Black Hills Power 10-K 2008 FY Annual report

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, 2008
o	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 if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes o No x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes x No o

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 o

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

This paragraph is not applicable to the Registrant. x

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated filer o Accelerated filer o Non-accelerated filer x Smaller reporting company o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

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

All outstanding shares are held by the Registrant’s 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.

Class	Outstanding at February 28, 2009
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.

TABLE OF CONTENTS
		Page
	GLOSSARY OF TERMS	3
ITEMS 1. and 2.	BUSINESS AND PROPERTIES	5
	Safe Harbor for Forward Looking Information	5
	General	7
	Regulations	9
ITEM 1A.	RISK FACTORS	10
ITEM 1B.	UNRESOLVED STAFF COMMENTS	17
ITEM 3.	LEGAL PROCEEDINGS	17
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY AND
	RELATED STOCKHOLDER MATTERS	17
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS
	OF OPERATIONS	17
ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	21
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
	ON ACCOUNTING AND FINANCIAL DISCLOSURE	51
ITEM 9A.	CONTROLS AND PROCEDURES	51
ITEM 9B.	OTHER INFORMATION	51
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	52
	SIGNATURES	54
	INDEX TO EXHIBITS	55

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GLOSSARY OF TERMS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation
Black Hills Non-	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of
regulated Holdings	the Parent Company, that was formerly known as Black Hills Energy, Inc.
Black Hills Utility	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of the Parent
Holdings	Company
Black Hills Wyoming	Black Hills Wyoming, Inc., an indirect, wholly-owned subsidiary of Black
	Hills Electric Generation, Inc.
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary
	of the Parent Company
Colorado Electric	Black Hills Colorado Electric Utility Company, LP, (doing business as
	Black Hills Energy), an indirect, wholly-owned subsidiary of
	Black Hills Utility Holdings, formed to hold the Colorado electric
	utility properties acquired from Aquila
EPA 2005	Energy Policy Act of 2005
Enserco	Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-regulated
	Holdings, LLC
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes –
	an Interpretation of FASB Statement 109”
FSP	FASB Staff Position
FSP FAS 132(R)-1	FSP FAS 132(R)-1, “Employers’ Disclosure about Postretirement Benefit Plan
	Assets”
GAAP	Accounting principles generally accepted in the United States of America
LIBOR	London Interbank Offered Rate
MAPP	Mid-Continent Area Power Pool
MDU	Montana Dakota Utilities Company
MEAN	Municipal Energy Agency of Nebraska
Moody’s	Moody’s Investor Services, Inc.
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
PUHCA	Public Utility Holding Company Act of 1935
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 71	SFAS 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS 133	SFAS 133, “Accounting for Derivative Instruments and Hedging Activities”
SFAS 141(R)	SFAS 141(R), “Business Combinations”

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SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS 158	SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other
	Postretirement Plans, an Amendment of FASB Statements No. 87, 88, 106
	and 132(R)”
SFAS 159	SFAS 159, “The Fair Value Option for Financial Assets and Financial
	Liabilities”
SFAS 160	SFAS 160, “Non-controlling Interest in Consolidated Financial Statements
	– an Amendment of ARB No. 51”
SFAS 161	SFAS 161, “Disclosures about Derivative Instruments and Hedging Activities
	– an Amendment of FASB Statement No. 133”
S&P	Standard & Poor’s Rating Services
WECC	Western Electricity Coordinating Council
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corporation, a direct, wholly-owned
	subsidiary of Black Hills Non-regulated Holdings, LLC

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PART I

ITEMS 1
and 2.	BUSINESS AND PROPERTIES

Safe Harbor for Forward Looking Information

This Annual Report on Form 10-K includes “forward-looking statements” as defined by the 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, without limitation, the Risk Factors set forth in Item 1A. of this Form 10-K and the following:

•     Our ability to obtain adequate cost recovery for our electric utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel and purchased power and our ability to add power generation assets into regulatory rate base;

•     Our ability to successfully maintain or improve our corporate credit rating;

•     Our ability to complete the expected sale to MDU of a minority interest in our Wygen III project under construction;

•     Our ability to obtain from utility commissions any requisite determination of prudency to support resource planning and development programs we propose to implement;

•     The timing and extent of scheduled and unscheduled outages;

•     The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

•     Changes in business and financial reporting practices arising from the enactment of the EPA 2005 and subsequent rules and regulations promulgated thereunder;

•     Our ability to complete the permitting, construction, start-up and operation of power generating facilities in a cost-effective and timely manner;

•     Our ability to remedy any deficiencies that may be identified in the review of our internal controls;

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•     The timing, volatility and extent of changes in energy-related and commodity prices, interest rates, energy and commodity supply or volume, the cost and availability of transportation of commodities, and demand for our services, all of which can affect our earnings, liquidity position and the underlying value of our assets;

•     Our ability to effectively use derivative financial instruments to hedge commodity risks;

•     Our ability to minimize defaults on amounts due from customers and counterparty transactions;

•     Our ability to comply, or to make expenditures required to comply with changes in laws and regulations, particularly those relating to taxation, safety and protection of the environment and to recover those expenditures in customer rates, where applicable;

•     Liabilities of environmental conditions, including remediation and reclamation obligations under environmental laws;

•     Our ability to recover our borrowing costs, in our customer rates;

•     Weather and other natural phenomena;

•     Macro- and micro-economic changes in the economy and energy industry, including the impact of (i) consolidations and changes in competition, (ii) changing conditions in the credit markets, and (iii) general economic and political conditions, including tax rates or policies and inflation rates;

•     The effect of accounting policies issued periodically by accounting standard-setting bodies;

•     The cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events;

•     The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements;

•     Capital market conditions, which may affect our ability to raise capital on favorable terms;

•     Price risk due to marketable securities held as investments in benefit plans; and

•     Other factors discussed from time to time in our other filings with the 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.

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General

We are a regulated electric utility serving customers in South Dakota, Wyoming and Montana. We are incorporated in South Dakota and began providing electric utility service in 1941. We are a wholly-owned subsidiary of the publicly traded Black Hills Corporation.

Unless the context otherwise requires, references in this Form 10-K to “the Company,” “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

Distribution and Transmission. Our distribution and transmission system serves approximately 66,000 electric customers, with an electric transmission system of 497 miles of high voltage lines (greater than 69 KV) and 2,834 miles of lower voltage lines. In addition, we jointly own 47 miles of high voltage lines with Basin Electric. Our service territory covers a 9,300 square mile area of western South Dakota, northeastern Wyoming and southeastern Montana with a strong and stable economic base. Approximately 91% of our retail electric revenues in 2008 were generated in South Dakota.

The following are characteristics of our distribution and transmission businesses:

•     We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2008 was comprised of 25% commercial, 20% residential, 11% contract wholesale, 27% wholesale off-system, 9% industrial and 8% municipal sales and other revenue. Approximately 80% of our large commercial and industrial customers are provided service under long-term contracts.

•     We are subject to regulation by the SDPUC, the WPSC and the MTPSC. In December 2006, we received an order from the SDPUC approving a 7.8% increase in retail rates and the addition of tariff provisions for automatic adjustments of rates for changes in energy, fuel and transmission costs effective January 1, 2007. The cost adjustments require us to absorb a portion of power cost increases, depending in part on earnings on certain short-term wholesale sales of electricity. Absent certain conditions, the order also restricts us from requesting an increase in base rates that would go into effect prior to January 1, 2010.

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•     We own 35% and Basin Electric owns 65% of a transmission tie that provides an interconnection between the Western and Eastern transmission grids, enabling access to both the WECC region in the West, and the MAPP region in the East. Our system is located in the WECC region. The total transfer capacity of the tie is 400 MW - 200 MW from West to East and 200 MW from East to West. This transmission tie allows us to buy and sell energy in the Eastern interconnection without having to isolate and physically reconnect load or generation between the two electrical transmission grids. The transmission tie accommodates scheduling transactions in both directions simultaneously. This transfer capability provides additional opportunity to sell our excess generation or to make economic purchases to serve our native load and our contract obligations, and to take advantage of the power price differentials between the two electric grids. Additionally, our system is capable of directly interconnecting up to 80 MW of generation or load to the Eastern transmission grid. Transmission constraints within the MAPP transmission system may limit the amount of capacity that may be directly interconnected to the Eastern system at any given time.

•     We have firm point-to-point transmission access to deliver up to 50 MW of power on PacifiCorp’s transmission system to wholesale customers in the Western region from 2007 through 2023.

•     We have firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming to serve our power sales contract with MDU through 2016, with the right to renew pursuant to the terms of PacifiCorp’s transmission tariff.

