BLACK HILLS POWER INC - FORM 10-K

Attached files

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EX-23.0 - DELOITTE AND TOUCHE CONSENT - BLACK HILLS POWER INC	ex23.htm
EX-32.1 - CEO CERTIFICATION - BLACK HILLS POWER INC	ex32_1.htm
EX-32.2 - CFO CERTIFICATION - BLACK HILLS POWER INC	ex32_2.htm
EX-31.2 - CFO CERTIFICATION - BLACK HILLS POWER INC	ex31_2.htm
EX-31.1 - CEO CERTIFICATION - BLACK HILLS POWER INC	ex31_1.htm

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, 2009

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 whether the Registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

Yes o 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 26, 2010
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	10

ITEM 1A.	RISK FACTORS	11

ITEM 1B.	UNRESOLVED STAFF COMMENTS	20

ITEM 3.	LEGAL PROCEEDINGS	20

ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS	20

ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS	20

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	25

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	58

ITEM 9A.	CONTROLS AND PROCEDURES	58

ITEM 9B.	OTHER INFORMATION	58

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	59

	SIGNATURES	62

	INDEX TO EXHIBITS	63

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
ASC	Accounting Standards Codification
ASC 105	ASC 105, "FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles"
ASC 715	ASC 715, "Compensation – Retirement Benefits"
ASC 805	ASC 805, "Business Combinations"
ASC 815	ASC 815, "Derivatives and Hedges"
ASC 820	ASC 820, "Fair Value Measurements and Disclosures"
ASC 825	ASC 825, "Financial Instruments"
ASC 855	ASC 855, "Subsequent Events"
Basin Electric	Basin Electric Power Cooperative
BHC	Black Hills Corporation
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of the Parent Company, that was formerly known as Black Hills Energy, Inc.
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Wyoming	Black Hills Wyoming, Inc., an indirect, wholly-owned subsidiary of Black Hills Electric Generation, Inc., a subsidiary of Black Hills Non-regulated Holdings
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
CO2	Carbon Dioxide
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
Enserco	Enserco Energy Inc., a wholly-owned subsidiary of Black Hills Non-Regulated Holdings, LLC
EPA	U.S. Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
GHG	Greenhouse gas
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
IRS	Internal Revenue Service
LIBOR	London Interbank Offered Rate
MAPP	Mid-Continent Area Power Pool
MDU	Montana Dakota Utilities Company
MEAN	Municipal Energy Agency of Nebraska
MIDC
MMBtu	Million British thermal units
Moody's	Moody's Investor Services, Inc.
MTPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours

NQDC	Non-Qualified Deferred Compensation Plan
PPA	Power Purchase Agreement
PSD	Prevention of Significant Deterioration
PUHCA	Public Utility Holding Company Act of 2005
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
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

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. Forward-looking statements involve risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by terminology such as "may," "will," "could," "should," "expects," "plans," "anticipates," "believes," "estimates," "projects," "predicts," "potentials," or "continue" or the negative of these terms or other similar terminology. There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurances that such indicated results will be realized. 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 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 Energy Policy Act of 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;

Our ability to successfully complete labor negotiations with our union;

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;

Federal and state laws concerning climate changes 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;

Our ability to recover our borrowing costs, including debt service 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 on our financial condition or results of operations;

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.

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 to Parent, and overall performance and growth.

Distribution and Transmission

Distribution and Transmission. Our distribution and transmission system serves approximately 66,900 electric customers, with an electric transmission system of 1,007 miles of high voltage lines (greater than 69 KV) and 2,403 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 90% of our retail electric revenues in 2009 were generated in South Dakota. We are subject to regulation by the SDPUC, the WPSC and the MTPSC.

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, 2009 was comprised of 29% commercial, 23% residential, 12% contract wholesale, 16% wholesale off-system, 10% industrial and 10% municipal sales and other revenue.

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 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. This agreement permitted MDU the option to participate in the ownership of the Wygen III plant that is currently being constructed. In April 2009, MDU exercised this option and purchased a 25% ownership interest in Wygen III. In conjunction with the ownership interest transaction, the agreement to supply capacity and energy through 2016 was modified. The agreement now provides that once in commercial operation, the first 25 MW of the required 74 MW will be supplied from MDU's ownership interest in Wygen III. During periods of reduced production at Wygen III, or during periods when Wygen III is offline, MDU will be provided with its 25 MW from our other generation facilities or from system purchases;

●

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, 2009, neither party to the agreement had given a notice of termination;

An agreement under which we supply 20 MW of energy and capacity to MEAN under a contract that expires in 2023. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows:

2010-2017 20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II

2018-2019 15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

2020-2021 12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II

2022-2023 10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II; and

In July 2009, we entered into a five-year PPA with MEAN. The contract commences the month following the onset of commercial operations of Wygen III. Under this contract, MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.

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, 1% is oil- or gas-fired, and 49% is supplied under the following purchased power contracts:

A PPA with PacifiCorp expiring in 2023, involving the purchase by us of 50 MW of coal-fired baseload power;

A reserve capacity integration agreement with PacifiCorp 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 PPA with Cheyenne Light expiring in 2028, under which we will purchase up to 20 MW of wind energy through Cheyenne Light's agreement with Happy Jack;

A 20-year PPA with Cheyenne Light expiring in 2029, under which we will purchase up to 20 MW of wind energy through Cheyenne Light's agreement with Silver Sage; and

A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light's excess energy.

