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

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

          For the fiscal year ended December 31, 20022003

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

          For the transition period from ___________________ to __________________

          Commission File Number 1-7978

BLACK HILLS POWER, INC.

Incorporated in South Dakota                       IRS Identification Number 46-0111677

625 Ninth Street
Rapid City, South Dakota 57701

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

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

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

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

YES     X                 NO____NO ______

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

        This paragraph is not applicable to the Registrant.                                                X

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                        ______NONO     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 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’s classes of common stock, as of the latest practicable date.

ClassOutstanding at March 28, 2003

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

Reduced Disclosure

 1.ClassOutstanding at February 29, 2004

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

Reduced Disclosure

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.

1


TABLE OF CONTENTS

Page

ITEMS 11. & 22.
  BUSINESS AND PROPERTIES   3 
      General   3 
      Electric UtilityRate Regulation   3
    Independent Power45 
      Risk Factors   56 

ITEM 33.
  LEGAL PROCEEDINGS   109 

ITEM 55.
  
MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
   
129
 

ITEM 77.
  
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF
OPERATIONS
   12

ITEM 7A
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK169 
      Market Risk DisclosuresResults of Operations   16
    Energy Activities17
    Financing Activities17
    Credit Risk189 
      Safe Harbor for Forward Looking Information   1811 

ITEM 88.
  CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA   2112 

ITEM 99.
  
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
   4736 

ITEM 149A.
  CONTROLS AND PROCEDURES   4736 

ITEM 1515.
  
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
   4837 

 
  
SIGNATURES
   5039 

 
  
CERTIFICATIONS
51

INDEX TO EXHIBITS
   5340 

2


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.

Distribution and Transmission

Our distribution and transmission businesses serve approximately 60,00061,000 electric customers, with an electric transmission system of 447 miles of high voltage lines and 514513 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 sell approximately 4647 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 (PSCO) for a period through 2004. For the 10-year period beginning in 2003, we willour utility and our power generation segment each provide 20 megawatts of unit contingent energy and capacity to the Municipal Energy Agency of Nebraska.

Regulated Power Plants and Purchased Power

Our utility 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:


Since 1995, our utility haswe have been a net producer of energy. Our utilityWe reached itsour 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.

4


Independent PowerRate Regulation

Our independentExisting Rate Regulation

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

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

new governmental impositions increasing annual costs for South Dakota customers by more than $2.0 million;
simultaneous forced outages of both our Wyodak plant 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 expansionNeil Simpson II plant projected to continue at the Las Vegas cogeneration powerleast 60 days;
forced outages occurring to either plant which wentcontinue for a period of three months and are projected to last at least nine months;
an increase in the Consumer Price Index at a monthly rate for six months which would result in a 10 percent or higher annual inflation rate;
the loss of a South Dakota customer or revenue from an existing South Dakota customer that would result in a loss of revenue of $2.0 million or more during any 12-month period;
the cost of coal to our South Dakota customers increases and is projected to increase by more than $2.0 million over the cost for the most recent calendar year; and
electric deregulation occurs as a result of either federal or state mandate, which allows any of our customers to choose its provider of electricity at any time during the freeze period.

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

machinery failure;
load loss caused by either an economic downturn or changes in regulation;
increased costs under power purchase contracts over which we have no control;
government interferences; and
acts of nature and other unexpected events that could cause material losses of income or increases in costs of doing business.

However, the settlement anticipates that we will retain, during that period of time, earnings realized from more efficient operations, sales from load growth, and off-system sales of power and energy.

Over the last several years, we have initiated an effort to enter into new contracts with our largest industrial customers. The new contracts contain “meet or release” provisions that grant us a five-year right to continue to serve a customer at market rates in the event of deregulation. Additionally, through our General Service Large Optional Combined Account Billing Tariff, we have allowed general service January 3, 2003) as well as minority interests in several power-related fundscustomers to aggregate their loads. This tariff also provides us with a net ownership interestfive-year right to continue to serve those customers in the event of 24 megawatts.deregulation. Our “meet or release” contracts currently total more than 108megawatts of large commercial and industrial load. These contracts provide us the assurance of a firm local market for our power resources, in the event deregulation occurs. These industrial and large commercial customers, together with our wholesale power sale agreements with the City of Gillette, Wyoming and Montana-Dakota Utilities Company, equal approximately 47 percent of our utility’s firm load.

5


Regulatory Accounting

As it pertains to the accounting for our utility operations, we follow SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. As a result of our regulatory activity, a 50-year depreciable life for the Neil Simpson II plant is used for financial reporting purposes. If we were not following SFAS 71, a 35- to 40-year life would probably be more appropriate, which would increase depreciation expense by approximately $0.6 — $1.1 million per year. If rate recovery of generation-related costs becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our generation operations. In the event we determine that we no longer meet the criteria for following SFAS 71, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material. Criteria that may give rise to the discontinuance of SFAS 71 include increasing competition that could restrict our ability to establish prices to recover specific costs and a significant change in the manner in which rates are set by regulators from cost-based regulation to another form of regulation. We periodically review these criteria to ensure that the continuing application of SFAS 71 is appropriate.

New Accounting Pronouncements

See Note 1 of our Notes to Consolidated Financial Statements for information on new accounting standards adopted in 2003 or pending adoption.

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:


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“Baa2” by Moody’s Investor Services, Inc., or Moody’s.Moody’s and “BB+” by Standard & Poors. Our credit rating on our First Mortgage Bonds is “Baa1” by Moody’s and “BBB” by Standard & Poor’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 extendedContinuing conflict with Iraqin the Middle East or an increase infurther 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.

6


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. After the rate freeze agreement expires, current rates will remain in effect until a point when the SDPUC would decide new rates are appropriate.

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:



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 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.liabilities. 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:


8


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 sellselling 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. ItInformation regarding our legal proceedings 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 ownedincorporated herein 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 respectreference 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“Legal Proceedings” subcaption within Item 8, Note 6, “Commitments 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 outcomeContingencies”, of our investigation or the viability of potential claims basedNotes to Financial Statements in this Annual report 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.Form 10-K.

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’SMANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

Consolidated Results

Overview

Revenue and net income (loss) from continuing operations provided by each business group asIn 2003, we made a percentagenon-cash dividend to our parent company, Black Hills Corporation, consisting of our total revenue100 percent ownership in Black Hills Generation, Inc., formerly known as Black Hills Energy Capital, Inc. As a result, we no longer have any subsidiaries 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 existedoperate only 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 yearbusiness.

Results 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.

Operations

2003
2002
2001
(in thousands)

Revenue
  $171,019 $162,186 $213,210 
Operating expenses   119,920  104,026  129,102 



Operating income  $51,099 $58,160 $84,108 



Income from continuing operations  $24,089 $30,217 $45,238 



Earnings in 2001 included a $4.4 million after-tax charge for financial exposure to Enron Corporation andThe following table provides 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 operating statistics:

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 



2003
2002
2001
Firm electric sales - MWh   1,994,819  1,966,060  2,012,354 
Wholesale off-system - MWh   930,706  979,677  965,030 

We currently have a winter peak load of 344 megawatts established in December 1998 and a summer peak load of 392 megawatts established in August 2001. We own 435 megawatts of electric utility generating capacity and purchase an additional 6050 megawatts under a long-term agreement (decreasingagreement.

9


2003 Compared to 55 megawatts2002

Electric revenue increased 5 percent in 2003).2003, compared to 2002, primarily due to an 18 percent increase in wholesale off-system sales at an average price that was 24 percent higher than the average price in 2002.

Firm kilowatt-hour sales increased 1 percent. Residential and commercial sales increases of 2 percent and 3 percent, respectively, in 2003 accounted for a $2.1 million increase in revenue. The 18 percent increase in wholesale off-system sales accounted for a $5.8 million increase in revenues. These increases were off-set by a 4 percent decrease in industrial sales, primarily due to the closing of Homestake Mine, which had been one of our largest customers.

Revenue per kilowatt-hour sold was 5.6 cents in 2003 compared to 5.3 cents in 2002. The number of customers in the service area increased to 61,148 in 2003 from 59,948 in 2002.

Electric utility operating expenses increased $15.9 million due to a $10.1 million increase in fuel and purchase power cost, a $3.7 million increase in certain operations and maintenance costs, including pension expense, a $1.5 million increase in depreciation expense and a $2.5 million increase in interest expense due to the full year impact of $75 million of first mortgage bonds issued in August 2002.

The increase in fuel cost is due to a 77 percent increase in average gas prices for combustion turbine generation facilities and a 19 percent increase in average megawatt-hour purchased power costs.

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 one1 percent above normal in 2002 and four4 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 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:

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.Foundation.