Power Sales Agreements. We sell a portion of our current load under long-term contracts. Our key contracts include:

•     An agreement under which we supply up to 74 MW of capacity and energy to MDU for the Sheridan, Wyoming electric service territory through the end of 2016. The sales to MDU have been integrated into our control area and are considered part of our firm native load. In accordance with the terms of the agreement, MDU has an option to participate in the ownership of the Wygen III plant that is currently being constructed. MDU has notified us of its intentions to exercise their option to participate in the Wygen III project and we expect to renegotiate the power sales agreement to reduce the energy and capacity supplied by us under the agreement;

•     An agreement with the City of Gillette, Wyoming, to provide the City its first 23 MW of capacity and energy annually. The sales to the City of Gillette have been integrated into our control area and are considered part of our firm native load. The agreement renews automatically and requires a seven year notice of termination. As of December 31, 2008, neither party to the agreement had given a notice of termination; and

•     An agreement under which we supply 20 MW of energy and capacity to MEAN under a contract that expires in 2013. This contract is unit-contingent based on the availability of our Neil Simpson II plant.

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Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide 434 MW of generating capacity, with the balance supplied under purchased power and capacity contracts. Approximately 50% of our capacity is coal-fired, 39% is oil- or gas-fired, and 11% is supplied under the following purchased power contracts:

•     A power purchase agreement expiring in 2023, involving the purchase by us of 50 MW of coal-fired baseload power;

•     A reserve capacity integration agreement expiring in 2012, which makes available to us 100 MW of reserve capacity in connection with the utilization of the Ben French Combustion Turbine units;

•     A 20-year power purchase agreement with Cheyenne Light expiring in 2028, under which we will purchase up to 20 MW of renewable energy through Cheyenne Light’s agreement with Happy Jack Wind Farms, LLC; and

•     A Generation Dispatch Agreement with Cheyenne Light that requires the Company to purchase all of Cheyenne Light’s excess energy.

Since 1995, we have been a net producer of energy. We reached our 2008 peak system load of 409 MW in August 2008 with an average system load of 255 for the year ended December 31, 2008. None of our generation is restricted by hours of operation, thereby providing us the ability to generate power to meet demand whenever necessary and economically feasible. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market, and through short-term sales contracts primarily in the WECC and MAPP regions. Our 294 MW of low-cost, coal-fired resources supports most of our native load requirements and positions us for these wholesale off-system sales.

Regulations

Rate Regulation

Rates for our retail electric service are subject to regulation by the SDPUC for customers in South Dakota, the WPSC for customers in Wyoming and the MTPSC for customers in Montana. Any changes in retail rates are subject to approval by the respective regulatory body. We have rate adjustment mechanisms in Montana and South Dakota which provide for pass-through of certain costs related to the purchase, production and/or transmission of electricity. We are also subject to the jurisdiction of FERC with respect to accounting practices and wholesale electricity sales. We have been granted market-based rate authority by the FERC and are not required to file cost-based tariffs for wholesale electric rates. Rates charged by us for use of our transmission system are subject to regulation by the FERC.

In South Dakota, we have three adjustment mechanisms: transmission, steam plant fuel and conditional energy cost adjustment. The transmission and steam plant fuel adjustment clauses will either pass along or give credits back to South Dakota customers based on actual costs incurred on a yearly basis. The conditional energy cost adjustment relates to purchased power and natural gas used to generate electricity. These costs are subject to $2.0 million and $1.0 million cost bands where we absorb the first $2.0 million of increased costs or retains the first $1.0 million in savings. Beyond these thresholds, costs or refunds begin to be passed on to South Dakota customers through annual calendar-year filings.

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Environmental Regulations

We are subject to federal, state and local laws and regulations with regard to air and water quality, waste disposal, federal health and safety regulations, and other environmental matters. We have incurred, and expect to incur, capital, operating and maintenance costs to comply with the operations of our plants. While the requirements are evolving, it is virtually certain that environmental requirements placed on the operations will continue to be more restrictive.

Regulatory Accounting

As it pertains to the accounting for our regulated utility operations, we follow SFAS 71 and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. If rate recovery 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.

New Accounting Pronouncements

See Note 1 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2008 or pending adoption.

ITEM 1A. RISK FACTORS

The following specific risk factors and other risk factors that we discuss in our periodic reports filed with the SEC 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.

We may not raise our retail rates without prior approval of the SDPUC, WPSC or the MTPSC. If we seek rate relief, we could experience delays, reduced or partial rate recovery, or disallowances in rate proceedings.

Because we are generally unable to increase our base rates without prior approval from the SDPUC, the WPSC, and the MTPSC, our returns could be threatened by plant outages, machinery failure, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause operating costs to increase and operating margins to decline. While we have cost pass-through mechanisms in place that allow recovery of increased costs related to fuel, purchased power, transmission and natural gas, there is no guarantee that all increases in these costs will be recovered. Additionally, our general operating costs and investments are subject to the review of the SDPUC, the WPSC and the MTPSC. These commissions could find certain costs or investments are not prudent and not recoverable in our rates, thus negatively affecting our revenues.

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The recent global financial crisis has made the credit markets less accessible and created a shortage of available credit. We may, therefore, be unable to obtain the financing needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities and proceeds of debt and equity offerings. Our ability and the ability of our Parent, to access the capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, changes in the federal or state regulatory environment affecting energy companies, volatility in commodity or electricity prices and general economic and market conditions.  

Recent financial distress within the global economy has caused significant disruption in the credit markets.  Among other things, long-term interest rates on debt securities have increased significantly and the volume of equity and debt security issuances has decreased.  Recent actions taken by the United States government, the Federal Reserve and other governmental and regulatory bodies may be insufficient to stabilize these markets.  The longer such conditions persist, the more significant the implications become for us, including the possibility that adequate capital may not be available (or available on reasonable commercial terms) for us to refinance indebtedness. Among other things, alternatives could include deferring portions of our planned capital expenditure program, selling assets or issuing equity. The failure to consummate refinancings, and any actions taken in lieu of such refinancings, could have a material adverse effect on our results of operations, cash flows and financial condition.

Regulatory commissions may refuse to approve some or all of the utility rate increases we have requested or may request in the future, or may determine that amounts passed through to customers were not prudently incurred and are, therefore, not recoverable.

Our regulated electricity operations are subject to cost-of-service regulation and earnings oversight. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the state public utility commissions will judge all of our costs, including our borrowing and debt service costs, to have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce a full recovery of our costs and the return on invested capital allowed by the applicable state public utility commission.

To some degree, we are permitted to recover certain costs (such as increased fuel and purchased power costs, as applicable) without having to file a rate case. To the extent we pass through such costs to ratepayers and a state public utility commission subsequently determines that such costs should not have been paid by ratepayers; we may be required to refund such costs to ratepayers. Any such costs not recovered through rates, or any such refund, could negatively affect our revenues, cash flows and results of operations.

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The recent global financial crisis has also increased our counterparty credit risk.

As a consequence of the global financial crisis, the creditworthiness of many of our contractual counterparties (particularly financial institutions) has deteriorated. As the creditworthiness of our counterparties deteriorates, we face increased exposure to counterparty credit default.

We have established guidelines, controls and limits to manage and mitigate credit risk. For our energy marketing, production and generation activities, we seek 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 parent company guarantees, prepayments, letters of credit and other security agreements. Although we aggressively monitor and evaluate changes in our counterparties’ credit status and adjust the credit limits based upon changes in the customer’s creditworthiness, our credit guidelines, controls and limits may not protect us from increasing counterparty credit risk under today’s stressed financial conditions. To the extent the financial crisis causes our credit exposure to contractual counterparties to increase materially, such increased exposure could have a material adverse effect on our results of operations, cash flows and financial condition.

National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows.

A prolonged recession may lead to an increase in late payments from retail and commercial utility customers, as well as our non-utility customers (including marketing counterparties). If late payments and uncollectible accounts increase, earnings and cash flows from our continuing operations may be reduced.

Our credit ratings could be lowered below investment grade 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 credit rating on our First Mortgage Bonds is “Baa1” by Moody’s and “BBB” by S&P. Any reduction in our ratings by Moody’s or S&P could adversely affect our ability to refinance or repay our existing debt and to complete new financings. In addition, a 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.

National and regional economic conditions may cause increased late payments and uncollectible accounts, which would reduce earnings and cash flows.

A prolonged recession may lead to an increase in late payments from retail and commercial utility customers. If late payments and uncollectible accounts increase, earnings and cash flows from our utilities may be reduced.

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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 facilities involve many risks, including:

•     The inability to obtain required governmental permits and approvals;

•     Contract restrictions upon the timing of scheduled outages;

•     Cost of supplying or securing replacement power during scheduled and unscheduled outages;

•     The unavailability or increased cost of equipment and labor supply;

•     Supply interruptions, work stoppages and labor disputes;

•     Capital and operating costs to comply with increasing stringent environmental laws and regulations;

•     Opposition by members of public or special-interest groups;

•     Weather interferences;

•     Unexpected engineering, environmental and geological problems; and

•     Unanticipated cost overruns.

The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses, or cause us to incur 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 timely or adequate to cover lost revenues, increased expenses or liquidated damage payments.

Because prices in the wholesale power markets are volatile, our revenues and expenses may fluctuate.

