corporation.
SIGNATURES
        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

                                              BLACK HILLS POWER, INC.

                                              By    DANIEL P. LANDGUTH
                                              Daniel P. Landguth, Chairman
                                              and Chief Executive Officer
BLACK HILLS POWER, INC.


By: /S/ DANIEL P. LANDGUTH
Daniel P. Landguth, Chairman
and Chief Executive Officer
Dated: March 30, 200131, 2003
        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

       DANIEL P. LANDGUTH                                     Director and Principal                      March 30, 2001
- ---------------------------------------------                   Executive Officer
Daniel P. Landguth, Chairman,
 and Chief Executive Officer

       MARK T. THIES                                          Principal Financial Officer                 March 30, 2001
- ---------------------------------------------
Mark T. Thies, Senior Vice President and
 Chief Financial Officer

       ROXANN R. BASHAM                                       Principal Accounting Officer                March 30, 2001
- ---------------------------------------------
Roxann R. Basham, Vice President-Controller,
 and Assistant Secretary

       ADIL M. AMEER                                                   Director                           March 30, 2001
- ---------------------------------------------
Adil M. Ameer

       BRUCE B. BRUNDAGE                                               Director                           March 30, 2001
- ---------------------------------------------
Bruce B. Brundage

       DAVID C. EBERTZ                                                 Director                           March 30, 2001
- ---------------------------------------------
David C. Ebertz

       GERALD R. FORSYTHE                                              Director                           March 30, 2001
- ---------------------------------------------
Gerald R. Forsythe

       JOHN R. HOWARD                                                  Director                           March 30, 2001
- ---------------------------------------------
John R. Howard

       EVERETT E. HOYT                                                 Director and Officer               March 30, 2001
- ---------------------------------------------
Everett E. Hoyt, President and Chief
Operating Officer

       KAY S. JORGENSEN                                                Director                           March 30, 2001
- ---------------------------------------------
Kay S. Jorgensen

       DAVID S. MANEY                                                  Director                           March 30, 2001
- ---------------------------------------------
David S. Maney

       THOMAS J. ZELLER                                                Director                           March 30, 2001
- ---------------------------------------------

  /s/ DANIEL P. LANDGUTH                                       Director and Principal                      March 31, 2003
Daniel P. Landguth, Chairman,                                   Executive Officer
 and Chief Executive Officer

  /s/ MARK T. THIES                                            Principal Financial Officer                 March 31, 2003
Mark T. Thies, Senior Vice President and
 Chief Financial Officer

  /s/ ROXANN R. BASHAM                                         Principal Accounting Officer                March 31, 2003
Roxann R. Basham, Vice President-Controller,
 and Assistant Secretary

  /s/ BRUCE B. BRUNDAGE                                        Director                                    March 31, 2003
Bruce B. Brundage

  /s/ DAVID C. EBERTZ                                          Director                                    March 31, 2003
David C. Ebertz

  /s/ JOHN R. HOWARD                                          Director                                    March 31, 2003
John R. Howard

  /s/ EVERETT E. HOYT                                         Director and Officer                        March 31, 2003
Everett E. Hoyt, President and Chief
Operating Officer

  /s/ KAY S. JORGENSEN                                        Director                                    March 31, 2003
Kay S. Jorgensen

  /s/ DAVID S. MANEY                                          Director                                    March 31, 2003
David S. Maney

  /s/ THOMAS J. ZELLER                                        Director                                    March 31, 2003
Thomas J. Zeller

CERTIFICATION
I, Daniel P. Landguth, certify that:
1.
I have reviewed this annual report on Form 10-K of Black Hills Power, Inc.;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.
The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 31, 2003
/s/ Daniel P. Landguth      
Chairman and
Chief Executive Officer
CERTIFICATION
I, Mark T. Thies, certify that:
1.
I have reviewed this annual report on Form 10-K of Black Hills Power, Inc.;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)
evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.
The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6.
The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 31, 2003
/s/ Mark T. Thies      
Senior Vice President and
Chief Financial Officer
INDEX TO EXHIBITS