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.10

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 Annual Report on Form 10-K includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. We make these forward-looking statements 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. 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 that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including:



SEC

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

11


ITEM 8.           CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Independent Auditors' Report21

Consolidated Statements of Income
  for the three years ended December 31, 200222

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

Consolidated Statements of Cash Flows
   for the three years ended December 31, 200224

Consolidated Statements of Common Stockholder's Equity and Comprehensive Income
   for the three years ended December 31, 200225

Notes to Consolidated Financial Statements
26-47
Independent Auditors' Report   12 

Consolidated Statements of Income
  
  for the three years ended December 31, 2003   13 

Consolidated Balance Sheets as of December 31, 2003 and 2002
   14 

Consolidated Statements of Cash Flows
  
   for the three years ended December 31, 2003   15 

Consolidated Statements of Common Stockholder's Equity and Comprehensive Income
  
   for the three years ended December 31, 2003   16 

Notes to Consolidated Financial Statements
   17-36

INDEPENDENT AUDITORS’AUDITORS' REPORT

To the StockholderShareholder of Black Hills Power, Inc.:
Rapid City, South Dakota:

We have audited the accompanying consolidated balance sheets of Black Hills Power, Inc. and subsidiaries (the Company) as of December 31, 20022003 and 2001,2002, 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, 2002. Our audits also included the financial statement schedule listed in the Table of Contents at Item 15.2003. These financial statements and financial statement schedule are the responsibility of the Corporation’sCompany's management. Our responsibility is to express an opinion on these consolidated 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 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, such consolidated financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. and subsidiaries as of December 31, 20022003 and 2001,2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002,2003, in conformity with accounting principles generally accepted in the United States 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,
March 10, 20032004

12


BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF INCOME

Years ended December 31,Years ended December 31,2002
 2001
 2000
 Years ended December 31,2003
2002
2001
(in thousands)(in thousands)

Operating revenues
  $287,453 $286,960 $193,233   $171,019 $162,186 $213,210 






Operating expenses:  
Fuel and purchased power  60,620  77,055  57,584   54,815  44,742  66,749 
Operations and maintenance  35,069  41,999  26,258   25,207  24,335  28,216 
Administrative and general  31,691  28,700  14,721   12,965  10,041  11,173 
Depreciation and amortization  43,933  31,703  18,612   18,999  17,499  15,773 
Taxes, other than income taxes  10,341  11,625  7,060   7,934  7,409  7,191 






  181,654  191,082  124,235   119,920  104,026  129,102 






Equity in earnings of unconsolidated subsidiaries  4,339  14,061  19,577 



Operating income  110,138  109,939  88,575   51,099  58,160  84,108 






Other (expense) income:  
Interest expense  (47,865) (44,584) (25,329)  (17,044) (13,662) (15,781)
Interest income  825  5,239  5,758   1,512  734  4,858 
Other expense  (312) (4,758) (540)  (286) (312) (3,623)
Other income  2,334  5,641  5,735   430  364  (69)






  (45,018) (38,462) (14,376)  (15,388) (12,876) (14,615)






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 from continuing operations before income taxes  35,711  45,284  69,493 
Income taxes  (21,675) (24,017) (22,583)  (11,622) (15,067) (24,255)






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  --  -- 



Income from continuing operations  24,089  30,217  45,238 
Discontinued operations, net of income taxes (Note 10)  1,906  10,962  2,868 



Net income $41,179 $48,106 $52,848  $25,995 $41,179 $48,106 






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

13


BLACK HILLS POWER, INC.
CONSOLIDATED BALANCE SHEETS

At December 31,At December 31,2002
 2001
 At December 31,2003
2002
(in thousands, except share amounts)(in thousands, except share
amounts)
ASSETS            

Current assets:
  
Cash and cash equivalents $45,042 $14,832  $1,052 $518 
Restricted cash  1,070  -- 
Receivables (net of allowance for doubtful accounts of $1,771 
and $2,677, respectively) - 
Receivables (net of allowance for doubtful accounts of $898 
and $882, respectively) - 
Customers  35,942  26,352   15,719  11,971 
Affiliates  53,984  9,457   38,618  54,253 
Other  5,596  5,982   1,293  4,546 
Materials, supplies and fuel  16,206  10,399   9,560  9,743 
Prepaid expenses  2,372  9,822 
Prepaid income taxes  2,813  -- 
Deferred income taxes  2,709  3,855   --  5,397 
Other  325  -- 
Assets of discontinued operations  --  1,008,901 




  163,246  80,699   69,055  1,095,329 




Investments  14,531  51,543   2,920  2,681 




Property and equipment  1,504,898  1,249,800 
Property, plant and equipment  623,197  603,548 
Less accumulated depreciation  (301,054) (240,472)  (212,041) (198,602)




  1,203,844  1,009,328   411,156  404,946 




Other assets:  
Regulatory asset  4,350  4,071   4,320  4,350 
Goodwill  30,562  25,566 
Intangible assets  77,661  85,983 
Other  16,864  16,239   15,622  7,033 




  129,437  131,859   19,942  11,383 




 $1,511,058 $1,273,429  $503,073 $1,514,339 




LIABILITIES AND STOCKHOLDER'S EQUITY  
Current liabilities:  
Current maturities of long-term debt $22,131 $35,881  $1,986 $3,095 
Notes payable  50,000  450 
Notes payable - affiliate  454,824  447,125 
Accounts payable  28,653  13,271   6,929  14,653 
Accounts payable - affiliate  2,990  4,385   7,909  2,585 
Accrued liabilities  22,796  16,929   15,691  15,575 
Derivative liabilities  9,345  10,212 
Deferred income taxes  239  -- 
Liabilities of discontinued operations  --  964,759 




  590,739  528,253   32,754  1,000,667 




Long-term debt, net of current maturities  557,195  415,314   210,056  212,042 





Deferred credits and other liabilities:
  
Deferred income taxes  101,046  65,094   65,633  58,539 
Regulatory liability  5,395  6,249   6,337  6,776 
Derivative liabilities  7,844  5,949 
Other  24,154  11,306   12,724  18,087 




  138,439  88,598   84,694  83,402 




Minority interest in subsidiaries  6,457  19,536 


Commitments and contingencies (Notes 11, 12 and 16) 
Commitments and contingencies (Notes 6 and 7) 

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 
Issued: 23,416,396 shares in 2003 and 2002  23,416  23,416 
Additional paid-in capital  80,961  80,961   39,549  80,961 
Retained earnings  131,906  121,875   114,098  131,906 
Accumulated other comprehensive loss  (18,055) (4,524)  (1,494) (18,055)




  218,228  221,728   175,569  218,228 




 $1,511,058 $1,273,429  $503,073 $1,514,339 




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

14


BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

Years ended December 31,Years ended December 31,2002
 2001
 2000
 Years ended December 31,2003
2002
2001
(in thousands)(in thousands)
Operating activities:               
Net income $41,179 $48,106 $52,848  $25,995 $41,179 $48,106 
Income from discontinued operations  --  (4,832) (12,570)
Adjustments to reconcile net income to net cash  
provided by operating activities-  
Income from discontinued operations  (1,906) (10,962) (2,868)
Depreciation and amortization  43,933  31,703  18,612   18,999  17,499  15,773 
Provision for valuation allowances  (906) 8,135  279   16  14  441 
Gain on sales of assets  --  --  (3,736)
Deferred income taxes  22,993  4,522  1,293   8,918  11,675  2,354 
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)  (2,304) (4,493) 10,870 
Accounts payable and other current liabilities  46,477  (3,289) 12,213   (2,284) 2,936  2,062 
Other operating activities  1,854  (1,044) (6,718)  (3,209) (5,278) 104 






  97,881  89,923  59,373   44,225  52,570  76,842 






Investing activities:  
Property, plant and equipment additions  (178,981) (316,809) (46,975)  (25,427) (37,472) (41,312)
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)  14,798  (42,691) 80,915 
Other investing activities  (19) --  468   (239) 1,222  327 






  (206,043) (451,352) (163,030)  (10,868) (78,941) 39,930 






Financing activities:  
Dividends paid on common stock  (31,148) (28,070) (23,527)  (29,728) (31,148) (28,070)
Increase in short-term borrowings, net  49,550  262,944  84,379 
Decrease in short-term borrowings  --  --  (86,000)
Long-term debt - issuance  160,632  144,103  60,082   --  75,000  -- 
Long-term debt - repayments  (32,501) (13,960) (1,330)  (3,095) (18,042) (3,578)
Other financing activities  (8,161) (1,453) (7,048)






  138,372  363,564  112,556   (32,823) 25,810  (117,648)






