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

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

          For the fiscal year ended December 31, 2003

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

          For the transition period from ___________________ to __________________

          Commission File Number 1-7978

BLACK HILLS POWER, INC.

Incorporated in South Dakota                       IRS Identification Number 46-0111677

625 Ninth Street
Rapid City, South Dakota 57701

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

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

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

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

YES      X                 NO ______

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

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

YES                        NO      X    

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

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

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.

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TABLE OF CONTENTS

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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.

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.

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 61,000 electric customers, with an electric transmission system of 447 miles of high voltage lines and 513 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:

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Power Sales Agreements

We sell approximately 47 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, our 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, we have been a net producer of energy. We reached our 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.

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Rate Regulation

Existing 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 adjustment tariff which would take effect during the freeze period. The specified extraordinary events are:

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

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 customers to aggregate their loads. This tariff also provides us with a five-year right to continue to serve those customers in the event of deregulation. Our “meet or release” contracts currently total more than 108 megawatts 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.

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

Our issuer credit rating was recently downgraded to “Baa2” by Moody’s Investor Services, Inc., or Moody’s 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 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 may impair our ability to raise capital and limit our growth.

Continuing conflict in the Middle East or further tensions with the government of North Korea could 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.

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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 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.

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:

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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 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.

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.

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:

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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 selling 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

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” subcaption within Item 8, Note 6, “Commitments and Contingencies”, of our Notes to Financial Statements in this Annual report on 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'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

In 2003, we made a non-cash dividend to our parent company, Black Hills Corporation, consisting of our 100 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 operate only in the electric utility business.

Results of Operations

The following table provides certain electric utility operating statistics:

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 50 megawatts under a long-term agreement.

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2003 Compared to 2002

Electric revenue increased 5 percent in 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 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 1 percent above normal in 2002 and 4 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, 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 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 in August 2002.

In addition, 2001 earnings included a $2.0 million after-tax charge related to the formation of the Black Hills Corporation Foundation.

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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 the risk factors described in Item 1 of this Form 10-K and the following:

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.

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ITEM 8.           CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

INDEPENDENT AUDITORS' REPORT

To the Shareholder 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, 2003 and 2002, and the related consolidated statements of income, common stockholder's equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements 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, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Minneapolis, Minnesota,
March 10, 2004

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BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF INCOME

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

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BLACK HILLS POWER, INC.
CONSOLIDATED BALANCE SHEETS

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

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BLACK HILLS POWER, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

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

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

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

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

(1)            BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. (the Company) is an electric utility serving customers in South Dakota, Wyoming and 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, long-lived asset values and useful lives, employee benefits plans and contingencies. Actual results could differ from those estimates.

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).

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 — $1.1 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.

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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 cost 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

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 percent and 10.2 percent during 2003, 2002 and 2001, respectively. The amount of AFUDC was approximately $0.1 million, $0.9 million, and $0.7 million in 2003, 2002 and 2001, respectively. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. 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.

Impairment of Long-Lived 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 or 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 federal income tax return with other affiliates. For financial statement purposes, 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.

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Reclassifications

In 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 amounts in the financial statements have been reclassified to conform to the 2003 presentation. These reclassifications had no effect on the Company’s common stockholders’ equity or results of operations, as previously reported.

Recently Adopted Accounting Pronouncements

SFAS 132-R

In December 2003, the FASB issued SFAS No. 132 (Revised), “Employer’s Disclosure about Pensions and Other Postretirement Benefits” (SFAS 132-R). SFAS 132-R retains disclosure requirements of the original SFAS 132 and requires additional 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 15, 2004. Interim period disclosures are effective for interim periods beginning after December 15, 2003. The adoption of the disclosure provisions of SFAS 132-R did not have an effect on the Company’s Financial Statements (see Note 7).

SFAS 143

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 provides accounting and disclosure requirements for retirement obligations associated with long-lived assets and was effective January 1, 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 effect on the Company’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 of Not 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.