       Exhibit
       Number                               Description

          2*          Plan of Exchange Between Black Hills Corporation and Black
                      Hills Holding Corporation (filed as an exhibit to the
                      Black Hills Holding Corporation's Registration Statement
                      on Form S-4 (No. 333-52664)).
         3.1*         Restated Articles of Incorporation of the Registrant
                      (filed as an exhibit to the Registrant's Form 8-K dated
                      June 7, 1994 (No. 1-7978)).
         3.2          Articles of Amendment to the Articles of Incorporation of
                      the Registrant, as filed with the Secretary of State
                      of the State of South Dakota on December 22, 2000.
         3.3*         Bylaws of the Registrant (filed as an exhibit to the
                      Registrant's Registration Statement on Form S-8 dated July
                      13, 1999).
          4.1*        Restated  and Amended  Indenture  of Mortgage  and Deed of
                      Trust of Black Hills  Corporation  (now called Black Hills
                      Power,  Inc.) dated as of  September  1, 1999 (filed as an
                      exhibit to the Registrant's Registration Statement on Form
                      S-4 (No. 333-52664)).
         10.1*        Agreement for  Transmission  Service and the Common Use of
                      Transmission  Systems dated  January 1, 1986,  among Black
                      Hills  Power,  Inc.,  Basin  Electric  Power  Cooperative,
                      Rushmore  Electric  Power  Cooperative,  Inc.,  Tri-County
                      Electric   Association,   Inc.,   Black   Hills   Electric
                      Cooperative,  Inc. and Butte  Electric  Cooperative,  Inc.
                      (filed as Exhibit 10(d) to the Registrant's  Form 10-K for
                      1987).
         10.2*        Restated and Amended Coal Supply Agreement for NS II dated
                      February 12, 1993 (filed as Exhibit 10(c) to the
                      Registrant's Form 10-K for 1992).
         10.3*        Coal Leases between Wyodak Resources Development Corp. and
                      the Federal Government
                         -Dated May 1, 1959 (filed as Exhibit 5(i) to the
                           Registrant's Form S-7, File No. 2-60755)
                              -Modified January 22, 1990 (filed as Exhibit 10(h)
                               to the Registrant's Form 10-K for 1989)
                         -Dated April 1, 1961 (filed as Exhibit 5(j) to the
                           Registrant's  Form S-7, File No. 2-60755)
                              -Modified January 22, 1990 (filed as Exhibit 10(i)
                               to  Registrant's  Form 10-K for 1989)
                         -Dated October 1, 1965 (filed as Exhibit 5(k) to the
                          Registrant's  Form S-7, File No. 2-60755)
                              -Modified January 22, 1990 (filed as Exhibit 10(j)
                               to the Registrant's Form 10-K for 1989).
         10.4*        Further  Restated and Amended Coal Supply  Agreement dated
                      May 5, 1987 between Wyodak Resources Development Corp. and
                      Pacific Power & Light  Company  (filed as Exhibit 10(k) to
                      the Registrant's Form 10-K for 1987).
         10.5*        Second  Restated and Amended Power Sales  Agreement  dated
                      September  29, 1997,  between  PacifiCorp  and Black Hills
                      Power,  Inc.  (filed as Exhibit 10(e) to the  Registrant's
                      Form 10-K for 1997).