Increase in cash and cash equivalents  30,210  2,135  8,899 
Increase (decrease) in cash and cash equivalents  534  (561) (876)
Cash and cash equivalents:  
Beginning of year  14,832  12,697  3,798   518  1,079  1,955 






End of year $45,042 $14,832 $12,697  $1,052 $518 $1,079 






Supplemental disclosure of cash flow information:  
Cash paid during the period for-  
Interest $50,134 $44,820 $26,258  $17,120 $12,894 $15,782 
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 $-- 
Income taxes $6,745 $3,448 $24,095 

Non-cash net assets acquired through issuance of common stock
 $-- $-- $3,635 

Stock dividend distributions to Black Hills Corporation, the
 
parent company of Black Hills Power, Inc. (Note 10) $46,450 $-- $89,643 

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

15


BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
AND COMPREHENSIVE INCOME

Accumulated Accumulated
Common Stock Additional Other AdditionalOther

 Paid-In Retained Comprehensive Common StockPaid-InRetainedComprehensive
Shares
 Amount
 Capital
 Earnings
 Loss
 Amount
 SharesAmountCapitalEarningsIncome (Loss)Total
(in thousands)(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    23,416 $23,416 $77,326 $191,482 $-- $292,224 












Comprehensive Income:  
Net income  --  --  --  48,106  --  48,106   --  --  --  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)
Other comprehensive loss, 
net of tax (see Note 8)  --  --  --  --  (4,524) (4,524)












Total comprehensive income  --  --  --  48,106  (4,524) 43,582   --  --  --  48,106  (4,524) 43,582 
Dividends on common stock  --  --  --  (28,070) --  (28,070)  --  --  --  (28,070) --  (28,070)
Earnout consideration on  
acquisition  --  --  3,635  --  --  3,635   --  --  3,635  --  --  3,635 
Stock distribution to parent  --  --  --  (89,643) --  (89,643)
Non-cash dividend to Parent  --  --  --  (89,643) --  (89,643)












Balance at December 31, 2001  23,416  23,416  80,961  121,875  (4,524) 221,728   23,416  23,416  80,961  121,875  (4,524) 221,728 












Comprehensive Income:  
Net income  --  --  --  41,179  --  41,179   --  --  --  41,179  --  41,179 
Other comprehensive loss,  
net of tax  --  --  --  --  (13,531) (13,531)
net of tax (see Note 8)  --  --  --  --  (13,531) (13,531)












Total comprehensive income  --  --  --  41,179  (13,531) 27,648   --  --  --  41,179  (13,531) 27,648 
Dividends on common stock  --  --  --  (31,148) --  (31,148)  --  --  --  (31,148) --  (31,148)












Balance at December 31, 2002  23,416 $23,416 $80,961 $131,906 $(18,055)$218,228   23,416  23,416  80,961  131,906  (18,055) 218,228 












Comprehensive Income: 
Net income  --  --  --  25,995  --  25,995 
Other comprehensive income, 
net of tax (see Note 8)  --  --  --  --  7,524  7,524 






Total comprehensive income  --  --  --  25,995  7,524  33,519 
Non-cash dividend to Parent  --  --  (41,412) (14,075) 9,037  (46,450)
Dividends on common stock  --  --  --  (29,728) --  (29,728)






Balance at December 31, 2003  23,416 $23,416 $39,549 $114,098 $(1,494)$175,569 






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

16


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003, 2002 2001 and 20002001

(1)            BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. and its subsidiaries (the Company) operate in two primary operating groups: regulatedis an electric utility serving customers in South Dakota, Wyoming and non-regulated power generation. Black Hills Power operates the public utility operations. The Company operates its power generation business through its direct subsidiary, Black Hills Energy Capital (BHEC).Montana. The Company is a wholly owned subsidiary of the publicly traded Black Hills Corporation (the Parent).

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Power, Inc. and its wholly-owned subsidiaries. As discussed in Note 10, the Company has distributed the stock held in its subsidiaries in the form of non-cash dividends to the Parent. These distributions represented 100 percent ownership of the subsidiaries. Activity at the subsidiaries was recorded up to the date of distribution and has been reclassified into “Discontinued operations” in the accompanying consolidated financial statements.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to allowance for uncollectible accounts receivable, realization of market value of derivatives due to commodity risk, intangible asset valuations and 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 owned and majority-owned 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.

As discussed in Note 16, Black Hills Energy Capital made several acquisitions during 2002 and 2001. The Company’s consolidated statements of income include operating activity of these companies beginning with their acquisition date.

The consolidated financial statements also include assets, liabilities and income from discontinued operations (see Note 2).

Minority Interest in Subsidiaries

Minority interest in the accompanying Consolidated Statements of Income represents the share of the income or loss of certain consolidated subsidiaries attributable to the minority shareholders of those subsidiaries. The minority interest in the accompanying Consolidated Balance Sheets reflect the amount of the underlying net assets of those certain consolidated subsidiaries attributable to the minority 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’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’s non-regulated businesses.

The Company’s electric operations follow the provisions of the Financial Accounting Standards Board (FASB) of Statement 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’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$1.1 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’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’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.

At December 31, 2003 and 2002, the Company had regulatory assets of $4.3 million and $4.4 million and regulatory liabilities of $6.3 million and $6.8 million, respectively. Regulatory assets are primarily recorded for the probable future revenue to recover future income taxes related to the deferred tax liability for the equity component of allowance for funds used during construction of utility assets. Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates and also the cost of removal for utility plant, recovered through the Company’s electric utility rates.

17


Cash Equivalents

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

Inventory

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

Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of the related debt.

Property, Plant and Equipment

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

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 9.8 percent, 9.1 10.2percent and 9.710.2 percent during 2003, 2002 and 2001, and 2000, respectively. In addition, the Company capitalizes interest, when applicable, on certain non-regulated construction projects. The amount of AFUDC and interest capitalized was $11.4approximately $0.1 million, $6.8$0.9 million, and $0.9$0.7 million in 2003, 2002 2001 and 2000,2001, 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, results 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 2003 and 2002, and 3.0 percent in 2001 and 2.8 percent in 2000. Non-regulated property, plant and equipment is depreciated on a straight-line basis using estimated useful lives ranging from 3 to 40 years.2001.


Deferred Financing Costs

Deferred financing costs are amortized using the effective interest method over the term of 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 through 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 $4.1 million, $2.5 million and $1.5 million in 2002, 2001 and 2000, respectively. Accumulated amortization was $14.9 million, $4.0 million and $1.5 million at December 31, 2002, 2001 and 2000, respectively.

Impairment of Long-Lived Assets and 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 2003, 2002 2001 or 2000.2001.

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. The Company classifies deferred tax assets and liabilities into current and non-current amounts based on the classification 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 allocated 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 determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured. For long-term non-utility power sales agreements revenue is recognized either 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 lower of the amount billed or the average rate expected over the life of the 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 involved in power generation, the Company uses the equity method to recognize as earnings its pro rata share of the net income or loss of the associated company.

18


Reclassifications

CertainIn 2003, the Company reclassified removal costs that are recoverable under our electric utility rates. These amounts, previously recorded as a component of accumulated depreciation, have been reclassified into regulatory liabilities. Amounts on the 2002 Consolidated Balance Sheet have been reclassified to conform to this presentation. The changes in presentation had no impact on the Company’s stockholders’ equity or results of operations, as previously reported.

In addition, certain 2002 and 2001 and 2000 amounts in the financial statements have been reclassified to conform to the 20022003 presentation. These reclassifications had no effect on the Company’s common stockholder’sstockholders’ equity or results of operations, as previously reported.


Recently Adopted Accounting Pronouncements

SFAS 132-R

In June 2001,December 2003, the Financial Accounting Standards Board (FASB)FASB issued SFAS No. 141, “Business Combinations,” (SFAS 141) and No. 142, “Goodwill132 (Revised), “Employer’s Disclosure about Pensions and Other Intangible Assets”Postretirement Benefits” (SFAS 142)132-R). The Company has adopted SFAS 141, which132-R retains disclosure requirements of the original SFAS 132 and requires all business combinations initiatedadditional disclosures related to assets, obligations, cash flows, and net periodic benefit cost. SFAS 132-R is effective for fiscal years ending after December 15, 2003, except that certain disclosures are effective for fiscal years ending after June 30, 2001 to be accounted15, 2004. Interim period disclosures are effective for usinginterim periods beginning after December 15, 2003. The adoption of 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 amortizationdisclosure 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 cumulative132-R did not have an 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 ofon 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.Financial Statements (see Note 11)7).