A portion of the variability of our net income in recent years has been attributable to wholesale electricity sales. The related power prices are influenced by many factors outside our control, including among other things, fuel prices, transmission constraints, supply and demand, weather, general economic conditions and the rules, regulations and actions of the system operators in those markets.

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

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Our operating results can be adversely affected by milder weather.

Our utility business is a seasonal business and weather patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating. Accordingly, our utility operations have historically generated less revenues and income when weather conditions are cooler in the summer and warmer in the winter. Unusually mild summers and winters therefore could have an adverse effect on our financial condition and results of operations.

Our business is subject to substantial governmental regulation and permitting requirements as well as environmental liabilities, including those we assumed in connection with certain acquisitions. We may be adversely affected if we fail to achieve or maintain compliance with existing or future regulations or requirements, or the potentially high cost of complying with such requirements or addressing environmental liabilities.

Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally must obtain and comply with a variety of licenses, permits and other approvals in order to operate, which could require significant capital expenditures and operating 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; claims for property damage or personal injury; or environmental clean-up costs. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities, which could require additional unexpected expenditures and have a detrimental effect on our business.

We strive to comply with all applicable environmental laws and regulations. Future steps to bring our facilities into compliance, if necessary, could be expensive, and could adversely affect our results of operation and financial condition. We expect our environmental compliance expenditures to be substantial in the future due to the continuing trends toward stricter standards, greater regulation, more extensive permitting requirements and an increase in the number of assets we operate.

Federal and state laws concerning climate change and air emissions, including emission reduction mandates and renewable energy portfolio standards, may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated fossil-fuel generating plants in South Dakota, Wyoming and Montana. We are constructing another fossil-fuel generating plant in Wyoming. Air emissions of our fossil-fuel generating plants are subject to federal, state and tribal regulation. Recent changes in federal and state laws governing air emissions from fossil-fuel generating plants will result in more stringent emission limitations. As the issue of climate change, particularly with respect to CO₂ emissions by fossil-fuel generating plants, receives increased attention, additional or more stringent emission limitations or other requirements could be imposed. These limitations or other requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by our non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.

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Montana has adopted mandatory renewable portfolio standards that require electric utilities to supply minimum percentage of the power delivered to customers from renewable resources (e.g. wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If these states increase their renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase (and could increase materially). Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material impact on our results of operations and financial condition.

Ongoing changes in the United States utility industry, including state and federal regulatory changes, a potential increase in the number or geographic scale 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:

•     The EPA 2005 and the repeal of the PUHCA;

•     Industry consolidation;

•     Consumer demands;

•     Transmission constraints;

•     Renewable resource supply requirements;

•     Technological advances; and

•     Greater availability of natural gas-fired power generation, and other factors.

The 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. 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, which could negatively affect our ability to expand our asset base.

In addition, the independent system operators who oversee many 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 generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

��

15

Governmental authorities may assess penalties on us if it is determined that we have not complied with environmental laws and regulations.

If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control, that failure may result in the assessment of civil or criminal penalties and fines against us. Recent lawsuits by the EPA and various states filed against others within industries in which we operate highlight the environmental risks faced by generating facilities, in general, and coal-fired generating facilities in particular.

Increased risks of regulatory penalties could negatively impact our business.

EPA 2005 increased FERC’s civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1.0 million per violation, per day. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations. If a serious violation did occur, and penalties were imposed by FERC, it could have a material adverse effect on our operations or our financial results.

Increasing costs associated with our defined benefit retirement plans may adversely affect our results of operations, financial position or liquidity.

We have defined benefit pension plans that cover a substantial portion of our employees. Assumptions related to future costs, return on investments, interest rates and other actuarial assumptions have a significant impact on our funding requirements related to these plans. These estimates and assumptions may change based on actual return on plan assets, changes in interest rates and any changes in governmental regulations. In addition, the Pension Protection Act of 2006 changed the minimum funding requirements for defined benefit pension plans beginning in 2008.

Increasing costs associated with health care plans may adversely affect our results of operations, financial position or liquidity.

The costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs related to health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our health care plans may adversely affect our results of operations, financial position or liquidity.

An effective system of internal control may not be maintained, leading to material weaknesses in internal control over financial reporting.

Section 404 of the Sarbanes-Oxley Act of 2002 requires management to make an assessment of the design and effectiveness of internal controls. During their assessment of these controls, management may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists.

16

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” subcaption within Item 8, Note 11, “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

	2008		2007		2006
	(in thousands)
Revenue	$	232,674	$	199,701	$	193,166
Fuel and purchased power		113,672		79,425		81,215
Gross margin		119,002		120,276		111,951
Operating expenses		80,366		72,762		71,949
Operating income	$	38,636	$	47,514	$	40,002
Net income	$	22,759	$	24,896	$	18,724

17

The following table provides certain electric utility operating statistics:

Electric Revenue
(in thousands)
			Percentage			Percentage
Customer Base	2008		Change	2007		Change	2006
Commercial	$	58,289	4%	$	55,991	13%	$	49,756
Residential		46,854	3		45,657	13		40,491
Industrial		21,432	(2)		21,974	6		20,694
Municipal sales		2,734	1		2,697	12		2,401
Total retail sales		129,309	2		126,319	11		113,342
Contract wholesale		26,643	6		25,240	2		24,705
Wholesale off-system		63,770	81		35,210	(17)		42,489
Total electric sales		219,722	18		186,769	3		180,536
Other revenue		12,952	—		12,932	2		12,630
Total revenue	$	232,674	17%	$	199,701	3%	$	193,166

Megawatt-Hours Sold
		Percentage		Percentage
Customer Base	2008	Change	2007	Change	2006
Commercial	699,734	1%	690,702	4%	667,220
Residential	524,413	1	518,148	4	499,152
Industrial	414,421	(5)	434,627	—	433,019
Municipal sales	34,368	(1)	34,661	5	32,961
Total retail sales	1,672,936	—	1,678,138	3	1,632,352
Contract wholesale	665,795	2	652,931	1	647,444
Wholesale off-system	1,074,398	58	678,581	(28)	942,045
Total electric sales	3,413,129	13%	3,009,650	(7)%	3,221,841

We established a new summer peak load of 430 MW in July 2007 and a new winter peak load of 407 MW in December 2008. We own 434 MW of electric utility generating capacity and purchase an additional 50 MW under a long-term agreement expiring in 2023.

	2008	2007	2006
Regulated power plant
fleet availability:
Coal-fired plants	93.5%	95.4%	93.5%
Other plants	89.2%	99.4%	98.6%
Total availability	91.6%	97.2%	95.7%

18

		Percentage		Percentage
Resources	2008	Change	2007	Change	2006
MWh generated:
Coal	1,731,838	(2)%	1,758,280	2%	1,729,636
Gas	61,801	(32)	90,618	67	54,299
	1,793,639	(3)	1,848,898	4	1,783,935
MWh purchased	1,703,088	33	1,279,005	(18)	1,553,024
Total resources	3,496,727	12%	3,127,903	(6)%	3,336,959

	2008	2007	2006
Heating and cooling degree days:
Actual
Heating degree days	7,676	6,627	6,472
Cooling degree days	482	1,033	931
Variance from normal
Heating degree days	6%	(7)%	(10)%
Cooling degree days	(19)%	74%	56%

2008 Compared to 2007

Net income decreased $2.1 million or 9% primarily due to:

•     A $2.6 million reduction in retail and wholesale sales margins due to increased fuel and purchased power costs, primarily due to increased coal costs and scheduled and unscheduled outages at Ben French, Osage and Neil Simpson I coal-fired plants. The duration of the Ben French outage was three months as we accelerated the completion of maintenance projects that were originally scheduled for this plant in 2009;

•     Increased operating expenses due to increased repairs and maintenance expenses and labor overhead costs; and

•     Increased administrative and general expenses of $1.9 million due to an increase in the workers’ compensation reserve.

Partially offsetting the decreases to earnings was the following:

•     Margins from wholesale off-system sales increased $1.3 million. Total MWhs increased 58% as we were able to take advantage of favorable market conditions and high MIDC pricing due to below normal temperatures; and

•     Income related to a $5.3 million increase of AFUDC, primarily attributable to the ongoing construction of Wygen III.

19

2007 Compared to 2006

Income from continuing operations increased 33% primarily due to:

•     Retail sales revenues increased 11% due to an increase in rates that went into effect on January 1, 2007 and a 3% increase in MWh sold;

•     Purchased power decreased 9% due to an 18% decrease in MWh purchased, partially offset by a 10% increase in price per MWh;

•     Margins from wholesale off-system sales increased 7%; and

•     Lower property taxes due to lower assessed property valuations.

Partially offsetting the increases to earnings was the following:

•     Fuel expense increased 23% due to increased coal prices and the use of higher cost gas generation to meet demand requirements.