         10.6*        Coal Supply Agreement for Wyodak Unit #2 dated February 3,
                      1983,  and  Ancillary  Agreement  dated  February 3, 1982,
                      between Wyodak Resources  Development Corp., Pacific Power
                      & Light  Company and Black  Hills  Power,  Inc.  (filed as
                      Exhibit  10(o) to the  Registrant's  Form 10-K for  1983).
                      Amendment to Agreement for Coal Supply for Wyodak #2 dated
                      May 5, 1987  (filed as Exhibit  10(o) to the  Registrant's
                      Form 10-K for 1987).
         10.7*        Reserve Capacity Integration  Agreement dated May 5, 1987,
                      between  Pacific  Power & Light  Company  and Black  Hills
                      Power,  Inc.  (filed as Exhibit 10(u) to the  Registrant's
                      Form 10-K for 1987).
         10.8*        Marketing, Capacity and Storage Service Agreement between
                      Black Hills Power, Inc. and PacifiCorp dated September 1,
                      1995 (filed as Exhibit 10(ag) to the Registrant's
                      Form 10-K for 1995).
         10.9*        Assignment   of  Mining   Leases  and  Related   Agreement
                      effective   May  27,  1997,   between   Wyodak   Resources
                      Development  Corp. and Kerr-McGee Coal Corporation  (filed
                      as Exhibit 10(u) to the Registrant's Form 10-K for 1997).
        10.10*        Rate Freeze Extension (filed as Exhibit 10(t) to the
                      Registrant's Form 10-K for 1999).
        10.11*+       Amended and Restated  Pension  Equalization  Plan of Black
                      Hills Corporation  dated January 6, 2000 (filed as Exhibit
                      10.11 to Black Hills Corporation's Form 10-K for 2000).
        10.12*+       First Amendment to the Pension Equalization Plan of Black
                      Hills Corporation dated January 30, 2001 (filed as Exhibit
                      10.12 to Black Hills Corporation's Form 10-K for 2000).
        10.13*+       Black Hills Corporation Nonqualified Deferred Compensation
                      Plan dated June 1, 1999 (filed as Exhibit 10.13 to Black
                      Hills Corporation's Form 10-K for 2000).
        10.14*+       Black  Hills  Corporation  1999 Stock Option  Plan (filed
                      as Exhibit 10.14 to Black Hills Corporation's Form 10-K
                      for 2000).
        10.15*+       Agreement for Supplemental Pension Benefit for Everett E.
                      Hoyt dated January 20, 1992 (filed as Exhibit 10(gg) to
                      the Registrant's Form 10-K for 1992).
        10.16*+       Change in Control Agreements for various officers (filed
                      as Exhibit 10(af) to the Registrant's Form 10-K for 1995).
        10.17*+       Black Hills Corporation 1996 Stock Option Plan (filed as
                      Exhibit 10(s) to the Registrant's Form 10-K for 1997).
        10.18*+       Outside Directors Stock Based Compensation Plan (filed as
                      Exhibit 10(t) to the Registrant's Form 10-K for 1997).
        10.19*+       Officers Short-Term Incentive Plan (filed as Exhibit 10(s)
                      to the Registrant's Form 10-K for 1999).
        10.20*        Agreement and Plan of Merger, dated as of January 1, 2000,
                      among Black Hills Corporation, Black Hills Energy Capital,
                      Inc., Indeck Capital, Inc., Gerald R. Forsythe, Michelle R
                      Fawcett, Marsha Fournier, Moncia Breslow, Melissa S.
                      Forsythe and John W. Salyer, Jr. (Exhibit 2 to Schedule
                      13D filed on behalf of the former shareholders of Indeck
                      Capital, Inc. consisting of Gerald R. Forsythe, Michelle R
                      Fawcett, Marsha Fournier, Monica Breslow, Melissa S.
                      Forsythe and John W. Salyer, Jr., dated July 7, 2000).