Since 1995, we have been a net producer of energy. We reached our 2009 peak system load of 392 MW in December 2009 with an average system load of 255 MW for the year ended December 31, 2009. 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 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 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 thresholds where we absorb the first $2.0 million of increased costs or retain 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.

Rate Increase Settlement. On February 10, 2009, FERC approved a formulaic approach to the method used to determine the revenue component of our open access transmission tariff, and increased our annual transmission revenue requirement by approximately $3.8 million. The revenue requirement is based on an equity return of 10.8%, and a capital structure consisting of 57% equity and 43% debt. The new rates had an effective date of January 1, 2009.

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

We follow accounting for regulated utility operations 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 accounting criteria for regulated operations, 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 2009 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.

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. Our returns could be threatened by plant outages, machinery failures, increased purchased power costs, acts of nature, acts of terrorism or other unexpected events over which we have no control that could cause our costs to increase and operating margins to decline. 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, purchased power costs and transmission, as applicable) without having to file a rate case. To the extent we pass through such costs to customers and a state public utility commission subsequently determines that such costs should not have been paid by customers, we may be required to refund such costs to customers. Any such costs not recovered through rates, or any such refund, could negatively affect our revenues, cash flows and results of operations.

The recent global financial crisis made the credit markets less accessible and created a shortage of available credit. Should a similar financial crisis occur in the future, we may 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, proceeds of debt offerings and proceeds from asset sales. Our ability 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.

Our financial performance depends on the successful operations of our facilities.

Operating electric generating facilities involves risks, including:

Operational limitations imposed by environmental and other regulatory requirements.

Interruptions to supply of fuel and other commodities used in generation.

Breakdown or failure of equipment or processes.

Inability to recruit and retain skilled technical labor.

Labor relations. Renewal negotiations of the collective bargaining agreement are planned in early 2010.

Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity that we sell to our retail and wholesale customers. If transmission is interrupted, our ability to sell or deliver product and satisfy our contractual obligations may be hindered.

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 from federal and state utility commissions. 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 are able to pass through such costs to our customers and a state public utility commission subsequently determines that such costs should not have been paid by our customers; we may be required to refund such costs to our customers. Any such costs not recovered through rates, or any such refund, could negatively affect our revenues, cash flows and results of operations.

The global financial crisis has affected 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.

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 quality and adjust the credit limits based upon such changes, our credit guidelines, controls and limits may not protect us from increasing counterparty credit risk. 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 "A3" by Moody's, "BBB" by S&P and A- by Fitch. Any reduction in our ratings by the rating agencies 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.

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;

The inability and cost of recruiting and retaining skilled labor;

Supply interruptions, work stoppages and labor disputes;

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

Opposition by members of the 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 off-system 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.

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. 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 regulations, 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 and non-regulated fossil-fuel generating plants in South Dakota and Wyoming. We are near completion of another fossil-fuel generating plant in Wyoming. Air emissions of fossil-fuel generating plants are subject to federal and state regulation. Recent developments under federal and state laws and regulation governing air emissions from fossil-fuel generating plants will likely result in more stringent emission limitations.

On October 22, 2009, the EPA filed a consent decree with environmentalists in the U.S. District Court for the District of Columbia, requiring the agency to propose a rule directed at coal and oil-fired power plants, setting maximum achievable control technology limits for air toxins, including mercury, by March 2011 and issue a final rule by November 2011. While we expect this rule will be applicable to certain of our coal-fired units, we are unable to ascertain the full impact until the provisions of the proposed rule are known.

On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency, holding that CO2 and other GHG emissions are pollutants subject to regulation under the motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or alternatively, to explain why GHG emissions should not be regulated. On April 17, 2009, the EPA signed its proposed Endangerment and Cause or Contribute Finding for Greenhouse Gases under Section 202 of the Clean Air Act. Although this proposal does not specifically address stationary sources, such as power generation plants, the general endangerment finding relative to GHGs could support such a proposal by the EPA for stationary sources. On October 30, 2009, the EPA published final rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions.

In addition, the EPA published in the October 27, 2009, Federal Register a proposed rule that would tailor the major source applicability thresholds for GHG emissions under the PSD and Title V programs of the Clean Air Act and set a PSD significance level for GHG emissions. EPA states this rule is necessary because they expect to soon promulgate regulations under the Clean Air Act to control GHG emissions and as a result, trigger PSD and Title V applicability requirements. This proposed rule would phase in the applicability thresholds for both the PSD and Title V programs for sources of GHG emissions. The first phase, which would last six years, would establish a temporary level for the PSD and Title V applicability thresholds at 25,000 tons per year on a carbon dioxide equivalent basis and would also establish temporary PSD significance levels. All our generating units would exceed this threshold and if the pending rule to control GHG emissions is published and finalized, we would be required upon Title V permit renewal, to evaluate options for reducing GHG emissions, to possibly include a Best Available Control Technology review that could result in more stringent emissions control practices and technologies. In the second phase of this proposed rule, EPA would within five years of the rule being final, review the first phase and promulgate revised applicability and significance level thresholds as appropriate.