Rate Increase Settlement. In December 2006, we received an order from the SDPUC, effective January 1, 2007, approving a 7.8% increase in retail rates and the addition of tariff provisions for automatic cost adjustments. The cost adjustments require us to absorb a portion of power cost increases partially depending on earnings from certain short-term wholesale sales of electricity. Absent certain conditions, the order also restricts us from requesting an increase in base rates that would go into effect prior to January 1, 2010. South Dakota retail customers account for approximately 91% of our total retail revenues.

Wygen III Power Plant Project

In March 2008, we received final regulatory approval for construction of Wygen III. Construction began immediately and the 110 MW coal-fired base load electric generation facility is expected to take 24 to 30 months to complete. The expected cost of construction is approximately $255 million, which includes estimates of AFUDC. We expect to retain ownership of 75 MW of the facility’s capacity with MDU currently being expected to take ownership of the remaining 25 MW. We will retain responsibility for operation of the facility with a life-of-plant site lease, and operations and coal supply agreements in place with MDU.

20

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Management’s Report on Internal Control over Financial Reporting	22
Report of Independent Registered Public Accounting Firm	23
Statements of Income for the three years ended December 31, 2008	24
Balance Sheets as of December 31, 2008 and 2007	25
Statements of Cash Flows for the three years ended December 31, 2008	26
Statements of Common Stockholder’s Equity and Comprehensive Income
for the three years ended December 31, 2008	27
Notes to Financial Statements	28 - 50

21

Management's Report on Internal Control over Financial Reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008, based on the criteria set forth in Internal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation we have concluded that our internal control over financial reporting was effective as of December 31, 2008.

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this annual report.

Black Hills Power

22

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of

Black Hills Power, Inc.

Rapid City, South Dakota

We have audited the accompanying balance sheets of Black Hills Power, Inc. (the “Company”) as of December 31, 2008 and 2007, and the related 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, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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 financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, MN

March 17, 2009

23

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME

Years ended December 31,	2008		2007		2006
	(in thousands)
Operating revenues	$	232,674	$	199,701	$	193,166
Operating expenses:
Fuel and purchased power		113,672		79,425		81,215
Operations and maintenance		31,028		25,786		24,304
Administrative and general		21,864		19,965		20,845
Depreciation and amortization		20,930		20,763		19,801
Taxes, other than income taxes		6,544		6,248		6,999
		194,038		152,187		153,164
Operating income		38,636		47,514		40,002
Other (expense) income:
Interest expense		(10,836)		(11,787)		(12,057)
Interest income		725		884		258
AFUDC – equity		3,605		601		405
Other expense		(47)		—		(1)
Other income		227		252		246
		(6,326)		(10,050)		(11,149)
Income from continuing operations before income taxes		32,310		37,464		28,853
Income taxes		(9,551)		(12,568)		(10,129)
Net income	$	22,759	$	24,896	$	18,724

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

24

BLACK HILLS POWER, INC.

BALANCE SHEETS

At December 31,	2008		2007
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	4	$	2,033
Receivables (net of allowance for doubtful accounts of $370 and $388 at 2008
and 2007, respectively) -
Customers		23,881		22,330
Affiliates		12,619		8,882
Other		2,111		2,198
Money pool note receivable		—		10,304
Materials, supplies and fuel		19,309		15,628
Other current assets		5,730		3,862
		63,654		65,237
Investments		3,999		3,774
Property, plant and equipment		843,691		695,452
Less accumulated depreciation and amortization		(281,220)		(266,583)
		562,471		428,869
Other assets:
Regulatory assets		33,818		9,899
Other		2,842		5,901
		36,660		15,800
	$	666,784	$	513,680
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	2,016	$	2,009
Accounts payable		26,567		12,982
Accounts payable – affiliate		10,411		3,158
Notes payable – affiliate		70,184		—
Accrued liabilities		15,151		13,898
Deferred income taxes		732		18
		125,061		32,065
Long-term debt, net of current maturities		149,193		151,209
Deferred credits and other liabilities:
Deferred income taxes		85,504		69,761
Regulatory liabilities		13,573		11,085
Benefit plan liabilities		29,904		9,194
Other		8,626		7,946
		137,607		97,986
Commitments and contingencies (Notes 5, 9 and 11)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized;
Issued: 23,416,396 shares in 2008 and 2007		23,416		23,416
Additional paid-in capital		39,575		39,575
Retained earnings		193,281		170,706
Accumulated other comprehensive loss		(1,349)		(1,277)
		254,923		232,420
	$	666,784	$	513,680

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

25

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS

Years ended December 31,	2008		2007		2006
	(in thousands)
Operating activities:
Net income	$	22,759	$	24,896	$	18,724
Adjustments to reconcile net income to net cash
provided by operating activities –
Depreciation and amortization		20,930		20,763		19,801
Provision for valuation allowances		(18)		138		(586)
Deferred income taxes		16,072		3,864		(2,799)
AFUDC – equity		(3,605)		(601)		(405)
Change in operating assets and liabilities –
Accounts receivable and other current assets		(11,909)		(11,257)		(2,513)
Accounts payable and other current liabilities		6,770		(6,151)		8,431
Other operating activities		965		2,464		1,346
Net cash provided by operating activities		51,964		34,116		41,999
Investing activities:
Property, plant and equipment additions		(132,247)		(34,043)		(24,147)
Notes receivable from affiliate companies, net		10,304		2,960		(13,264)
Other investing activities		(225)		(222)		(212)
Net cash used in investing activities		(122,168)		(31,305)		(37,623)
Financing activities:
Note payable to affiliate companies, net		70,184		—		(1,842)
Long-term debt – repayments		(2,009)		(2,001)		(1,996)
Net cash provided by (used in) financing activities		68,175		(2,001)		(3,838)
(Decrease) increase in cash and cash
equivalents		(2,029)		810		538
Cash and cash equivalents:
Beginning of year		2,033		1,223		685
End of year	$	4	$	2,033	$	1,223
Non-cash investing and financing activities –
Property, plant and equipment financed with
accrued liabilities	$	13,294	$	1,323	$	224
Supplemental disclosure of cash flow information:
Cash paid during the period for –
Interest (net of amounts capitalized)	$	11,578	$	11,782	$	13,826
Income taxes (refunded) paid	$	(5,877)	$	17,284	$	6,820

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

26

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

AND COMPREHENSIVE INCOME

									Accumulated
				Additional					Other
	Common Stock			Paid-In		Retained			Comprehensive
	Shares	Amount		Capital		Earnings			Income (Loss)	Total
	(in thousands)
Balance at December 31,2005	23,416	$	23,416	$	39,549	$	127,312	$	(1 ,598)	$	188,679
Comprehensive Income:
Net income	—		—		—		18,724		—		18,724
Other comprehensive income,
net of tax, (see Note 8)	—		—		—		—		786		786
Total comprehensive income	—		—		—		18,724		786		19,510
Adoption of accounting
pronouncement (see Note 1)	—		—		—		—		(120)		(120)
Assumption of business unit
of affiliate company
(see Note 10)	—		—		26		(226)		—		(200)
Balance at December 31,2006	23,416		23,416		39,575		145,810		(932)		207,869
Comprehensive Income:
Net income	—		—		—		24,896		—		24,896
Other comprehensive loss,
net of tax, (see Note 8)	—		—		—		—		(345)		(345)
Total comprehensive income	—		—		—		24,896		(345)		24,551
Balance at December 31,2007	23,416		23,416		39,575		170,706		(1,277)		232,420
Comprehensive Income:
Net income	—		—		—		22,759		—		22,759
Other comprehensive loss,
net of tax, (see Note 8)	—		—		—		—		(72)		(72)
Total comprehensive income	—		—		—		22,759		(72)		22,687
Adoption of accounting
Pronouncement (see Note 9)	—		—		—		(184)		—		(184)
Balance at December 31,2008	23,416	$	23,416	$	39,575	$	193,281	$	(1,349)	$	254,923

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

27

NOTES TO FINANCIAL STATEMENTS

December 31, 2008, 2007 and 2006

(1) BUSINESSDESCRIPTIONANDSUMMARYOFSIGNIFICANTACCOUNTINGPOLICIES

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 BHC or the Parent, a public registrant listed on the New York Stock Exchange.

Basis of Presentation

The financial statements include the accounts of Black Hills Power, Inc. and also the Company’s ownership interests in the assets, liabilities and expenses of its jointly owned facilities (Note 3).

Use of Estimates

The preparation of financial statements in conformity with GAAP 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, unbilled revenues, long-lived asset values and useful lives, asset retirement obligations, employee benefits plans and contingency accruals. 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 FERC.

The Company’s regulated utility operations follow the provisions of SFAS 71 and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating its electric operations. If rate recovery 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 could be an extraordinary non-cash charge to operations in an amount that could be material.