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.SFAS 143

In AugustJune 2001, the FASB issued SFAS No. 144, "Accounting143, “Accounting for the Impairment or Disposal of Long-Lived Assets"Asset Retirement Obligations” (SFAS 144)143). 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 the143 provides 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 modeldisclosure requirements for retirement obligations associated with long-lived assets to be disposed of by sale and resolves implementation issues related to SFAS 121. The Company adopted SFAS 144was effective January 1, 2002.2003. SFAS 143 requires that the present value of retirement costs for which the Company has a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The liability is then accreted over time by applying an interest method of allocation to the liability. Adoption did not have a material impacteffect on the Company's consolidatedCompany’s financial position, results of operations or cash flows.

SFAS 150

In May 2003, the FASB issued SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS 150). SFAS 150 provides accounting and disclosure requirements for classification and measurement of certain financial instruments with characteristics of both liabilities and equity. Management adopted SFAS 150 effective July 1, 2003. Adoption did not have a material effect on the Company’s financial position, results of operations or cash flows.

Issue C20

On June 25, 2003, the FASB Derivatives Implementation Group cleared Issue C20, “Scope Exceptions: Interpretation of the Meaning ofNot Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature” (Issue C20). Issue C20 clarifies which contracts qualify for the “normal purchase or sale” exception as provided by paragraph 10(b) of SFAS 133. The Company adopted this guidance on October 1, 2003. Under Issue C20, the Company’s long-term power sales contracts either are not considered derivatives, or qualify for the “normal purchase or sale” exception as defined by SFAS 133, therefore adoption of this guidance had no impact on the Company’s results of operations and financial position.

19


Recently Issued Accounting Pronouncements

FSP 106-1

In June 2001,January 2004, the FASB issued StatementFASB Staff Position (FSP) No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143). SFAS 143 requires that the fair value2003” (FSP 106-1), which permits a sponsor of a liabilitypostretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for an asset retirement obligation be recognized in the period in which it is incurredeffects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 until remaining questions – notably the issue of how to account for the federal subsidy – are resolved. The Company provides prescription drug benefits to certain eligible employees and has elected the one-time deferral of accounting for the effects of the 2003 Medicare Act. The Company intends to analyze the 2003 Medicare Act, along with the associated asset retirement costs being capitalized as partauthoritative guidance, when issued, to determine if its benefit plans need to be amended and how to record the effects of the carrying amount2003 Medicare Act. Specific guidance on the accounting for the federal subsidy provided by the 2003 Medicare Act is pending and that guidance, when issued, could require the Company to change previously reported postretirement benefit information. For more information on the Company’s postretirement benefits, see Note 7.

(2)           PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31, consisted of the long-lived asset. Over time, the liabilityfollowing (in thousands):

Regulated

2003
2002
Lives
(in years)

Electric plant:         
     Production  $316,544 $313,725 25-58  
     Transmission   122,640  94,683 35-50  
     Distribution   150,748  143,629 20-40  
     General   30,205  32,299 7-40  



     Total electric plant   620,137  584,336    
Less accumulated depreciation and amortization   212,041  198,602    



     Electric plant net of accumulated depreciation and amortization   408,096  385,734    
Construction work in progress   3,060  19,212    



     Net electric plant  $411,156 $404,946    



20


(3)           LONG-TERM DEBT

Long-term debt outstanding at December 31, is accreted to its present value each period and the capitalized cost is depreciated over the useful lifeas follows:

2003
2002
(in thousands)
First mortgage bonds:      
     9.00% repaid 2003  $-- $1,113 
     8.06% due 2010   30,000  30,000 
     9.49% due 2018   4,260  4,550 
     9.35% due 2021   29,970  31,635 
     8.30% due 2024   45,000  45,000 
     7.23% due 2032   75,000  75,000 


    184,230  187,298 


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   3,312  3,339 


    27,812  27,839 


Total long-term debt   212,042  215,137 
Less current maturities   (1,986) (3,095)


Net long-term debt  $210,056 $212,042 


Substantially all 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" (SFAS 133). SFAS 133 requires that derivative instruments be recorded in the balance sheet as either an asset or liability measured at fair value. SFAS 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 hedge accounting for qualifying fair value and cash flow hedges. SFAS 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 attributableCompany’s property is subject to the hedged risk be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portionlien 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 on January 1, 2001. On January 1, 2001, the Company had interest rate swaps documented as cash flow hedges. These contracts were defined as derivatives under SFAS 133 and met the requirements for cash flow hedges. Because the contracts were documented as hedges prior to adoption, the transition adjustment was reported in accumulated other comprehensive income. The aggregated entry for these derivatives identified as cash flow hedges increased derivative assets by $0.3 million, increased derivative liabilities by $7.8 million and decreased accumulated other comprehensive income by $7.5 million pre-tax.


(2)      NON-CASH DIVIDEND AND DISCONTINUED OPERATIONS

During the quarter ended March 31, 2001, the Company distributed a non-cash dividend toindenture securing 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 operationsfirst mortgage bonds. First mortgage bonds of the Company for all periods presented.

The net operating results of discontinued operations are includedmay be issued in the Consolidated Statements of Income under the caption "Discontinued operations, net of income taxes"amounts limited by property, earnings 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:


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 for fuel purchases.

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


In 2001, the Company acquired several natural gas swaps when it completed the Las 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 long-term purchase priceother provisions of the index-priced natural gas purchase contract. At acquisition close,mortgage indentures.

Scheduled maturities are approximately $2.0 million a year for the fair value of these swaps was $6.0 million. These swaps were executed with Enron North America Corp. (Enron), which is currently in bankruptcy proceedings.

These swaps met the definition of derivatives under SFAS 133. The Company elected to treat these derivatives as cash flow hedges so that any gains or losses on the fair values of the swaps could be deferred and subsequently recognized when the underlying hedged natural gas was consumed in the plant. The swaps were properly documented and met the criteria for cash flow hedges.

During the fourth quarter of 2001, the Company determined that it was probable that Enron would default on its obligations to the Company 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, 2002, these hedges met effectiveness testing criteria and retained their cash flow hedge status. At December 31, 2002, the Company 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, 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, 2002, the Company had $871.9 million of outstanding, variable-rate debt of which $659.6 million was not 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 interest expense to increase $6.6 million.2004 through 2008.

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, in accordance with SFAS 133, 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 Company’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 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. The Company maintains credit policies with regard to its counterparties that the Company believes limit its overall credit risk.

The Company attempts to mitigate its credit risk by conducting a majority of its business with investment grade companies, obtaining netting agreements where possible and securing its exposure with less creditworthy counterparties through parental guarantees, prepayments and letters of 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:

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

(6)     COMMON STOCK

The Company is a wholly owned subsidiary of Black Hills Corporation.


(7) LONG-TERM DEBT

Long-term debt outstanding at December 31, is as 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 


_________________

(a)Floating rate debt secured by a spare LM6000 turbine.

(b)Approximately 58 percent of the December 31, 2002 balance has been hedged with an interest rate swap moving the floating rates to fixed rates with a weighted average interest rate of 5.98 percent (see Note 3-Risk Management Activities).

(c)Interest rates are presented as of December 31, 2002.

Substantially all of the Company’s utility property is subject to the lien of the indenture securing its first mortgage bonds. First mortgage bonds of the Company may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures.

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

Certain debt instruments of the Company and its subsidiaries contain restrictive covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 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: $22.1 million in 2003, $24.2 million in 2004, $25.6 million in 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 has an unsecured line of credit with Black Hills Generation, a wholly-owned indirect subsidiary of the 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, 2002 and 2001, respectively.

(9)           FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of the Company’s financial instruments at December 31, are as 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 
2003
2002
Carrying Amount
Fair Value
Carrying Amount
Fair Value
Cash and cash equivalents  $1,052 $1,052 $518 $518 
Long-term debt  $212,042 $238,331 $215,137 $238,811 

The following methods and assumptions were used to estimate the fair value of each class of the Company’s financial instruments.

Cash and Cash Equivalents and Restricted Cash

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

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.21

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


(10)(5)           JOINTLY OWNED FACILITYFACILITIES

The Company owns a 20 percent interest and Pacific PowerPacifiCorp owns an 80 percent interest in the Wyodak Plant (Plant), a 330362 megawatt coal-fired electric generating station located in Campbell County, Wyoming. Pacific PowerPacifiCorp is the operator of the Plant. The Company receives 20 percent of the Plant’s capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 2002,2003, the Company’s investment in the Plant included $71.5$72.2 million in electric plant and $26.5$40.4 million in accumulated depreciation, and is included in the corresponding captions in the accompanying Consolidated Balance Sheets. The Company’s share of direct expenses of the Plant was $5.8 million, $5.5 million $5.9 million and $5.6$5.9 million for the years ended December 31, 2003, 2002 2001 and 2000,2001, respectively, and is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income.