Finally, federal legislation is currently under consideration in the U.S. Congress, including H.R. 2454, "the American Clean Energy and Security Act of 2009," which was approved by the U.S. House of Representatives on June 26, 2009. This legislation would affect electric generation and electric and natural gas distribution companies. H.R. 2454 also proposes a national renewable electricity standard, which would implement a phased process ultimately mandating that 20% of electricity sold by retail suppliers be met by energy efficiency improvements and renewable energy resources by 2020.

The climate bill under consideration in the U.S. Senate is S.1733, "the Clean Energy Jobs and American Power Act." S.1733 was passed by the Environment and Public Works Committee November 5, 2009, but is not expected to be brought to the Senate floor in its current form. Other committees with jurisdiction include Finance, Energy and Natural Resources, Commerce, Agriculture, and Foreign Relations. The Senate Energy and Natural Resources Committee passed S.1462, "the American Clean Energy Leadership Act of 2009," on July 16, 2009, which would establish a 15% Renewable Electricity Standard by 2021. If the Senate were to act in 2010, it is likely the climate change and renewable electricity standard portions would be combined into one bill.

Due to uncertainty as to the final outcome of federal climate change legislation, or regulatory changes under the Clean Air Act, we cannot definitively estimate the effect of GHG regulation on our results of operations, cash flows or financial position. The impact of GHG legislation or regulation upon our company will depend upon many factors, including but not limited to the timing of implementation, the GHG sources that are regulated, the overall GHG emissions cap level, and the availability of technologies to control or reduce GHG emissions. If a "cap and trade" structure is implemented, the impact will also be affected by the degree to which offsets are allowed, the allocation of emission allowances to specific sources, and the affect of carbon regulation on natural gas and coal prices.

More stringent GHG emissions limitations or other energy efficiency requirements, however, 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, the acquisition or development of additional energy supply from renewable resources, 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. Black Hills Non-regulated Holdings would also attempt to recover the emission compliance costs of their non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by the affiliated 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.

We own regulated electric utilities that serve customers in South Dakota, Wyoming and Montana. Montana has adopted mandatory renewable portfolio standards that require electric utilities to supply a 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, our power supply costs will further increase. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.

We may be vulnerable to cyber attacks and terrorism.

Man-made problems such as computer viruses, terrorism, theft and sabotage, may disrupt our operations and harm our operating results. We operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Our technology systems may be vulnerable to disability, failures or unauthorized access due to hacking, viruses, acts of war or terrorism and other causes. If our technology systems were to fail or be breached and we were unable to recover in a timely manner, we may be unable to fulfill critical business functions and sensitive, confidential and other data could be compromised, which could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, our generation plants, fuel storage facilities, transmission and distribution facilities may be targets of terrorist activities that could disrupt our ability to produce or distribute some portion of our energy products.

Ongoing changes in the United States electric 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 Energy Policy Act of 2005 and the repeal of the PUHCA;

Industry consolidation;

Consumer demands;

Transmission constraints;

Renewable resource supply requirements;

Resistance to the siting of utility infrastructure or to the granting of right-of-ways;

Technological advances; and

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

FERC has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses. 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 adversely affect our financial condition or results of operations.

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.

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.

The Energy Policy Act of 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 our 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 or our independent auditors may identify areas of weakness in control design or effectiveness, which may lead to the conclusion that a material weakness in internal control exists.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 3.

LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the "Legal Proceedings" sub caption within Item 8, Note 12, "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

	2009			2008			2007
	(in thousands)

Revenue	$	207,079		$	232,674		$	199,701
Fuel and purchased power		91,349			113,672			79,425
Gross margin		115,730			119,002			120,276

Operating expenses		80,925			80,366			72,762
Operating income		34,805			38,636			47,514

Interest expense, net		(11,164	)		(10,111	)		(10,903	)
Other income		7,802			3,785			853
Income tax expense		(8,304	)		(9,551	)		(12,568	)
Net income	$	23,139		$	22,759		$	24,896

The following tables provide certain electric utility operating statistics:

Electric Revenue (in thousands)

Customer Base	2009		Percentage Change			2008		Percentage Change			2007

Commercial	$	59,897		3	%	$	58,289		4	%	$	55,991
Residential		48,586		4			46,854		3			45,657
Industrial		20,014		(7	)		21,432		(2	)		21,974
Municipal		2,735		-			2,734		1			2,697
Total retail sales		131,232		1			129,309		2			126,319
Contract wholesale		25,358		(5	)		26,643		6			25,240
Wholesale off-system		32,212		(49	)		63,770		81			35,210
Total electric sales		188,802		(14	)		219,722		18			186,769
Other revenue		18,277		41			12,952		-			12,932
Total revenue	$	207,079		(11	)%	$	232,674		17	%	$	199,701

Megawatt-Hours Sold

Customer Base	2009		Percentage Change			2008		Percentage Change			2007

Commercial		723,360		3	%		699,734		1	%		690,702
Residential		529,825		1			524,413		1			518,148
Industrial		353,041		(15	)		414,421		(5	)		434,627
Municipal		33,948		(1	)		34,368		(1	)		34,661
Total retail sales		1,640,174		(2	)		1,672,936		-			1,678,138
Contract wholesale		645,297		(3	)		665,795		2			652,931
Wholesale off-system		1,009,574		(6	)		1,074,398		58			678,581
Total electric sales		3,295,045		(3	)		3,413,129		13			3,009,650
Losses and company use		159,207		90			83,598		(29	)		118,253
Total energy		3,454,252		(1	)%		3,496,727		12	%		3,127,903

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.