28

On December 31, 2008 and 2007, the Company had the following regulatory assets and liabilities:

	2008		2007
Regulatory assets:
Unamortized loss on reacquired debt	$	2,367	$	2,527
AFUDC		4,995		4,139
Defined benefit postretirement plans		26,256		2,998
Deferred energy costs		4,382		939
Other		199		235
	$	38,199	$	10,838
Regulatory liabilities:
Deferred income taxes	$	1,857	$	2,094
Cost of removal for utility plant		11,705		8,510
Other		79		760
	$	13,641	$	11,364

Regulatory assets are primarily recorded for the probable future revenue to recover the costs associated with defined benefit postretirement plans, future income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt. To the extent that energy costs are under-recovered or over-recovered during the year, they are recorded as a regulatory asset or liability, respectively. 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, gains associated with regulated utilities’ defined benefit postretirement plans and the cost of removal for utility plant, recovered through the Company’s electric utility rates. Regulatory assets are included in Other current assets and Other assets, Regulatory assets on the accompanying Balance Sheet. Regulatory liabilities are included in Accrued liabilities and Deferred credits and other liabilities, Regulatory liabilities on the accompanying Balance Sheet.

Allowance for Funds Used During Construction

AFUDC represents the approximate composite cost of borrowed funds and a return on capital used to finance a project. AFUDC for the years ended December 31, 2008, 2007 and 2006 was $6.2 million, $0.9 million, and $0.6 million, respectively. The equity component of AFUDC for 2008, 2007 and 2006 was $3.6 million, $0.6 million and $0.4, respectively. The borrowed funds component of AFUDC for 2008, 2007 and 2006 was $2.6 million, $0.3 million and $0.2 million, respectively. The equity component of AFUDC is included in Other income (expense), and the borrowed funds component of AFUDC is netted in Interest expense on the accompanying Statements of Income.

Cash Equivalents

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

29

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated on a weighted-average cost basis. To the extent fuel has been designated as the underlying hedged item in a “fair value” hedge transaction, those volumes are stated at market value using published industry quotations. As of December 31, 2008 and 2007, there were no market adjustments related to fuel.

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. 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. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary 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 3.2% in 2008, 3.1% in 2007 and 3.0% in 2006.

Derivatives and Hedging Activities

The Company, from time to time, utilizes risk management contracts including forward purchases and sales and fixed-for-float swaps to hedge the price of fuel for its combustion turbines, maximize the value of its natural gas storage or fix the interest on its variable rate debt. Contracts that qualify as derivatives under SFAS 133, and that are not exempted such as normal purchase/normal sale, are required to be recorded in the balance sheet as either an asset or liability, measured at its 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 attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income, net of tax, 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, is recognized currently in earnings.

30

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 2008, 2007 or 2006.

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, as well as operating loss and tax credit carryforwards. 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.

Recently Adopted Accounting Pronouncements

SFAS 157

During September 2006, the FASB issued SFAS 157. This Statement defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 does not expand the application of fair value accounting to any new circumstances, but applies the framework to other accounting pronouncements that require or permit fair value measurement. The Company applies fair value measurements to certain assets and liabilities, primarily commodity derivatives.

SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. As of January 1, 2008, the Company adopted the provisions of SFAS 157 for all assets and liabilities measured at fair value except for non-financial assets and liabilities measured at fair value on a non-recurring basis, as permitted by FSP FAS 157-2. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with instruments carried at fair value. On October 10, 2008, the FASB issued FSP FAS 157-3. It was effective upon issuance including prior periods for which financial statements have not been issued. This FSP clarifies the application of SFAS 157 in a market that is not active. The adoption of SFAS 157 and related FSPs did not have a material impact on the Company’s financial position, results of operations or cash flows.

31

SFAS 158

During September 2006, the FASB issued SFAS 158. This Statement requires the recognition of the overfunded or underfunded status of defined benefit postretirement plans as an asset or liability in the statement of financial position, recognition of changes in the funded status in comprehensive income, measurement of the funded status of a plan as of the date of the year-end statement of financial position, and provides for related disclosures. The Company applied the recognition provisions of SFAS 158 as of December 31, 2006. Effective for fiscal years ending after December 15, 2008, SFAS 158 requires the measurement of the funded status of the plan to coincide with the date of the year-end statement of financial position. In accordance with SFAS 158, the measurement date for the funded status of the Company’s pension and other postretirement benefit plans was changed to December 31 from September 30 (see Note 9).

SFAS 159

SFAS 159 establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS 159 was adopted on January 1, 2008 and did not have an impact on the Company’s financial position, results of operations or cash flows.

Recently Issued Accounting Pronouncements

SFAS 141(R)

In December 2007, the FASB issued SFAS 141(R). SFAS 141(R) requires an acquiring entity to recognize the assets acquired, the liabilities assumed and any non-controlling interests in the acquiree at the acquisition date to be measured at their fair values as of the acquisition date, with limited exceptions specified in the statement. This replaces the cost allocation process in SFAS 141, which required the cost of an acquisition to be allocated to the individual assets acquired and liabilities assumed based on their estimated fair values. Acquisition-related costs will be expensed in the periods in which the costs are incurred or services are rendered. Costs to issue debt or equity securities shall be accounted for under other applicable GAAP. SFAS 141(R) applies prospectively to business combinations for which the acquisition date is on or after the first annual reporting period beginning on or after December 15, 2008. We expect SFAS 141(R) will not have an impact on our financial statements when effective, but the nature and magnitude of the specific effects will depend upon the nature, terms and size of any acquisitions we consummate after the effective date. If previously recorded income tax liabilities acquired in a business combination reverse subsequent to the adoption of SFAS 141(R), such reversals will affect expense including income tax expense in the period of reversal. Management is assessing the full impact SFAS 141(R) might have on future financial statements.

32

SFAS 160

In December 2007, the FASB issued SFAS 160. SFAS 160 amends ARB 51 and requires:

•     Ownership interests in subsidiaries held by other parties other than the parent be clearly identified on the consolidated statement of financial position within equity, but separate from the parent’s equity;

•     Consolidated net income attributable to the parent and to the non-controlling interest be clearly identified on the face of the consolidated statement of income;

•     Changes in a parent’s ownership interest while the parent retains controlling financial interest be accounted for consistently as equity transactions;

•     When a subsidiary is deconsolidated, any retained non-controlling equity investment in the former subsidiary be initially measured at fair value; and

•     Sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.

SFAS 160 is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. Management does not expect the adoption of SFAS 160 to have a significant effect on the Company’s financial statements.

SFAS 161

In March 2008, the FASB issued SFAS 161, which requires enhanced disclosures about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. Management does not expect the adoption of SFAS 161 to have a significant effect on the Company’s financial statements.

33

FSP FAS 132(R)-1

During December 2008 the FASB issued FSP FAS 132(R)-1, “Employers Disclosures about Postretirement Benefit Plan Assets.” The objectives of the disclosures about plan assets in an employers defined benefit pension or other postretirement plan are to provide users of financial statements with an understanding of:

•     How investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies;

•     The major categories of plan assets;

•     The input and valuation techniques used to measure the fair value of plan assets;

•     The effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period; and

•     Significant concentrations of risk within plan assets.

FSP FAS 132(R)-1 is effective for fiscal years ending after December 15, 2009. Management does not expect the adoption of FSP FAS 132(R)-1 to have a significant effect on the Company’s financial statements.

(2) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31, consisted of the following (in thousands):

			2008			2007
			Weighted			Weighted
			Average			Average
			Useful			Useful	Lives
	2008		Life	2007		Life	(in years)
Electric plant:
Production	$	326,606	47	$	322,572	47	30-62
Transmission		70,470	45		70,897	45	35-55
Distribution		249,652	37		238,799	37	15-65
Plant acquisition adjustment		4,870	32		4,870	32	32
General		47,127	23		39,296	22	10-50
Total electric plant		698,725			676,434
Less accumulated depreciation
and amortization		281,220			266,583
Electric plant net of accumulated
depreciation and amortization		417,505			409,851
Construction work in progress		144,966			19,018
Net electric plant	$	562,471		$	428,869

34

(3) JOINTLY OWNED FACILITIES

The Company uses the proportionate consolidation method to account for its percentage interest in the assets, liabilities and expenses of the following facilities:

•     The Company owns a 20% interest and PacifiCorp owns an 80% interest in the Wyodak Plant (Plant), a 362 MW coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. The Company receives 20% of the Plant’s capacity and is committed to pay 20% of its additions, replacements and operating and maintenance expenses. As of December 31, 2008 and 2007, the Company’s investment in the Plant included $79.1 million and $80.4 million, respectively, in electric plant and $50.8 million and $43.5 million, respectively, in accumulated depreciation, and is included in the corresponding captions in the accompanying Balance Sheets. The Company’s share of direct expenses of the Plant was $8.0 million, $7.3 million and $7.9 million for the years ended December 31, 2008, 2007 and 2006, respectively, and is included in the corresponding categories of operating expenses in the accompanying Statements of Income.

•     The Company also owns a 35% interest and Basin Electric owns a 65% interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides the Company with access to both the WECC region and the MAPP region. The total transfer capacity of the transmission tie is 400 MW – 200 MW West to East and 200 MW from East to West. The Company is committed to pay 35% of the additions, replacements and operating and maintenance expenses. The Company’s share of direct expenses was $0.1 million for each of the years ended December 31, 2008, 2007 and 2006. As of December 31, 2008 and 2007, the Company’s investment in the transmission tie was $19.8 million, with $2.5 million and $2.0 million, respectively, of accumulated depreciation and is included in the corresponding captions in the accompanying Balance Sheets.