The Company also owns a 35 percent interest and Basin Electric Power Cooperative owns a 65 percent interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie placed into service in the fourth quarter of 2003. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the Western Electricity Coordinating Council (WECC) region and the Mid-Continent Area Power Pool, or “MAPP” region. The total transfer capacity of the tie is 400 megawatts – 200 megawatts West to East and 200 megawatts from East to West. The Company is committed to pay 35 percent of the additions, replacements and operating and maintenance expenses. As of December 31, 2003, the Company’s investment in the transmission tie was $20.3 million.

(11)(6)           COMMITMENTS AND CONTINGENCIES

Acquisition Earn-out Agreement

On July 7, 2000, the Company 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 earn-out over a four-year period beginning in 2000. As of December 31, 2001, $3.6 million has been paid under the earn-out. On December 31, 2002, additional consideration of $3.8 million was earned and payable. 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 Purchase and Transmission Services Agreement – Pacific Power— PacifiCorp

In 1983, the Company entered into a 40 year power purchase agreement with PacifiCorp providing for the purchase by the Company of 75 megawatts of electric capacity and energy from PacifiCorp’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 PacifiCorp’s coal-fired electric generating plants. Costs incurred under this agreement were $10.8 million in 2003, $10.9 million in 2002 (net of a $1.3 million refund for prior years) and $13.9 million in 2001.

In addition, the Company has a firm network transmission agreement for 36 MWs of capacity with PacifiCorp that expires on December 31, 2006. Annual costs are approximately $0.9 million per year. The Company uses this agreement to serve the Sheridan, Wyoming electric service territory under our contract with Montana-Dakota Utilities Company.

The Company also has a firm point-to-point transmission service agreement with PacifiCorp that expires on December 31, 2023. The agreement provides that the following amounts of capacity and energy be transmitted: 32 megawatts in 2001, 27 megawatts in 2002, 22 megawatts in 2003, 17 megawatts in 2004-2006 and $14.650 megawatts in 2007-2023. Costs incurred under this agreement were $0.5 million in 2000.2003 and $0.7 million in each of 2002 and 2001.

22


Long TermLong-Term Power Sales Agreements

The Company, through its subsidiaries, has the following significant long-term power sales contracts:



The Company has 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. The Company also has 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 served by the Company’s electric utility and are integrated into our control area and are treated as firm native load.

Ongoing LitigationLegal Proceedings

Hell CanyonForest Fire Claims

In September 2001, a fire occurred in the southwestern Black Hills.Hills, now known as the “Hell Canyon Fire.” It is alleged that the fire occurred when a high voltage electrical span maintained by the Company 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 complaintComplaint 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 thatA substantially similar claims will be assertedsuit was filed against the Company by the United States Forest Service.Service, on June 30, 2003, in the United States District Court for the District of South Dakota, Western Division. The Company’s investigation intoState subsequently joined its claim in the federal action. The State claims damages in the amount of approximately $0.8 million for fire suppression and rehabilitation costs. The United States Government’s claim for fire suppression and related costs has been submitted at approximately $1.3 million. The Company continues to investigate the cause and origin of the fire, is still pending. The total amount of damages claimed byand the State of South Dakota is not specified in the complaint.damage claims. A trial date has been set for early 2005. 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.Dakota, now known as the “Grizzly Gulch Fire.” Before being contained more than eight days later, the fire consumed approximately 11,000over 10,000 acres of public and private land, mostly consisting of rugged forested areas. The fire destroyed approximately 20 structures.7 homes, and 15 outbuildings. 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 the Company, in the Seventh Judicial Circuit Court, Pennington County, South Dakota. The complaintComplaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages iswas asserted with respect to the claim for injury to timber. The total amount of alleged damages is not specified.

On March 3, 2003, the United States of America filed a similar suit against the Company, in the United States District Court, District of South Dakota, Western Division. The federal government complaintgovernment’s 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. In April 2003, the State of South Dakota intervened in the federal action. Accordingly, the state court litigation will be stayed, and all governmental claims will be tried in U.S. District Court.

The total amountstate and federal government claim approximately $5.3 million for suppression costs, $1.2 million for rehabilitation costs, and $0.6 million for timber loss. Additional claims could be asserted for alleged loss of alleged federal damages is not specified.habitat and aesthetics or for assistance to private landowners.

23


The Company is completing its own investigation of the fire cause and origin and has requested access to the materials that form the basis for the assertions of state and federal fire investigators.origin. The Company’s investigation is not complete,continuing, but based onupon information currently available, the Company expectsfiled its Answer to denythe Complaints of both the State and the United States government, denying all claims, and asserting that the fire was caused by an independent intervening cause, or an act of God. The Company expects to vigorously defend any and all claims brought by governmental or private parties.

During the period of April through November 2003, various private civil actions were filed against the Company, asserting that the Grizzly Gulch Fire caused damage to the parties’ real property. These actions were filed in the Fourth Judicial Circuit Court, Lawrence County, South Dakota. The Complaints seek recovery on the same theories asserted in the governmental Complaints, but most of the Complaints specify no amount for damage claims. The Company will vigorously defend these matters as well.

Additional claims could be made for individual and business losses relating to injury to personal and real property, and lost income.

Although we cannot predict the outcome of our investigation or the viability of potential claims with respect to either fire, based on the information currently available, management believes that any such claims, if determined adversely to us,the Company, will not have a material adverse effect on our 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 additional 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.

PPM Energy, Inc. Demand for Arbitration

Other Proceedings

In additionOn January 2, 2004, PPM Energy, Inc. delivered its Demand for Arbitration to the above proceedings,Company. The Demand alleges claims for breach of contract and requests a declaration of the parties’ rights and responsibilities under an Exchange Agreement executed on or about April 3, 2001. Specifically, PPM Energy asserts that the Exchange Agreement obligates the Company to accept receipt and its subsidiaries are involvedcause corresponding delivery of electric energy, and to grant access to transmission rights allegedly covered by the Agreement. PPM Energy requests an award of damages in numerousan amount not less than $20.0 million. The Company denies all claims and will vigorously defend this matter, the timing and outcome of which is uncertain.

Ongoing Litigation

The Company is subject to various other legal proceedings, claims and litigation which arise in the ordinary course of business.operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the consolidated financial position or results of operations of the Company.

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)(7)           EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The Company has a noncontributory defined benefit pension plan (Plan) covering the employees who meet certain eligibility requirements.of the Company. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. The Company’s funding policy is in accordance with the federal government’s funding requirements. The Plan’s assets are held in trust and consist primarily of equity securities and cash equivalents.


Net pension income The Company uses a September 30 measurement date for the Plan was as follows:Plan.

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%

_________________24

*The discount rate used for net periodic pension cost was changed from 7.50 percent in 2002 to 6.75 percent for the calculation of the 2003 Net Periodic Pension cost. This change is expected to increase pension costs by approximately $0.3 million.

**The expected rate of return on plan assets was 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 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 beginningObligations and ending balances of the projectedFunded Status

Change in benefit obligation is as follows (in thousands):obligation:

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 


2003
2002
(in thousands)

Projected benefit obligation at beginning of year
  $38,141 $33,151 


Service cost   714  588 
Interest cost   2,500  2,406 
Actuarial loss   1,110  571 
Discount rate change   4,239  3,380 
Benefits paid   (1,972) (1,955)
Amendments   --  -- 
Taxable wage rate and cost of living rate change   71  -- 


Net increase   6,662  4,990 


Projected benefit obligation at end of year  $44,803 $38,141 


A reconciliation of the fair value of Plan assets as(as of October 1 of each yearthe September 30 measurement date) is as follows (in thousands):follows:

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 



2003
2002
(in thousands)

Beginning market value of plan assets
  $25,830 $32,938 
Benefits paid   (1,972) (1,955)
Investment income (loss)   6,406  (5,153)
Employer contributions   6,851  -- 


Ending market value of plan assets  $37,115 $25,830 


Funding information for the Plan is as follows:

2003
2002
(in thousands)

Fair value of plan assets
  $37,115 $25,830 
Projected benefit obligation   (44,803) (38,141)


Funded status   (7,688) (12,311)
Unrecognized:  
     Net loss   17,457  17,075 
     Prior service cost   1,088  1,253 


Net amount recognized  $10,857 $6,017 


Amounts recognized in statement of October 1 each year was as follows (in thousands):financial position consist of:

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 


2003
2002
(in thousands)

Net pension (liability) asset
  $10,857 $(6,370)
Intangible asset   -- ��1,326 
Accumulated other comprehensive loss   --  11,061 


Net amount recognized  $10,857 $6,017 


Accumulated benefit obligation  $36,577 $32,254 


25


The provisions of Statement of Financial Accounting StandardsSFAS No. 87 "Employers'“Employers’ Accounting for Pensions"Pensions” (SFAS 87) requiresrequired the Company to record a net pension asset of $10.9 million at December 31, 2003 and is included in the line item Other in Other assets on the accompanying Balance Sheets.