	2009	2008	2007
Regulated power plant fleet availability:
Coal-fired plants	90.3%	93.5%	95.4%
Other plants	97.7%	89.2%	99.4%
Total availability	93.5%	91.6%	97.2%

Resources	2009		Percentage Change			2008		Percentage Change			2007

MWh generated:
Coal		1,721,074		(1	)%		1,731,838		(2	)%		1,758,280
Gas		46,723		(24	)		61,801		(32	)		90,618
		1,767,797		(1	)		1,793,639		(3	)		1,848,898

MWh purchased		1,686,455		(1	)		1,703,088		33			1,279,005
Total resources		3,454,252		(1	)%		3,496,727		12	%		3,127,903

	2009	2008	2007

Heating and cooling degree days:
Actual
Heating degree days	7,753	7,676	6,627
Cooling degree days	354	482	1,033

Variance from 30-year average:
Heating degree days	8%	6%	(7)%
Cooling degree days	(41)%	(19)%	74%

2009 Compared to 2008

Net income increased $0.4 million or 2% primarily due to:

$6.5 million increase in other margins primarily due to an increase in transmission rates effective January 1, 2009;

Increased other income primarily due to a $2.2 million increase of AFUDC-equity, attributable to the ongoing construction of Wygen III; and

Income tax expense decreased $1.2 million primarily due to a decrease in pre-tax net income and the favorable tax impact as a result of the increase in AFUDC-equity.

Partially offsetting the increases to earnings was the following:

Margins from wholesale off-system sales decreased $7.6 million due to a 46% decrease in energy prices and a 6% decrease in total MWh sold in the power markets;

Increase in net interest expense of $1.1 million primarily due to a new debt issuance; and

A $1.0 million decrease in retail and wholesale margins primarily due to increased coal costs and a 2% decrease in MWh sold related to lower cooling degree days.

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 MWh 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.

Rate Increase Requests. On October 19, 2009, we filed a rate case with the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred since 1995. We are seeking a $3.8 million, or approximately 38.95%, increase in annual utility revenues and anticipate that the new rates will be effective for our Wyoming customers on or around July 1, 2010, although recovery could be delayed until August 2010 as part of the regulatory process. The proposed rate increase is subject to approval by the WPSC and we cannot predict the outcome of this rate filing request.

On September 30, 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years. We are seeking a $32.0 million, or approximately 26.6%, increase in annual utility revenues. The final order from the SDPUC is not expected by April 1, 2010. On March 1, 2010, we filed a petition with the SDPUC requesting an interim rate increase of $24.0 million, or 20%, for South Dakota utility customers. The SDPUC approved the request for interim rates on March 9, 2010 effective April 1, 2010. The proposed rate increase is subject to approval by the SDPUC and we cannot predict the outcome of this rate filing request.

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 90% 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 be completed by April 2010. The expected cost of construction is approximately $255 million, which includes estimates of AFUDC. In April 2009, we sold a 25% ownership interest to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date for the on-going construction of the facility. MDU will continue to reimburse us monthly for its 25% of the total costs paid to complete the project. 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.

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	INDEX TO FINANCIAL STATEMENTS

Management's Report on Internal Control over Financial Reporting	26

Report of Independent Registered Public Accounting Firm	27

Statements of Income for the three years ended December 31, 2009	28

Balance Sheets as of December 31, 2009 and 2008	29

Statements of Cash Flows for the three years ended December 31, 2009	30

Statements of Common Stockholder's Equity and Comprehensive Income for the three years ended December 31, 2009	31

Notes to Financial Statements	32 - 57

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, 2009, based on the criteria set forth in Internal Control - Integrated Framework issued 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, 2009.

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

Black Hills Power

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, 2009 and 2008, 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, 2009. Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedule 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, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, 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, present fairly in all material respects the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 10, 2010

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME

Years ended December 31,	2009			2008			2007
	(in thousands)

Operating revenues	$	207,079		$	232,674		$	199,701

Operating expenses:
Fuel and purchased power		91,349			113,672			79,425
Operations and maintenance		30,339			31,028			25,786
Administrative and general		24,586			21,864			19,965
Depreciation and amortization		19,465			20,930			20,763
Taxes, other than income taxes		6,535			6,544			6,248
Total operating expenses		172,274			194,038			152,187

Operating income		34,805			38,636			47,514

Other (expense) income:
Interest expense		(11,422	)		(10,836	)		(11,787	)
Interest income		258			725			884
AFUDC - equity		5,831			3,605			601
Other expense		-			(47	)		-
Other income		1,971			227			252
Total other expense		(3,362	)		(6,326	)		(10,050	)

Income from continuing operations before income taxes		31,443			32,310			37,464
Income tax expense		(8,304	)		(9,551	)		(12,568	)

Net income	$	23,139		$	22,759		$	24,896

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

BLACK HILLS POWER, INC.