35

(4) RISK MANAGEMENT

The Company holds natural gas in storage for use as fuel for generating electricity with its gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, the Company utilizes various derivative instruments in managing these risks. As of December 31, 2008, there were no derivative contracts outstanding. The balance on December 31, 2007, the Company had the following derivatives and related balances (in thousands):

Pre-tax

Non-

Non-

Accumulated

Maximum

Current

current

Current

current

Other

Terms in

Derivative

Derivative

Derivative

Derivative

Comprehensive

Notional*

Years

Assets

Assets

Liabilities

Liabilities

Income

December 31,

2007

Natural gas

swaps

610,000

0.33

$

238

$

—

$

68

$

—

$

170

________________________

*gas in MMbtus

(5) LONG-TERM DEBT

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

	2008		2007
	(in thousands)
First mortgage bonds:
8.06% due 2010	$	30,000	$	30,000
9.49% due 2018		2,810		3,100
9.35% due 2021		21,645		23,310
7.23% due 2032		75,000		75,000
		129,455		131,410
Other long-term debt:
Pollution control revenue bonds at 4.8% due 2014		6,450		6,450
Pollution control revenue bonds at 5.35% due 2024		12,200		12,200
Other		3,104		3,158
		21,754		21,808
Total long-term debt		151,209		153,218
Less current maturities		(2,016)		(2,009)
Net long-term debt	$	149,193	$	151,209

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 in 2009; $32.0 million in 2010; $2.0 million a year for the years 2011, 2012 and 2013; and $111.2 million thereafter.

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(6) FAIR VALUE OF FINANCIAL INSTRUMENTS

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

	2008				2007
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	4	$	4	$	2,033	$	2,033
Derivative financial
instruments – assets	$	—	$	—	$	238	$	238
Derivative financial
instruments – liabilities	$	—	$	—	$	68	$	68
Long-term debt	$	151,209	$	144,107	$	153,218	$	168,042

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

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 instruments the Company uses are included in Note 4.

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 first mortgage 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 first mortgage bonds.

(7) INCOME TAXES

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

	2008		2007		2006
Current	$	(6,521)	$	8,704	$	12,928
Deferred		16,072		3,864		(2,799)
	$	9,551	$	12,568	$	10,129

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The temporary differences which gave rise to the net deferred tax liability were as follows (in thousands):

Years ended December 31,	2008		2007
Deferred tax assets, current:
Asset valuation reserve	$	129	$	136
Employee benefits		932		399
		1,061		535
Deferred tax liabilities, current:
Prepaid expenses		213		181
Items of other comprehensive income		—		290
Deferred credits		1,580		—
Other		—		82
		1,793		553
Net deferred tax liability, current	$	732	$	18
Deferred tax assets, non-current:
Plant related differences	$	1,151	$	1,316
Regulatory liabilities		10,156		4,533
Employee benefits		3,528		3,366
Items of other comprehensive income		227		226
Other		128		128
		15,190		9,569
Deferred tax liabilities, non-current:
Accelerated depreciation and other plant related differences		83,112		68,250
AFUDC		3,247		2,690
Regulatory assets		11,270		5,222
Employee benefits		2,237		2,284
Other		828		884
		100,694		79,330
Net deferred tax liability, non-current	$	85,504	$	69,761
Net deferred tax liability	$	86,236	$	69,779

38

The following table reconciles the change in the net deferred income tax liability from December 31, 2007, to December 31, 2008, to the deferred income tax expense (in thousands):

	2008
Increase in deferred income tax liability from the preceding table	$	16,457
Deferred taxes related to regulatory assets and liabilities		(1,200)
Deferred taxes associated with other comprehensive loss		38
Deferred taxes related to property tax differences		767
Other		10
Deferred income tax expense for the period	$	16,072

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

	2008	2007	2006
Federal statutory rate	35.0%	35.0%	35.0%
Amortization of excess deferred and investment tax credits	(0.7)	(1.0)	(1.3)
Equity AFUDC	(3.6)	—	—
IRS tax exam adjustment*	—	—	2.6
Other	(1.1)	(0.5)	(1.2)
	29.6%	33.5%	35.1%

__________________________

*As a result of a settlement of an Internal Revenue Service (IRS) exam.

FIN 48

The Company adopted the provisions of FIN 48 on January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109 and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken. The impact of the implementation of FIN 48 had no effect on the financial statements of the Company.

The following table reconciles the total amounts of unrecognized tax benefits at the beginning and end of the period (in thousands):

Unrecognized tax benefits at December 31, 2007	$	—
Additions for current year tax positions		767
Unrecognized tax benefits at December 31, 2008	$	767

None of the total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate.

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It is the Company’s continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2008, the interest expense recognized was not material to the financial results of the Company.

The Company files income tax returns in the United States federal jurisdiction. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of any audits or the expiration of statutes of limitations prior to December 31, 2009.

(8) COMPREHENSIVE INCOME

The following tables display each component of Other Comprehensive Income (Loss) and the related tax effects for the years ended December 31, (in thousands):

	2008
	Pre-tax		Tax		Net-of-tax
	Amount		Benefit		Amount
Pension liability adjustment	$	(4)	$	1	$	(3)
Reclassification adjustments of cash flow hedges
settled and included in net income		(107)		38		(69)
Comprehensive loss	$	(111)	$	39	$	(72)

	2007
	Pre-tax		Tax (Expense)		Net-of-tax
	Amount		Benefit		Amount
Pension liability adjustment	$	115	$	(39)	$	76
Reclassification adjustments of cash flow hedges
settled and included in net income		424		(148)		276
Net change in fair value of derivatives designated as
cash flow hedges		(1,069)		372		(697)
Comprehensive loss	$	(530)	$	185	$	(345)

	2006
	Pre-tax				Net-of-tax
	Amount		Tax Expense		Amount
Pension liability adjustment	$	48	$	(17)	$	31
Amortization of cash flow hedges settled and deferred in
AOCI and reclassified into interest expense		64		(22)		42
Net change in fair value of derivatives designated as
cash flow hedges		1,097		(384)		713
Comprehensive income	$	1,209	$	(423)	$	786

40

Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets are as follows (in thousands):

	Derivatives		Employee
	Designated as		Benefit
	Cash Flow Hedges		Plans		Total
As of December 31, 2008	$	(932)	$	(417)	$	(1,349)
As of December 31, 2007	$	(861)	$	(416)	$	(1,277)

(9) EMPLOYEE BENEFIT PLANS

SFAS 158

The application of SFAS 158 requires recognition of the funded status of postretirement benefit plans in the statement of financial position. The funded status for pension plans is measured as the difference between the projected benefit obligation and the fair value of plan assets. The funded status for all other benefit plans is measured as the difference between the accumulated benefit obligation and the fair value of plan assets. A liability is recorded for an amount by which the benefit obligation exceeds the fair value of plan assets or an asset is recorded for any amount by which the fair value of plan assets exceeds the benefit obligation.

Prior to the December 31, 2006 effective date of SFAS 158, liabilities recorded for postretirement benefit plans were reduced by any unrecognized net periodic benefit cost. Upon adoption of SFAS 158, the unrecognized net periodic benefit cost, previously recorded as an offset to the liability for benefit obligations, was reclassified within AOCI, net of tax. The Company applied the guidance under SFAS 71, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to AOCI was alternatively recorded as a regulatory asset or regulatory liability, net of tax.

SFAS 158 required that the measurement date of plans be the date of the Company’s year-end balance sheet. The Company had used a September 30 measurement date. During 2008, the Company changed the measurement date to December 31. Therefore, $0.2 million, net of tax, was recognized as an adjustment to retained earnings. The amortization of prior service costs for October 1, 2007 to December 31, 2007 was less than $0.1 million, net of tax, and the service cost, interest cost and expected return on plan assets for October 1, 2007 to December 31, 2007 was $0.2 million, net of tax.

Defined Benefit Pension Plan

The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of the Company who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. The Company’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 and fixed income investments. The Company uses a December 31 measurement date for the Plan.

41

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 9.5% for the 2008 and 2007 plan years. For determining the expected long-term rate of return for equity assets, the Company reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2008, 8.4%, 11.0%, 9.0% and 9.2%, respectively. Fund management fees were estimated to be 0.18% for S&P 500 Index assets and 0.45% for other assets. The expected long-term rate of return on fixed income investments was 6.0%; the return was based upon historical returns on 10-year treasury bonds of 7.1% from 1962 to 2007, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 4.0%; expected cash returns were estimated to be 2.0% below long-term returns on intermediate-term bonds.