The provisions of SFAS No. 87 required 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 AssetsDeferred credits and other liabilities on the accompanying Consolidated Balance Sheet. Sheets.

Components of Net Periodic Pension Expense

2003
2002
2001
(in thousands)

Service cost
  $714 $588 $719 
Interest cost   2,500  2,406  2,565 
Expected return on assets   (2,473) (3,345) (4,928)
Amortization of prior service cost   165  184  199 
Recognized net actuarial (gain) loss   1,105  96  (453)



Net pension (income) expense  $2,011 $(71)$(1,898)



Additional Information

2003
2002
(in thousands)
Pre-tax amount included in other comprehensive      
   income (loss) arising from a change in the  
   additional minimum pension liability  $11,061 $(11,061)


Assumptions

Weighted-average assumptions used to determine
benefit obligations:
2003
2002

Discount rate
   6.00% 6.75%
Rate of increase in compensation levels   5.00% 5.00%


Weighted-average assumptions used to determine net
periodic benefit cost for plan year:
2003
2002
2001

Discount rate*
   6.75% 7.50% 7.50%
Expected long-term rate of return on assets**   10.00% 10.50% 10.50%
Rate of increase in compensation levels   5.00% 5.00% 5.00%

_________________

*The discount rate used for net periodic pension cost was changed from 6.75 percent in 2003 to 6.0 percent for the calculation of the 2004 net periodic pension cost. This change is expected to affect pension costs in 2004 by an increase of approximately $0.4 million.

**The expected rate of return on plan assets was changed from 10.0 percent in 2003 to 9.5 percent for the calculation of the 2004 net periodic pension cost. This change is expected to increase pension costs in 2004 by approximately $0.2 million.

26


The remaining amountPlan’s expected long-term rate of $11.1 millionreturn on assets assumption is recorded as a componentbased upon the weighted average expected long-term rate of stockholder's equity, net of related tax benefits of $4.0 million,returns for each individual asset class. The asset class weighting is determined using the target allocation for each asset class in the line item Accumulated other comprehensive lossPlan portfolio. The expected long-term rate of return for each asset class is determined primarily from long-term historical returns for the asset class, with adjustments if it is anticipated that long-term future returns will not achieve historical results.

The expected long-term rate of return for equity investments was 10.5 percent and 11.0 percent for the 2003 and 2002 plan years, respectively. For determining the expected long-term rate of return for equity assets, the Company reviewed annual 20-, 30-, 40-, and 50-year returns on the accompanying Consolidated Balance SheetS&P 500 Index, which were, at December 31, 2002, 12.5 percent, 10.5 percent, 10.3 percent and 10.9 percent respectively. Fund management fees were estimated to be 0.18 percent for S&P 500 Index assets and 0.45 percent for other assets. The expected long-term rate of return on fixed income investments was 6.0 percent; the return was based upon historical returns on intermediate-term treasury bonds of 6.3 percent from 1950 to 2002. The expected long-term rate of return on cash investments was estimated to be 4.0 percent; expected cash returns were estimated to be 2.0 percent below long-term returns on intermediate-term treasury bonds.

Plan Assets

Percentage of fair value of Plan assets at September 30:

 2003
 2002
 
Domestic equity   44.8% 63.0%
Foreign equity   26.6% 25.9%
Fixed income   3.8% 7.8%
Cash   24.8%(a) 3.3%


     Total   100.0% 100.0%


(a)

Allocation includes $6.9 million cash contribution made to the plan on September 30, 2003; the contribution is expected to be placed in noncash investments in the fiscal 2004 plan year.


The Plan’s investment policy includes a target asset allocation as follows:

Asset Class
Target Allocation
US Stock60% (with a variance of no more or less than 10% of target).
Foreign Stocks30% (with a variance of no more or less than 10% of target).
Fixed Income5% (with a variance of no more than 10% or no less than 5% of target).
Cash5% (with a variance of no more than 10% or no less than 5% of target).

The Plan’s investment policy includes the investment objective that the achieved long-term rate of return meet or exceed the assumed actuarial rate. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity-based assets. The policy provides that the Plan will maintain a passive core US Stock portfolio based on the S&P 500 Index. Complementing this core will be investments in US and foreign equities through actively managed mutual funds.

The policy contains certain prohibitions on transactions in separately managed portfolios in which the Plan may invest, including prohibitions on short sales and the use of options or futures contracts. With regards to pooled funds, the policy requires the evaluation of the appropriateness of such funds for managing Plan assets if a fund engages in such transactions. The Plan has historically not invested in funds engaging in such transactions.

Contributions

The Company made a contribution to the Plan of $6.9 million on September 30, 2003. The Company does not anticipate that a contribution will be made to the Plan in the 2004 fiscal year.

27


Supplemental Nonqualified Defined Benefit Retirement PlanPlans

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 underThe Company uses a September 30 measurement date for the plans were $0.2 million in 2002Plans.

Obligations and $0.4 million in 2001 and 2000, respectively.Funded Status

The following table summarizes the projected benefit obligation and 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 
2003
2002
(in thousands)
Change in benefit obligation:      
     Projected benefit obligation at beginning of year  $1,676 $1,282 


     Service cost   6  22 
     Interest cost   109  116 
     Actuarial losses   197  358 
     Benefits paid   (102) (102)


       Net increase   210  394 


     Projected benefit obligation at end of year  $1,886 $1,676 


Fair value of plan assets at end of year  
Funded status  $(1,886)$(1,676)
Unrecognized net loss   824  670 
Unrecognized prior service cost   4  1 
Contributions   25  25 


Net amount recognized  $(1,033)$(980)




2003
2002
(in thousands)
Amounts recognized in statement of financial position consist of:      
     Net pension (liability)  $(1,613)$(1,388)
     Intangible asset   4  1 
     Contributions   25  25 
     Accumulated other comprehensive loss   551  382 


Net amount recognized  $(1,033)$(980)


Accumulated benefit obligation  $1,615 $1,445 


The provisions of SFAS 87 required the Company to record an additional minimumaccrued pension liability of $0.4$1.6 million and $1.4 million at December 31, 2002. This amount2003 and 2002, and is included in AccruedDeferred credits and other liabilities, Other on the accompanying Consolidated Balance Sheet. This liability representsSheets.

Components of Net Periodic Benefit Cost

2003
2002
2001
(in thousands)

Service cost
  $6 $22 $60 
Interest cost   109  116  242 
Prior service cost   (3) (2) 28 
(Gain) loss   42  42  35 



Net periodic benefit cost  $154 $178 $365 



28


Additional Information

2003
2002
(in thousands)
Pre-tax amount included in other comprehensive      
  income (loss) arising from a change in the  
  additional minimum pension liability  $(169)$(382)


Assumptions

Weighted-average assumptions used to determine
benefit obligations at September 30
2003
2002

Discount rate
   6.00% 6.75%
Rate of increase in compensation levels   5.00% 5.00%


Weighted-average assumptions used to determine net
periodic benefit cost for plan year
2003
2002
2001

Discount rate*
   6.75% 7.50% 7.50%
Rate of increase in compensation levels   5.00% 5.00% 5.00%

_________________

*The discount rate used for net periodic benefit cost was changed from 6.75 percent in 2003 to 6.0 percent for the calculation of the 2004 net periodic benefit cost. This change will not materially affect benefit costs in 2004.

Plan Assets

The plan has no assets. The Company funds on a cash basis as benefits are paid.

Contributions

The Company anticipates that contributions to the amount by whichplan for the accumulated benefit obligation exceedsnext fiscal year will be approximately $0.1 million; 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,contributions are expected to be in the line item Accumulated other comprehensive loss on the accompanying Consolidated Balance Sheet at December 31, 2002.form of benefit payments.


Non-pension Defined Benefit Postretirement Plan

Employees who are participants in the Company’s Postretirement Healthcare 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. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. The Company may amend or change the Plan periodically. The Company is not pre-funding its retiree medical plan. The Company uses a September 30 measurement date for the Plan.

These financial statements and this Note do not reflect the effects of the 2003 Medicare Act on the postretirement benefit plan.