BALANCE SHEETS

At December 31,	2009			2008
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,709		$	4
Receivables – customers, net		19,991			23,881
Receivables – affiliates, net		4,146			12,619
Other receivables, net		5,293			2,111
Money pool note receivable		57,737			-
Materials, supplies and fuel		18,825			19,309
Regulatory assets, current		7,467			4,382
Other current assets		1,639			1,348
Total current assets		116,807			63,654
Investments		4,197			3,999
Property, plant and equipment		950,577			843,691
Less accumulated depreciation and amortization		(293,823	)		(281,220	)
Total property, plant and equipment, net		656,754			562,471
Other assets:
Regulatory assets - non-current		31,305			33,818
Other, non-current assets		3,730			2,842
Total other assets		35,035			36,660
TOTAL ASSETS	$	812,793		$	666,784
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt	$	32,025		$	2,016
Accounts payable		24,175			26,567
Accounts payable - affiliate		10,030			10,411
Notes payable - affiliate		-			70,184
Accrued liabilities		17,892			15,083
Regulatory liability, current		1,238			68
Deferred income tax liability - current		1,853			732
Total current liabilities		87,213			125,061

Long-term debt, net of current maturities		297,044			149,193

Deferred credits and other liabilities:
Deferred income tax liability - non-current		96,207			85,504
Regulatory liabilities, non-current		14,955			13,573
Benefit plan liabilities		28,224			29,904
Other, non-current liabilities		10,952			8,626
Total deferred credits and other liabilities		150,338			137,607
Commitments and contingencies (Notes 4, 5, 9 and 12)
Stockholder's equity:
Common stock $1 par value; 50,000,000 shares authorized; Issued: 23,416,396 shares in 2009 and 2008		23,416			23,416
Additional paid-in capital		39,575			39,575
Retained earnings		216,420			193,281
Accumulated other comprehensive loss		(1,213	)		(1,349	)
Total stockholder's equity		278,198			254,923
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	812,793		$	666,784

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

BLACK HILLS POWER, INC.

STATEMENTS OF CASH FLOWS

Years ended December 31,	2009			2008			2007
	(in thousands)
Operating activities:
Net income	$	23,139		$	22,759		$	24,896
Adjustments to reconcile net income to net cash provided by operating activities -
Depreciation and amortization		19,465			20,930			20,763
Provision for valuation allowances		(111	)		(18	)		138
Deferred income taxes		11,600			16,072			3,864
AFUDC - equity		(5,831	)		(3,605	)		(601	)
Other non-cash		351			434			965
Change in operating assets and liabilities -
Accounts receivable and other current assets		13,233			(11,909	)		(11,257	)
Accounts payable and other current liabilities		2,556			7,821			(6,151	)
Regulatory assets		(2,205	)		(738	)		6,471
Regulatory liabilities		586			(518	)		441
Other operating activities		3,375			736			(5,413	)
Net cash provided by operating activities		66,158			51,964			34,116

Investing activities:
Property, plant and equipment additions		(146,148	)		(132,247	)		(34,043	)
Proceeds from sale of ownership interest in plant		32,783			-			-
Notes receivable from affiliate companies, net		(82,737	)		10,304			2,960
Other investing activities		1,067			(225	)		(222	)
Net cash used in investing activities		(195,035	)		(122,168	)		(31,305	)

Financing activities:
Note payable to affiliate companies, net		(45,184	)		70,184			-
Long-term debt issuance		180,000			-			-
Long-term debt - repayments		(2,140	)		(2,009	)		(2,001	)
Other financing activities		(2,094	)		-			-
Net cash provided by (used in) financing activities		130,582			68,175			(2,001	)

Increase (decrease) in cash and cash equivalents		1,705			(2,029	)		810

Cash and cash equivalents:
Beginning of year		4			2,033			1,223
End of year	$	1,709		$	4		$	2,033

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

BLACK HILLS POWER, INC.

STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

AND COMPREHENSIVE INCOME

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

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
Comprehensive Income:
Net income		-		-		-		23,139			-			23,139
Other comprehensive income, net of tax, (see Note 8)		-		-		-		-			136			136
Total comprehensive income		-		-		-		23,139			136			23,275

Balance at December 31, 2009		23,416	$	23,416	$	39,575	$	216,420		$	(1,213	)	$	278,198

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

NOTES TO FINANCIAL STATEMENTS

December 31, 2009, 2008 and 2007

(1)	BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. (the Company) is an electric utility serving customers in South Dakota, Wyoming and Montana. We are 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 our ownership interests in the assets, liabilities and expenses of our jointly owned facilities (Note 3). Certain prior years' data presented in the financial statement have been reclassified to conform to the current year presentation. The Balance Sheet has been modified to reflect "Regulatory assets, current," which had been previously included in Other current assets and "Regulatory liabilities, current," which was previously included in Accrued liabilities. The Statement of Cash Flows for December 31, 2008 and 2007 has been modified within Net cash provided by operating activities to reflect "Regulatory assets," which was previously included in Other operating activities and "Regulatory liabilities," which was previously included in Other operating activities. The Statement of Cash Flows for December 31, 2008 and 2007 has been modified within Net cash provided by operating activities to reflect “Other non-cash” which was previously included in Other operating activities.