         10.21*       Addendum to the Agreement and Plan of Merger,  dated as of
                      April 6, 2000, among Black Hills Corporation,  Black Hills
                      Energy  Capital,  Inc.,  Indeck Capital,  Inc.,  Gerald R.
                      Forsythe,  Michelle R. Fawcett,  Marsha  Fournier,  Monica
                      Breslow,  Melissa  S.  Forsythe  and John W.  Salyer,  Jr.
                      (Exhibit 3 to  Schedule  13D filed on behalf of the former
                      shareholders of Indeck Capital,  Inc. consisting of Gerald
                      R. Forsythe,  Michelle R. Fawcett, Marsha Fournier, Monica
                      Breslow,  Melissa S.  Forsythe  and John W.  Salyer,  Jr.,
                      dated July 7, 2000).
         10.22*       Supplemental   Agreement   Regarding   Contingent   Merger
                      Consideration,  dated as of January 1, 2000,  among  Black
                      Hills  Corporation,  Black  Hills  Energy  Capital,  Inc.,
                      Indeck  Capital,  Inc.,  Gerald R.  Forsythe,  Michelle R.
                      Fawcett,  Marsha  Fournier,  Moncia  Breslow,  Melissa  S.
                      Forsythe  and John W. Salyer,  Jr.  (Exhibit 4 to Schedule
                      13D filed on behalf of the former  shareholders  of Indeck
                      Capital,  Inc. consisting of Gerald R. Forsythe,  Michelle
                      R. Fawcett,  Marsha Fournier,  Monica Breslow,  Melissa S.
                      Forsythe and John W. Salyer, Jr., dated July 7, 2000).
         10.23*       Supplemental Agreement Regarding  Restructuring of Certain
                      Qualifying  Facilities (Exhibit 5 to Schedule 13D filed on
                      behalf of the former shareholders of Indeck Capital,  Inc.
                      consisting  of Gerald R.  Forsythe,  Michelle R.  Fawcett,
                      Marsha Fournier,  Monica Breslow,  Melissa S. Forsythe and
                      John W. Salyer, Jr., dated July 7, 2000).
         10.24*       Addendum to the Agreement and Plan of Merger,  dated as of
                      June 30, 2000, among Black Hills Corporation,  Black Hills
                      Energy  Capital,  Inc.,  Indeck Capital,  Inc.,  Gerald R.
                      Forsythe,  Michelle R. Fawcett,  Marsha  Fournier,  Monica
                      Breslow,  Melissa  S.  Forsythe  and John W.  Salyer,  Jr.
                      (Exhibit 6 to  Schedule  13D filed on behalf of the former
                      shareholders of Indeck Capital,  Inc. consisting of Gerald
                      R. Forsythe,  Michelle R. Fawcett, Marsha Fournier, Monica
                      Breslow,  Melissa S.  Forsythe  and John W.  Salyer,  Jr.,
                      dated July 7, 2000).

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

Description

2*

Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation's Registration Statement on Form S-4 (No. 333-52664)).
3.1*
Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant's Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*
Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant's Form 10-K for 2000).
3.3*
Bylaws of the Registrant (filed as an exhibit to the Registrant's Registration Statement on Form S-8 dated July 13, 1999).
4.1*
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as an exhibit to Black Hills Holding Corporation's Registration Statement on Form S-4 (No. 333-52664)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.1 to the Registrant's Form 10-Q for the quarter ended September 30, 2002).
10.1*
Agreement for Transmission Service and the Common Use of Transmission Systems dated January 1, 1986, among Black Hills Power, Inc., Basin Electric Power Cooperative, Rushmore Electric Power Cooperative, Inc., Tri-County Electric Association, Inc., Black Hills Electric Cooperative, Inc. and Butte Electric Cooperative, Inc. (filed as Exhibit 10(d) to the Registrant's Form 10-K for 1987).
10.2*
Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant's Form 10-K for 1992).
10.3*
Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant's Form 10-K for 1997).
10.4*
Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant's Form 10-K for 1987).
10.5*
Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).
10.6*
Purchase and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc. dated June 18, 2001 to purchase Southwest Power, LLC.
99.1
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.2
Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
_________________
*
Previously filed as part of the filing indicated and incorporated by reference herein.
+
Indicates a board of director or management compensatory plan.