29


Obligation and Funded Status

2003
2002
(in thousands)

Change in benefit obligation:
      
Accumulated postretirement benefit obligation at beginning of year  $6,547 $7,275 


Service cost   198  160 
Interest cost   435  402 
Plan participant's contributions   319  337 
Amendments   --  (284)
Benefits paid and actual expenses   (480) (483)
Net transfer in/out   --  (433)
Actuarial (gains) losses   1,178  (427)


     Net increase   1,650  (728)


Accumulated postretirement benefit obligation at end of year  $8,197 $6,547 


Fair value of plan assets at end of year  
Funded status  $(8,197)$(6,547)
Unrecognized net loss   2,930  1,830 
Unrecognized prior service cost   (246) (265)
Unrecognized transition obligation   1,050  1,167 
Contributions   42  51 


Net amount recognized  $(4,421)$(3,764)


Amounts recognized in statement of financial position consist of:

 2003
 2002
 
(in thousands)
Accrued postretirement (liability)  $(4,421)$(3,764)


Components of Net Periodic Benefit Cost

2003
2002
2001
(in thousands)

Service cost
  $198 $160 $208 
Interest cost   435  402  414 
Amortization of transition obligation   117  117  124 
Amortization of prior service cost   (19) (19) -- 
Loss   78  34  22 



Net periodic benefit cost  $809 $694 $768 



30


Assumptions

Weighted-average assumptions used to determine
benefit obligations at September 30

2003
2002
Discount rate   6.00% 6.75%


Weighted-average assumptions used to determine net
periodic benefit cost for plan year

2003
2002
2001
Discount rate*   6.75% 7.50% 7.50%

_________________

*The discount rate used for net periodic benefit cost was changed from 6.75 percent in 2003 to 6.0 percent for the calculation of the 2004 net periodic benefit cost. This change is expected to affect benefit costs in 2004 by an increase of approximately $0.1 million.

The net periodic postretirement cost was as 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 (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, a 12.0 percent annual rate of increase in healthcare benefits was assumed for 2002; the rate was assumed to decrease gradually to 5 percent in 2009 and remain at that level thereafter. The healthcare cost trend rate assumption hasfor the 2003 fiscal year expense was 11 percent for fiscal 2003 grading down 1 percent per year until a significant effect on the amounts reported. 5 percent ultimate trend rate is reached in fiscal year 2009. The health care trend rate assumption for 2003 fiscal year disclosure and 2004 fiscal year expense is 12 percent for fiscal 2004 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2011.

A one1 percent increase in the healthcare cost trend assumption would increase the service and interest cost $0.1 million or 19.521 percent and the netaccumulated periodic postretirement costbenefit obligation $1.1 million or 17.014 percent. A one1 percent decrease would reduce the service and interest cost by $0.1 million or 16.016 percent and decrease the netaccumulated periodic postretirement costbenefit obligation $0.9 million or 13.611 percent.

Plan Assets

The weighted-average discount rate usedplan has no assets. The Company funds on a cash basis as benefits are paid.

Contributions

The Company anticipates that contributions to the plan for the next fiscal year will be approximately $0.5 million in determining the accumulated postretirement benefit obligation was 6.75 percent for 2002form of benefits and 7.5 percent for 2001.administrative costs paid.

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), theThe Company provides a matching contribution of 100 percent of the employee’s tax-deferred contribution up to a maximum 3 percent of the employee’s eligible compensation. Matching contributions vest at 20 percent per year and are fully vested when the participant has 5 years of service with the Company. The Company’s matching contributions totaled $0.4 million for 2003,$0.4 million for 2002 and $0.6 million for 2001 and $0.3 million for 2000.2001.

31


(13)(8)           OTHER COMPREHENSIVE LOSSINCOME (LOSS)

The following tables display the related tax effects allocated to each component of Other Comprehensive LossIncome (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.


2003
Pre-tax Amount
Tax Benefit
Net-of-tax Amount
Minimum pension liability adjustment  $10,892 $(3,813)$7,079 
Net change in fair value of derivatives designated as cash flow hedges  
  associated with discontinued operations   672  (269) 403 
Amortization of cash flow hedges settled and deferred in accumulated  
  other comprehensive loss and reclassified into interest expense   64  (22) 42 



Other comprehensive income  $11,628 $(4,104)$7,524 




2002
Pre-tax
Amount

Tax Benefit
Net-of-tax
Amount

Net change in fair value of derivatives designated as cash flow hedges,        
  including some of which have been classified into discontinued  
  operations  $(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        
  associated with discontinued operations  $(7,540)$3,016 $(4,524)



(14)(9)           INCOME TAXES

Income tax expense (benefit) for the years ended December 31 was (in thousands):

2002
 2001
 2000
 
2003
2002
2001
Current  $(1,318)$19,495 $21,290   $3,550 $10,826 $23,680 
Deferred  22,993  4,522  1,293   8,072  4,241  575 






 $21,675 $24,017 $22,583  $11,622 $15,067 $24,255 






32


The temporary differences which gave rise to the net deferred tax liability were 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 



Years ended December 31,2003
2002

Deferred tax assets, current:
      
   Valuation reserve  $314 $309 
   Employee benefits   2,623  2,375 
   Items of other comprehensive income   --  4,028 
   Other   624  791 


    3,561  7,503 


Deferred tax liabilities, current:  
   Employee benefits   3,800  2,106 


    3,800  2,106 


Net deferred tax (liability) asset, current  $(239)$5,397 


Deferred tax assets, non-current:  
   Regulatory asset  $1,156 $1,295 
   ITC   460  571 
   Items of other comprehensive income   806  612 
   Other   789  632 


    3,211  3,110 


Deferred tax liabilities, non-current:  
   Accelerated depreciation and other plant related differences   63,615  56,284 
   AFUDC   2,808  2,828 
   Regulatory liability   1,512  1,523 
   Other   909  1,014 


    68,844  61,649 


     Net deferred tax liability, non-current  $65,633 $58,539 


     Net deferred tax liability  $65,872 $53,142 


The following table reconciles the change in the net deferred income tax liability from December 31, 2001,2002, to December 31, 2002,2003, to deferred income tax expense:

2002 2003
(in thousands) (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)

Increase in deferred income tax liability from the preceding table
  $12,730 
Deferred taxes associated with ITC  (716)
Deferred taxes associated with other comprehensive loss  7,675   (3,834)
Other  (238)  (108)


Deferred income tax expense for the period $22,993  $8,072 


33


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

2002
 2001
 2000
 
2003
2002
2001
Federal statutory rate   35.0% 35.0% 35.0%   35.0% 35.0% 35.0%
Amortization of excess deferred and investment tax credits  (1.0) (1.0) (1.0)  (1.3) (1.3) (0.7)
Research and development credit  (1.8) --  --   (0.1) --  -- 
Other  2.8  1.7  1.9   (1.1) (0.4) 0.6 






  35.0% 35.7% 35.9%  32.5% 33.3% 34.9%






(10)           NON-CASH DIVIDEND AND DISCONTINUED OPERATIONS

At DecemberDuring the quarter ended March 31, 2002,2003, the Company had net operating loss carryforwardsdistributed a non-cash dividend to its parent company, Black Hills Corporation (Parent). The dividend consisted of $2.8 million10,000 common shares of Black Hills Generation, Inc., formerly known as Black Hills Energy Capital, Inc., (Generation), which expire in the year 2020 and $1.1 million which expire in the year 2022.

(15) BUSINESS SEGMENTS

The Company’s reportable segments are those that are based on the Company’s method of internal reporting, which generally segregates the strategic business groups due to differences in products, services and regulation. As of December 31, 2002, substantially all of the Company’s operations and assets are located within the United States. The Company’s operations are conducted through two business groups: Electric, which supplies electric utility service to western South Dakota, northeastern Wyoming and southeastern Montana; and Independent Power, which produces and sells power and capacity to wholesale 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 the Pepperell Facility (Pepperell), a 40 megawatt gas-fired plant located in Pepperell, Massachusetts. These transactions give the Company arepresents 100 percent ownership interestof Generation. The Company therefore no longer operates in Harborthe independent power production business. As a result, the Company no longer has any subsidiaries and Pepperell and were funded by borrowings from affiliates.

operates only in the electric utility business. The Company’s investment in Generation at the above entity prior totime of the above acquisitiondistribution was $46.5 million.

The disposition was accounted for under the equity methodprovisions of accountingSFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144). Accordingly, results of operations have been classified as “Discontinued operations, net of income taxes” in the accompanying Statements of Income, and wasprior periods have been restated. For business segment reporting purposes, Generation’s business results were previously included in Investmentsthe segment “Independent Power Production”. The assets and liabilities of Generation are shown in the accompanying Balance Sheets under the captions “Assets from discontinued operations” and “Liabilities from discontinued operations.”