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

Our 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.

Our regulated utility operations follow accounting standards for regulated operations and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating our electric operations. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply to our regulated generation operations. In the event we determine that we no longer meet the criteria for following accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations in an amount that could be material.

As of December 31, 2009 and 2008, we had $22.6 million and $24.6 million, respectively, in net regulatory assets for which we recover the costs, but we do not earn a return.

On December 31, 2009 and 2008, we had the following regulatory assets and liabilities (in thousands):

	Recovery Period	2009		2008

Regulatory assets:
Unamortized loss on reacquired debt	14 years	$	2,207	$	2,367
AFUDC	Up to 45 years		7,579		4,995
Defined benefit postretirement plans	Up to 17 years		21,024		26,256
Deferred energy costs	Less than one year		7,467		4,382
Other			495		200
Total regulatory assets		$	38,772	$	38,200

Regulatory liabilities:
Cost of removal for utility plant	Up to 53 years	$	13,678	$	11,705
Other			2,515		1,936
Total regulatory liabilities		$	16,193	$	13,641

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 our electric utility rates. Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Balance Sheet. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current 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, 2009, 2008 and 2007 was $10.2 million, $6.2 million and $0.9 million, respectively. The equity component of AFUDC for 2009, 2008 and 2007 was $5.8 million, $3.6 million and $0.6 million, respectively. The borrowed funds component of AFUDC for 2009, 2008 and 2007 was $4.4 million, $2.6 million and $0.3 million, respectively. The equity component of AFUDC is included in Other income, and the borrowed funds component of AFUDC is netted in Interest expense on the accompanying Statements of Income.

Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Allowance for Doubtful Accounts

We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade receivables allowances by considering such factors as historical experience, credit-worthiness, the age of the receivable balances and current economic conditions that may affect the ability to pay.

Following is a summary of receivables at December 31 (in thousands):

	2009			2008

Accounts receivable trade	$	14,703		$	18,860
Unbilled revenues		5,547			5,391
Total accounts receivable – customers		20,250			24,251
Allowance for doubtful accounts		(259	)		(370	)
Net accounts receivable	$	19,991		$	23,881

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, 2009 and 2008, 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 2.8% in 2009, 3.2% in 2008 and 3.1% in 2007. Based on a rate study, the new composite rate of 2.8% went into effect August 2009.

Derivatives and Hedging Activities

From time to time we utilize risk management contracts including forward purchases and sales and fixed-for-float swaps to hedge the price of fuel for our combustion turbines, maximize the value of our natural gas storage or fix the interest on our variable rate debt. Contracts that qualify as derivatives under accounting standards for derivatives, 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. Accounting standards for derivatives require that changes in the derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Accounting standards for derivatives allows hedge accounting for qualifying fair value and cash flow hedges. 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 should be recognized currently in earnings in the same accounting period. Conversely, the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument should 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.

Impairment of Long-Lived Assets

We periodically evaluate whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of our long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, we 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, we would recognize an impairment loss. No impairment loss was recorded during 2009, 2008 or 2007.

Income Taxes

We use 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. We classify deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.

We file 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 Standards

FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles, ASC 105

On July 1, 2009, the FASB Accounting Standards CodificationTM became the source of authoritative GAAP recognized by the FASB to be applied by non-governmental entities. On the effective date of this Statement, the Codification superseded all then-existing non-SEC accounting and reporting standards. All other non-SEC accounting literature not included or grandfathered in the Codification became non-authoritative. This Statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009.

Following this Statement, the FASB will not issue new standards in the form of Statements, FASB Staff Positions, or Emerging Task Force Abstracts. Instead, it will issue Accounting Standards Updates. The FASB will not consider Accounting Standards Updates as authoritative in their own right. Accounting Standards Updates will serve only to update the Codification, provide background information about the guidance, and provide the basis for conclusions on the change(s) in the Codification.

Business Combinations, ASC 805

The ASC for Business Combinations requires that the acquisition method of accounting be used for all business combinations and for an acquirer to be identified for each business combination. It also establishes principles and requirements for how the acquirer (i) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree, (ii) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and (iii) discloses the nature and financial effects of the business combination; and requires restructuring and acquisition-related costs to be expensed. In addition, if income tax liabilities are settled for an amount other than as previously recorded, such adjustments could affect income tax expense in the period of adjustment. Effective January 1, 2009, any impact the standard will have on our consolidated financial statements will depend on the nature and magnitude of any future acquisitions we consummate including any tax-related adjustments.

Derivative and Hedging, ASC 815

The ASC for Derivative and Hedging Disclosures includes requirements for enhanced disclosures about derivative and hedging activities and their affect on an entity's financial position, financial performance and cash flows. Accounting standards for derivatives and hedging encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption. Required disclosures for periods subsequent to January 1, 2009 are provided in Note 4.

Fair Value Measurements and Disclosures, ASC 820

The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement. We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives.

Financial Instruments, ASC 825

The ASC for Financial Instruments requires public companies to provide more frequent disclosures about the fair value of their financial instruments for interim and annual periods ending after June 15, 2009. These disclosures are included in Note 6.