Plan Assets

Percentage of fair value of Plan assets at December 31:

	2008	2007
Equity	68%	76%
Fixed income	28	21
Cash	4	3
Total	100%	100%

As a result of the severe decline in equity values in the fourth quarter of 2008 and in light of the improved relative value of fixed income investment opportunities, we are undergoing a review to consider a revision of the pension plan investment allocations.

The revision is expected to result in a higher fixed income allocation. Until the investment allocation review is complete and implemented, we have suspended our practice of rebalancing the portfolio on a quarterly basis. This has resulted in an investment allocation of 68% equities and 32% fixed income/cash at December 31, 2008.

The Plan’s investment policy includes the investment objective that the achieved long-term rates of return meet or exceed the assumed actuarial rate. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets. The policy provides that the Plan will maintain a passive core United States Stock portfolio based on a broad market index. Complementing this core will be investments in United States 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.

42

Cash Flows

The Company made no contributions to the Plan in 2008, but expects to contribute $0.3 million to the Plan in 2009.

Supplemental Nonqualified Defined Benefit Retirement Plans

The Company has various supplemental retirement plans for key executives of the Company. The Plans are nonqualified defined benefit plans. The Company uses a December 31 measurement date for the Plans.

Plan Assets

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

Estimated Cash Flows

The estimated employer contribution is expected to be $0.1 million in 2009. Contributions are expected to be made in the 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 December 31measurement date for the Plan.

It has been determined that the Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The effect of the Medicare Part D subsidy on the accumulated postretirement benefit obligation for the fiscal year ending December 31, 2008, was an actuarial gain of approximately $1.0 million. The effect on 2009 net periodic postretirement benefit cost will be a decrease of approximately $0.1 million.

Plan Assets

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

Estimated Cash Flows

The estimated employer contribution is expected to be $0.2 million in 2009. Contributions are expected to be made in the form of benefit payments.

The following tables provide a reconciliation of the Employee Benefit Plan’s obligations and fair value of assets for 2008 and 2007, components of the net periodic expense for the years ended 2008, 2007 and 2006 and elements of regulatory assets and liabilities and AOCI for 2008 and 2007.

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Benefit Obligations

					Supplemental Nonqualified
					Defined Benefit				Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans				Benefit Postretirement Plans
	2008		2007		2008		2007		2008		2007
	(in thousands)
Change in benefit obligation:
Projected benefit obligation at
beginning of year	$	48,937	$	50,340	$	1,958	$	1,999	$	6,649	$	6,791
Service cost		1,396		1,137		—		—		264		211
Interest cost		3,790		2,923		150		116		522		398
Actuarial (gain) loss		2,712		(328)		65		(54)		506		(571)
Amendments		—		—		—		—		—		—
Discount rate change		—		(2,641)		—		—		—		—
Benefits paid		(2,838)		(2,145)		(142)		(103)		(830)		(638)
Asset transfer to affiliate		(2,032)		(349)		(359)		—		(297)		(19)
Medicare Part D adjustment		—		—		—		—		71		75
Plan participant’s contributions		—		—		—		—		508		402
Net increase (decrease)		3,028		(1,403)		(286)		(41)		744		(142)
Projected benefit obligation at
end of year	$	51,965	$	48,937	$	1,672	$	1,958	$	7,393	$	6,649

A reconciliation of the fair value of Plan assets (as of the December 31 measurement date) is as follows:

					Supplemental Nonqualified
					Defined Benefit				Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans				Benefit Postretirement Plans
	2008		2007		2008		2007		2008		2007
					(in thousands)
Beginning market value of
plan assets	$	52,466	$	46,916	$	—	$	—	$	—	$	—
Investment income		(8,771)		8,044		—		—		—		—
Benefits paid		(2,249)		(2,145)		—		—		—		—
Asset transfer to affiliate		—		(349)		—		—		—		—
Ending market value of
plan assets	$	41,446	$	52,466	$	—	$	—	$	—	$	—

Amounts recognized in the statement of financial position consist of:

					Supplemental Nonqualified
					Defined Benefit					Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans					Benefit Postretirement Plans
	2008		2007		2008		2007			2008		2007
					(in thousands)
Regulatory asset (liability)	$	26,256	$	2,998	$	—		$	—	$	(11)		$	(480)
Current liability		—		—		109			129		223			186
Non-current asset (liability)		(19,864)		3,529		(1,564)			(1,801)		(7,169)			(6,399)

44

Accumulated Benefit Obligation

					Supplemental Nonqualified
					Defined Benefit				Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans				Benefit Postretirement Plans
	2008		2007		2008		2007		2008		2007
					(in thousands)
Accumulated benefit obligation	$	43,894	$	41,823	$	1,622	$	1,808	$	7,393	$	6,649

Components of Net Periodic Expense

								Supplemental Nonqualified
								Defined Benefit								Non-pension Defined Benefit
	Defined Benefit Pension Plans							Retirement Plans								Postretirement Plans
	2008		2007			2006		2008			2007			2006		2008		2007		2006
								(in thousands)
Service cost	$	1,117	$	1,137	$		1,085	$	—	$		—	$		—	$	211	$	211	$	249
Interest cost		3,032		2,923			2,720		120			116			113		417		398		398
Expected return on assets		(4,374)		(3,885)			(3,557)		—			—			—		—		—		—
Amortization of prior
service cost		112		103			103		1			1			1		—		—		(19)
Amortization of transition
obligation		—		—			—		—			—			—		51		51		117
Recognized net actuarial
loss		—		408			665		44			57			67		(1)		—		—
Net periodic expense	$	(113)	$	686	$		1,016	$	165	$		174	$		181	$	678	$	660	$	745

AOCI

In accordance with SFAS 158, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31, are as follows:

					Supplemental Nonqualified
					Defined Benefit				Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans				Benefit Postretirement Plans
	2008		2007		2008		2007		2008		2007
					(in thousands)
Net loss	$	—	$	—	$	(347)	$	(418)	$	—	$	—
Prior service cost		—		—		(1)		(1)		—		—
Transition obligation		—		—		—		—		—		—
	$	—	$	—	$	(348)	$	(419)	$	—	$	—

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The amounts in AOCI, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2009 are as follows:

			Supplemental
			Nonqualified		Non-pension
	Defined Benefits		Defined Benefit		Defined Benefit
	Pension Plans		Retirement Plans		Postretirement Plans
	(in thousands)
Net loss	$	1,118	$	28	$	—
Prior service cost		73		—		—
Transition obligation		—		—		33
Total net periodic benefit cost
expected to be recognized
during calendar year 2008	$	1,191	$	28	$	33

Assumptions

				Supplemental Nonqualified			Non-pension
	Defined Benefit			Defined Benefit			Defined Benefit
	Pension Plans			Retirement Plans			Postretirement Plans
Weighted-average
assumptions used to
determine benefit
obligations:	2008	2007	2006	2008	2007	2006	2008	2007	2006
Discount rate	6.20%	6.35%	5.95%	6.20%	6.35%	5.95%	6.10%	6.35%	5.95%
Rate of increase in
compensation levels	4.25%	4.34%	4.31%	5.00%	5.00%	5.00%	N/A	N/A	N/A
Weighted-average
assumptions used to
determine net periodic
benefit cost for plan year:	2008	2007	2006	2008	2007	2006	2008	2007	2006
Discount rate	6.35%	5.95%	5.75%	6.35%	5.95%	5.75%	6.35%	5.95%	5.75%
Expected long-term rate
of return on assets*	8.50%	8.50%	8.50%	N/A	N/A	N/A	N/A	N/A	N/A
Rate of increase in
compensation levels	4.34%	4.31%	4.34%	N/A	5.00%	5.00%	N/A	N/A	N/A

_____________________________

* The expected rate of return on plan assets remained at 8.50% for the calculation of the 2009 net periodic pension cost.

The healthcare cost trend rate assumption for 2008 fiscal year benefit obligation determination and 2009 fiscal year expense is a 9% increase for 2009 grading down 1% per year until a 5% ultimate trend rate is reached in fiscal year 2013. The healthcare cost trend rate assumption for the 2008 fiscal year benefit obligation determination and 2008 fiscal year expense was a 10% increase for 2008 grading down 1% per year until a 5% ultimate trend rate is reached in fiscal year 2013.

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The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1% increase in the healthcare cost trend assumption would increase the service and interest cost $0.1 million or 21% and the accumulated periodic postretirement benefit obligation $1.3 million or 18%. A 1% decrease would reduce the service and interest cost by $0.1 million or 16% and the accumulated periodic postretirement benefit obligation $1.0 million or 14%.