Revenues and net income from the discontinued operations are as follows:

2003
2002
2001
(in thousands)

Revenue
  $41,485 $125,267 $73,750 



Income (loss) before income taxes and change  
  in accounting principle  $2,833 $16,674 $(2,202)
Income tax (expense) benefit   (927) (6,608) 238 
Change in accounting principle, net of tax   --  896  -- 



Net income (loss) from discontinued operations  $1,906 $10,962 $(1,964)



34


Assets and liabilities of discontinued operations included on the accompanying Consolidated Balance Sheets.Sheet are as follows (in thousands):

December 31
2002

Current assets  $77,213 
Property, plant and equipment   801,910 
Goodwill   30,562 
Intangible assets, net   77,661 
Other non-current assets   21,555 
Notes payable   (50,000)
Due to affiliate   (455,498)
Current derivative liability   (9,345)
Other current liabilities   (40,257)
Non-current derivative liability   (7,844)
Long-term debt, net of current maturities   (345,153)
Other non-current liabilities   (56,662)

Net assets of discontinued operations (including     
  accumulated other comprehensive loss of $9,440)  $44,142 

During the quarter ended March 31, 2001, we distributed a non-cash dividend to our parent company. The above acquisition gavedividend 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 Company majoritycoal 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. Our investment in Wyodak at the time of the distribution was $89.6 million.

Revenues and voting control, therefore, after acquisitionnet income from the Company has consolidated the entity in its consolidated financial statements.discontinued operations are as follows:

2001*
(in thousands)

Revenue
  $197,274 

Income before income taxes  $7,849 
Income tax expense   (3,017)

Net income  $4,832 

_________________

*Includes only one month of operations

The above acquisition hasfinancial statements and notes to financial statements have been accountedrestated to reflect our continuing operations for all periods presented. The net operating results of discontinued operations are included in the Statements of Income under the purchase methodcaption “Discontinued operations, net 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.income taxes.”

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 $150 million (excluding goodwill and other intangibles) and liabilities assumed of approximately $2 million. The purchase price and related acquisition costs exceeded the fair values assigned to net tangible assets by approximately $42 million, which was recorded as long-lived intangible assets and goodwill.

On April 11, 2001, BHEC purchased the Fountain Valley facility, a 240 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 project was approximately $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 assumes 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 consolidated majority-owned subsidiaries, Black Hills North American Power Fund, L.P. and Indeck North American Power Partners, L.P., respectively, from minority shareholders. Total consideration paid was $15.9 million.

Pro forma financial amounts reflecting the effects of the above acquisitions are not presented as such acquisitions were not significant to the Company’s results of operations.35


(17)(11)           QUARTERLY HISTORICAL DATA (Unaudited)

The Company operates on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter of 20022003 and 2001.2002.

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

On 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. This dividend will be paid to the Parent on March 31, 2003. With the completion of this restructuring, the Company’s business will consist solely of the electric utility operations.

First
Quarter

Second Quarter
Third
Quarter

Fourth
Quarter

(in thousands)
2003:          
     Operating revenues  $43,762 $39,207 $46,268 $41,782 
     Operating income   13,652  10,597  14,495  12,355 
     Income from continuing operations   6,699  4,722  6,772  5,896 
     Net income   8,605  4,722  6,772  5,896 

2002:
  
     Operating revenues  $37,192 $38,303 $45,291 $41,400 
     Operating income   14,327  13,353  15,975  14,505 
     Income from continuing operations   7,823  6,792  8,304  7,298 
     Net income   11,984  9,131  11,013  9,051 

ITEM 9.            CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
                           ACCOUNTING ANDFINANCIAL
AND FINANCIAL 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.None.

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 14.9A.            CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

Within 90 days prior to the filing date of the Form 10-K, our chief executive officerOur Chief Executive Officer and chief financial officerChief Financial Officer evaluated the effectiveness of our disclosure controls and procedures as(as defined in Rules 13a-14(c)13a-15(e) and 15d-14(c)15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act).) as of December 31, 2003. 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 includedrequired to be disclosed 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 chiefcontrol over financial officerreporting

During our fourth fiscal quarter, there have concluded that there werebeen no significant changes in our internal controlscontrol over financial reporting that have materially affected or in other factors that could significantlyare reasonably likely to materially affect these controls subsequent to the date of their most recent evaluation of such controls, and that there were no significant deficiencies or material weaknesses in our internal controls.control over financial reporting.

36


PART IV

INDEPENDENT AUDITORS’ REPORT

To the Shareholder of
Black Hills Power, Inc.
Rapid City, South Dakota

We have audited the consolidated financial statements of Black Hills Power, Inc. and subsidiaries (the Company) as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003, and have issued our report thereon dated March 10, 2004, which report expresses an unqualified opinion. Such financial statements and report are included elsewhere in this 2003 Annual Report on Form 10-K. Our audits also included the financial statement schedule of Black Hills Power, Inc., listed in Item 15(a)(2). This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. 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.

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota
March 10, 2004

ITEM 15.            EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)     1.   Consolidated Financial Statements

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

                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, 2003, 2002 2001 and 2000.2001.

 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, 2003, 2002 2001 AND 20002001

Additions

Description


Balance at
beginning of year


Charged to costs
and expenses


Deductions


Balance at
end of year

(In thousands)
Allowance for
doubtful accounts:
2003  $882 $201 $(185)$898 
2002   868  189  (175) 882 
2001   428  627  (187) 868 

Additions37

        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'sCorporation’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 the 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*10.2* 

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*10.3* 

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*10.4* 

Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).


10.6*31.1   Purchase and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc. dated June 18, 2001

Certification pursuant to purchase Southwest Power, LLC.Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


99.131.2   

Certification Pursuantpursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


32.1  

Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuantadopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


99.232.2   

Certification Pursuantpursuant to 18 U.S.C. Section 1350, as Adopted Pursuantadopted 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.

_________________

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

(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.

38


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: By/S/ DANIEL P. LANDGUTH /S/ DAVID R. EMERY
Daniel P. Landguth, ChairmanDavid R. Emery, President
and Chief Executive Officer

Dated: March 31, 200325, 2004

        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.


  /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./S/ DAVID R. EMERY 

I have reviewed this annual report on Form 10-K of Black Hills Power, Inc.;


2.Director and 

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.March 25, 2004 

Based on my knowledge, the financial statements,

David R. Emery, President 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:


Principal Executive Officer   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;Chief Executive Officer

   b)

/S/ MARK T. THIES
 evaluated the effectiveness of the registrant’s disclosure controlsPrincipal Financial and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”);March 25, 2004
Mark T. Thies, Executive Vice President and

Accounting Officer   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. Chief Financial Officer

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)

/S/ DANIEL P. LANDGUTH
 any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls;Director and

6. Officer 

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.March 25, 2004 

I have reviewed this annual report on Form 10-K of Black Hills Power, Inc.;


2.Daniel P. Landguth, Chairman

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)

/S/ BRUCE B. BRUNDAGE
 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”); andDirectorMarch 25, 2004

Bruce B. Brundage   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)

/S/ DAVID C. EBERTZ
 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; andDirectorMarch 25, 2004

David C. Ebertz   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


/S/ JOHN R. HOWARD
DirectorMarch 25, 2004
John R. Howard

/S/ EVERETT E. HOYT
Director 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.

Officer
March 25, 2004
Everett E. Hoyt, Chief Operating Officer

/S/ KAY S. JORGENSEN
DirectorMarch 25, 2004
Kay S. Jorgensen

/S/ RICHARD KORPAN
DirectorMarch 25, 2004
Richard Korpan

/S/ STEPHEN D. NEWLIN
DirectorMarch 25, 2004
Stephen D. Newlin

/S/ THOMAS J. ZELLER
DirectorMarch 25, 2004
Thomas J. Zeller

Date: March 31, 2003

/s/ Mark T. Thies      

Senior Vice President and
Chief Financial Officer39


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'sCorporation’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 the 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*10.2* 

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*10.3* 

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*10.4* 

Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant's Form 10-K for 1999).


10.6*31.1   Purchase and Sale Agreement by and between TLS Investors, LLC and Black Hills Energy Capital, Inc. dated June 18, 2001

Certification pursuant to purchase Southwest Power, LLC.Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


99.131.2   

Certification Pursuantpursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.


32.1  

Certification pursuant to 18 U.S.C. Section 1350, as Adopted Pursuantadopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


99.232.2   

Certification Pursuantpursuant to 18 U.S.C. Section 1350, as Adopted Pursuantadopted 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.

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

40