Subsequent Events, ASC 855

The ASC for Subsequent Events establishes general standards of accounting for and disclosures of events that occur after the balance sheet date, but before financial statements are issued or are available to be issued. These standards and disclosures were applied to our financial statements issued after June 15, 2009.

Employers Accounting for Defined Benefit Pension and Other Postretirement Plans, ASC 715

The ASC for Employer's Accounting for Defined Benefit Pension and Other Postretirement Plans 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. Effective for fiscal years ending after December 15, 2008, this accounting standard required the measurement of the funded status of the plan to coincide with the date of the year-end statement of financial position. Therefore, the measurement date for the funded status of our pension and other postretirement benefit plans was changed to December 31 from September 30. ASC 715 also provides guidance on an employer's disclosure about plan assets for a defined benefit pension or other postretirement plans. These disclosures are effective for fiscal years ending after December 15, 2009. See Note 9 for additional information.

Recently Issued Accounting Standards

Consolidation of Variable Interest Entities, ASC 810-10-15

In June 2009, the FASB issued a revision regarding consolidations. The revised accounting guidance requires a company to consider whether an entity that is insufficiently capitalized or is not controlled through voting should be consolidated. It will require additional disclosures about the involvement with variable interest entities and any significant changes in risk exposure due to that involvement. This standard is effective for annual periods that begin after November 15, 2009. We are currently assessing the impact that the adoption of this standard will have on our financial condition, results of operations, and cash flows.

Fair Value Measurements, ASC 820

In January 2010, the FASB issued guidance related to improving disclosures about fair value measurements. The guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3, fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods and were effective for the Company on January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. The guidance will require additional disclosures, but will not impact our financial position or results of operations.

(2)	PROPERTY, PLANT AND EQUIPMENT

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

	2009		2009 Weighted Average Useful Life		2008		2008 Weighted Average Useful Life		Lives (in years)
Electric plant:
Production	$	336,534		53	$	326,606		47		30-62
Transmission		86,841		44		70,470		45		35-55
Distribution		264,847		37		249,652		37		15-65
Plant acquisition adjustment		4,870		32		4,870		32		32
General		55,701		22		47,127		23		10-50
Total electric plant		748,793				698,725
Less accumulated depreciation and amortization		293,823				281,220
Electric plant net of accumulated depreciation and amortization		454,970				417,505
Construction work in progress		201,784				144,966
Net electric plant	$	656,754			$	562,471

(3)	JOINTLY OWNED FACILITIES

We use the proportionate consolidation method to account for our percentage interest in the assets, liabilities and expenses of the following facilities:

We own 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. We receive 20% of the Plant's capacity and are committed to pay 20% of its additions, replacements and operating and maintenance expenses. As of December 31, 2009 and 2008, our investment in the Plant included $79.8 million and $79.1 million, respectively, in electric plant and $52.2 million and $50.8 million, respectively, in accumulated depreciation, and is included in the corresponding captions in the accompanying Balance Sheets. Our share of direct expenses of the Plant was $8.0 million, $8.0 million and $7.3 million for the years ended December 31, 2009, 2008 and 2007, respectively, and is included in the corresponding categories of operating expenses in the accompanying Statements of Income.

We also own 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 us 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. We are committed to pay 35% of the additions, replacements and operating and maintenance expenses. Our share of direct expenses was $0.1 million for each of the years ended December 31, 2009, 2008 and 2007. As of December 31, 2009 and 2008, our investment in the transmission tie was $19.6 million and $19.8 million, with $3.8 million and $2.5 million, respectively, of accumulated depreciation and is included in the corresponding captions in the accompanying Balance Sheets.

The Balance Sheet includes our ownership interest in the assets and liabilities of the Wygen III facility currently under construction. We own 75% of Wygen III and MDU owns 25%. Wygen III is expected to commence operations by April 1, 2010. Included in the December 31, 2009 Balance Sheet in Construction Work in Progress was $175.6 million. During 2009, we were reimbursed $48.4 million for the construction. Our share of direct expenses of the jointly-owned facility is included in Operating expenses in the Statements of Income.

(4)	RISK MANAGEMENT

We hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we utilize various derivative instruments in managing these risks. As of December 31, 2008, there were no derivative contracts outstanding. As of December 31, 2009, we had the following derivatives and related balances included in Accrued liabilities on the accompanying Balance Sheet (dollars, in thousands):

	Natural Gas Swaps

Notional*		232,500
Maximum terms in months		10
Current derivative liabilities	$	5
Pre-tax accumulated other comprehensive loss	$	(5	)

___________________________

*	Gas in MMbtus.

(5)	LONG-TERM DEBT

Long-term debt outstanding at December 31 is as follows (in thousands):

	2009			2008
First mortgage bonds:
8.06% due 2010	$	30,000		$	30,000
9.49% due 2018		2,520			2,810
9.35% due 2021		19,980			21,645
7.23% due 2032		75,000			75,000
6.125% due 2039		180,000			-
Unamortized discount on 6.125% bonds		(124	)		-
		307,376			129,455
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		3,043			3,104
		21,693			21,754

Total long-term debt		329,069			151,209
Less current maturities		(32,025	)		(2,016	)
Net long-term debt	$	297,044		$	149,193

On October 27, 2009, we completed a $180 million first mortgage bond issuance. The bonds were priced at 99.931% of par and a reoffer yield of 6.13%. The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which is scheduled to be paid semi-annually. We received proceeds net of underwriting fees of $178.3 million which were used to repay intercompany borrowings from BHC, primarily incurred to fund the construction of Wygen III. Deferred finance costs of approximately $2.2 million were capitalized and will be amortized over the term of the bonds.