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Recently Issued Accounting Pronouncements

FSP 106-1

In January 2004, the FASB issued FASB Staff Position (FSP) No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-1), which permits a sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer accounting for the effects 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 authoritative guidance, when issued, to determine if its benefit plans need to be amended and how to record the effects of the 2003 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 following (in thousands):

Regulated

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(3)           LONG-TERM DEBT

Long-term debt outstanding at December 31, is as follows:

Substantially all of the Company’s 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.

Scheduled maturities are approximately $2.0 million a year for the years 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.

(4)           FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of the Company’s financial instruments at December 31, are as follows (in thousands):

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.

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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.

(5)           JOINTLY OWNED FACILITIES

The Company owns a 20 percent interest and PacifiCorp owns an 80 percent interest in the Wyodak Plant (Plant), a 362 megawatt coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp 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, 2003, the Company’s investment in the Plant included $72.2 million in electric plant and $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 and $5.9 million for the years ended December 31, 2003, 2002 and 2001, respectively, and is included in the corresponding categories of operating expenses in the accompanying 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.

(6)           COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreement — 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 50 megawatts in 2007-2023. Costs incurred under this agreement were $0.5 million in 2003 and $0.7 million in each of 2002 and 2001.

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Long-Term Power Sales Agreements

Legal Proceedings

Forest Fire Claims

In September 2001, a fire occurred in the southwestern Black 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 Complaint seeks recovery of damages for alleged fire suppression and rehabilitation costs. A claim for treble damages is asserted with respect to the claim for injury to timber. A substantially similar suit was filed against the Company by the United States Forest Service, on June 30, 2003, in the United States District Court for the District of South Dakota, Western Division. The State 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, and the 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.

On June 29, 2002, a forest fire began near Deadwood, South Dakota, now known as the “Grizzly Gulch Fire.” Before being contained more than eight days later, the fire consumed over 10,000 acres of public and private land, mostly consisting of rugged forested areas. The fire destroyed approximately 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 Complaint seeks recovery of damages for alleged injury to timber, fire suppression and rehabilitation costs. A claim for treble damages was asserted with respect to the claim for injury to timber.

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’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 state 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 habitat and aesthetics or for assistance to private landowners.

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The Company is completing its own investigation of the fire cause and origin. The Company’s investigation is continuing, but based upon information currently available, the Company filed its Answer to the 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 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 or the viability of potential claims with respect to either fire, based on the information available, management believes that any such claims, if determined adversely to the Company, will not have a material adverse effect on the Company’s financial condition or results of operations.

PPM Energy, Inc. Demand for Arbitration

On January 2, 2004, PPM Energy, Inc. delivered its Demand for Arbitration to the 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 cause 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 an 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 operations. In the opinion of management, the amount of liability, if any, with respect to these actions would not materially affect the financial position or results of operations of the Company.

(7)           EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

The Company has a noncontributory defined benefit pension plan (Plan) covering the employees 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. The Company uses a September 30 measurement date for the Plan.

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Obligations and Funded Status

Change in benefit obligation:

A reconciliation of the fair value of Plan assets (as of the September 30 measurement date) is as follows:

Funding information for the Plan is as follows:

Amounts recognized in statement of financial position consist of:

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The provisions of SFAS No. 87 “Employers’ Accounting for Pensions” (SFAS 87) required 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 the line item Other in Deferred credits and other liabilities on the accompanying Balance Sheets.

Components of Net Periodic Pension Expense

Additional Information

Assumptions

_________________

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The Plan’s expected long-term rate of return on assets assumption is based upon the weighted average expected long-term rate of returns for each individual asset class. The asset class weighting is determined using the target allocation for each asset class in the Plan 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 S&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:

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

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.

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Supplemental Nonqualified Defined Benefit Retirement Plans

The Company has various supplemental retirement plans for outside directors and key executives of the Company. The plans are nonqualified defined benefit plans. The Company uses a September 30 measurement date for the Plans.

Obligations and Funded Status

The provisions of SFAS 87 required the Company to record an accrued pension liability of $1.6 million and $1.4 million at December 31, 2003 and 2002, and is included in Deferred credits and other liabilities, Other on the accompanying Balance Sheets.

Components of Net Periodic Benefit Cost