The following benefit payments, which reflect future service, are expected to be paid (in thousands):

					Non-pension Defined
					Benefit Postretirement Plans
			Supplemental		Expected		Expected		Expected
	Defined		Nonqualified		Gross		Medicare Part D		Net
	Benefit		Defined Benefit		Benefit		Drug Benefit		Benefit
	Pension Plans		Retirement Plan		Payments		Subsidy		Payments
2009	$	2,440	$	109	$	298	$	(75)	$	223
2010		2,561		107		340		(83)		257
2011		2,695		111		384		(91)		293
2012		2,780		92		404		(100)		304
2013		2,917		74		441		(108)		333
2014-2018		16,817		421		2,667		(643)		2,024

Defined Contribution Plan

The Parent sponsors a 401(k) savings plan in which employees of the Company may participate. Participants may elect to invest up to 20% of their eligible compensation on a pre-tax basis, up to a maximum amount established by the Internal Revenue Service. The Company provides a matching contribution of 100% of the employee’s annual contribution up to a maximum of 3% of eligible compensation. Matching contributions vest at 20% per year and are fully vested when the participant has 5 years of service with the Company. The Company’s matching contributions were $0.7 for 2008, $0.6 million for 2007 and $0.6 million for 2006.

(10) RELATED-PARTY TRANSACTIONS

Receivables and Payables

The Company has accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $12.6 million and $8.9 million as of December 31, 2008 and 2007, respectively. The Company also has accounts payable balances related to transactions with other BHC subsidiaries. The balances were $10.4 million and $3.2 million as of December 31, 2008 and 2007, respectively.

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Money Pool Notes Receivable and Notes Payable

The Company has a Utility Money Pool Agreement with the Parent, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, the Company may borrow from the Parent. The Agreement restricts the Company from loaning funds to the Parent or to any of the Parent’s non-utility subsidiaries; the Agreement does not restrict the Company from making dividends to the Parent. Borrowings under the agreement bear interest at the daily cost of external funds as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 100 basis points.

The Company through the Utility Money Pool had a net note payable balance to the Parent of $70.2 million as of December 31, 2008 and a note receivable balance from Cheyenne Light and the Parent of $10.3 million as of December 31, 2007. Advances under this note bear interest at 0.70% above the daily LIBOR rate (1.14% at December 31, 2008). Net interest expense of $0.9 million and net interest income of $0.9 million was recorded for the years ended December 31, 2008 and 2007, respectively.

Other Balances and Transactions

The Company also received revenues of approximately $1.2 million, $1.9 million and $2.4 million for the years ended December 31, 2008, 2007 and 2006, respectively, from Black Hills Wyoming, Inc. for the transmission of electricity.

The Company recorded revenues of $0.2 million, $1.4 million and $3.3 million for the years ending December 31, 2008, 2007 and 2006, respectively, relating to payments received pursuant to a natural gas swap entered into with Enserco.

The Company received revenues of approximately $2.8 million for the year ended December 31, 2008, from Cheyenne Light for the sale of electricity and dispatch services.

The Company purchases coal from WRDC. The amount purchased during the years ended December 31, 2008, 2007 and 2006 was $15.5 million, $12.6 million and $10.8 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.

The Company purchases excess power generated by Cheyenne Light. The amount purchased during the year ended December 31, 2008 was $6.4 million.

In order to fuel its combustion turbine, the Company purchased natural gas from Enserco. The amount purchased during the years ended December 31, 2008, 2007 and 2006 was approximately $8.0 million, $4.5 million and $7.2 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.

In addition, the Company also pays the Parent for allocated corporate support service cost incurred on its behalf. Corporate costs allocated from the Parent were $12.4 million and $11.3 million for the years ended December 31, 2008 and 2007, respectively.

The Company has funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $1.9 million and $1.8 million at December 31, 2008 and 2007, respectively, which is included in Deferred credits and other liabilities, Other on the accompanying Balance Sheets. Interest on the deposit accrues quarterly at an average prime rate (5% at December 31, 2008).

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On January 1, 2006, the Company assumed the assets and liabilities of Mayer Radio, Inc., a subsidiary of the Parent. Results from the assumption of the business unit activity were not material to the Company.

On August 28, 2008 the Company entered into a contract with Cheyenne Light under which Cheyenne Light will sell up to 20 MW wind-generated, renewable energy to the Company until 2028. Purchases from this agreement during 2008 were $0.6 million.

(11) COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements

In 1983, the Company entered into a 40 year power purchase agreement with PacifiCorp providing for the purchase by the Company of 75 MW of electric capacity and energy from PacifiCorp’s system. An amended agreement signed in October 1997 reduces the contract capacity by 25 MW (5 MW 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 $11.6 million in 2008, $10.9 million in 2007 and $10.1 million in 2006.

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 the Company’s capacity and energy will be transmitted by PacifiCorp: 17 MW in 2005-2006 and 50 MW in 2007-2023. Costs incurred under this agreement were $1.2 million in 2008, $1.2 million in 2007 and $0.4 million in 2006.

•     A 20-year power purchase agreement with Cheyenne Light expiring in 2028, under which we will purchase up to 20 MW of renewable energy through Cheyenne Light’s agreement with Happy Jack Wind Farms, LLC; and

•     A Generation Dispatch Agreement with Cheyenne Light that requires the Company to purchase all of Cheyenne Light’s excess energy.

Long-Term Power Sales Agreements

•     The Company has a ten-year power sales contract with MEAN for 20 MW of unit-contingent capacity from the Neil Simpson II plant. The contract expires in 2013; and

•     The Company has a power purchase agreement with MDU for the supply of up to 74 MW of capacity and energy for Sheridan, Wyoming from 2007 through 2016. The Company also has a contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city’s first 23 MW of capacity and energy. The agreement renews automatically and requires a seven-year notice of termination. Both contracts are served by the Company and are integrated into its control area and are treated as part of the utility’s firm native load.

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Legal Proceedings

Ongoing Litigation

The Company is subject to various 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, results of operations or cash flows of the Company.

(12) 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 2008 and 2007.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands)
2008:
Operating revenues	$	57,632	$	57,978	$	59,358	$	57,706
Operating income		10,591		9,270		10,228		8,547
Net income		5,576		5,251		6,371		5,561
2007:
Operating revenues	$	47,767	$	44,972	$	51,774	$	55,188
Operating income		12,545		10,060		11,148		13,761
Net income		6,699		4,881		5,781		7,535

(13) SUBSEQUENT EVENT

On February 24, 2009, the SDPUC approved an Energy Cost Adjustment for South Dakota customers effective March 1, 2009. The Company will absorb the first $2.0 million in increased costs and both South Dakota customers and the Company will share in absorbing costs above that amount.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2008. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

Internal control over financial reporting

Management’s Report on Internal Control over Financial Reporting is presented on Page 22 of this Annual Report on Form 10-K.

During our fourth fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)	1.	Financial Statements
		Financial statements required by Item 15 are listed in the index included in Item 8 of
		Part II.
	2.	Schedules
		Valuation and Qualifying Accounts for the years ended December 31, 2008, 2007 and
		2006.
		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 this Form 10-K.

BLACK HILLS POWER, INC.
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006
Additions
	Balance		Charged				Balance
	at beginning		to costs				at end
Description	of year		and expenses		Deductions		of year
	(in thousands)
Allowance for
doubtful accounts:
2008	$	388	$	637	$	(655)	$	370
2007		250		320		(182)		388
2006		830		163		(743)		250

3. Exhibits

Exhibit Number	Description
2*	Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation’s Registration Statement on Form S-4 (No. 333-52664)).
3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).

52

3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).
4.1*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as an exhibit to Black Hills Holding Corporation’s Registration Statement on Form S-4 (No. 333-52664)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002).
10.1*	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).
10.2*	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).
10.3*	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).
31.1	Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Rule13a-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 of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

__________________________

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

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

(c) 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.

53

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	/s/ DAVID R. EMERY
	David R. Emery, Chairman and
	Chief Executive Officer
Dated:  March 17, 2009

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/ DAVID R. EMERY	Director and	March 17, 2009
David R. Emery, Chairman and	Principal Executive Officer
Chief Executive Officer
/s/ ANTHONY S. CLEBERG	Principal Financial and	March 17, 2009
Anthony S. Cleberg, Executive Vice President	Accounting Officer
and Chief Financial Officer
/s/ DAVID C. EBERTZ	Director	March 17, 2009
David C. Ebertz
/s/ JACK W. EUGSTER	Director	March 17, 2009
Jack W. Eugster
/s/ JOHN R. HOWARD	Director	March 17, 2009
John R. Howard
/s/ KAY S. JORGENSEN	Director	March 17, 2009
Kay S. Jorgensen
/s/ STEPHEN D. NEWLIN	Director	March 17, 2009
Stephen D. Newlin
/s/ GARY L. PECHOTA	Director	March 17, 2009
Gary L. Pechota
/s/ WARREN L. ROBINSON	Director	March 17, 2009
Warren L. Robinson
/s/ JOHN B. VERING	Director	March 17, 2009
John B. Vering
/s/ THOMAS J. ZELLER	Director	March 17, 2009
Thomas J. Zeller

54

INDEX TO EXHIBITS

Exhibit Number	Description
2*	Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation’s Registration Statement on Form S-4 (No. 333-52664)).
3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (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 Registrant’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*	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).
10.2*	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).
10.3*	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).
31.1	Certification of Chief Executive Officer pursuant to Rule13a-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Rule13a-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 of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

__________________________

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

55