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

Scheduled maturities are approximately $32.0 million in 2010; $2.0 million a year for the years 2011, 2012 and 2013; $8.4 million in 2014; and $282.7 million thereafter.

(6)	FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at December 31 are as follows (in thousands):

	2009				2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Cash and cash equivalents	$	1,709	$	1,709	$	4	$	4
Derivative financial instruments – accrued liabilities	$	5	$	5	$	-	$	-
Long-term debt, including current maturities	$	329,069	$	344,942	$	151,209	$	144,107

The following methods and assumptions were used to estimate the fair value of each class of our 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 we use are included in Note 4.

Long-Term Debt

The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings. Our outstanding first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits for us 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):

	2009			2008			2007

Current	$	(3,296	)	$	(6,521	)	$	8,704
Deferred		11,600			16,072			3,864
Total income tax expense	$	8,304		$	9,551		$	12,568

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

Years ended December 31,	2009		2008

Deferred tax assets, current:
Asset valuation reserve	$	90	$	129
Employee benefits		946		932
Other		2		-
Total deferred tax assets, current		1,038		1,061

Deferred tax liabilities, current:
Prepaid expenses		214		213
Deferred costs		2,677		1,580
Total deferred tax liabilities, current		2,891		1,793

Net deferred tax liability, current	$	1,853	$	732

Deferred tax assets, non-current:
Plant related differences	$	1,151	$	1,151
Regulatory liabilities		7,847		10,156
Employee benefits		3,468		3,528
Items of other comprehensive income		175		227
Research and development credit		1,038		-
Other		128		128
Total deferred tax assets, non-current		13,807		15,190

Deferred tax liabilities, non-current:
Accelerated depreciation and other plant related differences		93,253		83,112
AFUDC		4,926		3,247
Regulatory assets		10,011		11,270
Employee benefits		1,052		2,237
Other		772		828
Total deferred tax liabilities, non-current		110,014		100,694

Net deferred tax liability, non-current	$	96,207	$	85,504

Net deferred tax liability	$	98,060	$	86,236

The following table reconciles the change in the net deferred income tax liability from December 31, 2008, to December 31, 2009, to the deferred income tax expense (in thousands):

	2009			2008

Increase in deferred income tax liability from the preceding table	$	11,824		$	16,457
Deferred taxes related to regulatory assets and liabilities		(1,323	)		(1,200	)
Deferred taxes associated with other comprehensive income		(73	)		38
Deferred taxes related to property basis differences		2,851			767
Deferred taxes related to AFUDC		(1,679	)		-
Other		-			10
Deferred income tax expense for the period	$	11,600		$	16,072

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

	2009			2008			2007

Federal statutory rate		35.0	%		35.0	%		35.0	%
Amortization of excess deferred and investment tax credits		(0.9	)		(0.7	)		(1.0	)
Equity AFUDC		(6.2	)		(3.6	)		-
Other		(1.5	)		(1.1	)		(0.5	)
		26.4	%		29.6	%		33.5	%

We adopted the accounting standards for uncertain tax positions on January 1, 2007 which clarifies the accounting for uncertainty in income taxes recognized in an enterprise's financial statements in accordance with accounting standards for income taxes. The accounting standards prescribe a recognition threshold and measurement attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken. The impact of this implementation had no effect on our financial statements.

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

	2009		2008

Unrecognized tax benefits at January 1	$	767	$	-
Additions for prior year tax positions		3,110		-
Additions for current year tax positions		-		767

Unrecognized tax benefits at December 31	$	3,877	$	767

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.3 million.

It is our continuing practice to recognize interest and/or penalties related to income tax matters in income tax expense. During the year ended December 31, 2009, the interest expense recognized was not material to our financial results.

We file income tax returns in the United States federal jurisdiction. We do 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, 2010.

(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):

	2009

	Pre-tax Amount				Tax (Expense) Benefit				Net-of-tax Amount

Pension liability adjustment		$	150			$	(52	)		$	98
Reclassification adjustments of cash flow hedges settled and included in net income			64				(24	)			40
Net change in fair value of derivatives designated as cash flow hedges			(5	)			3				(2	)
Other comprehensive income		$	209			$	(73	)		$	136

	2008

	Pre-tax Amount				Tax Benefit			Net-of-tax Amount

Pension liability adjustment		$	(4	)		$	1		$	(3	)
Reclassification adjustments of cash flow hedges settled and included in net income			(107	)			38			(69	)
Other comprehensive loss		$	(111	)		$	39		$	(72	)

	2007

	Pre-tax Amount				Tax (Expense) Benefit				Net-of-tax 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	)
Other comprehensive loss		$	(530	)		$	185			$	(345	)

Balances by classification included within Accumulated other comprehensive loss on the accompanying Balance Sheets at December 31 are as follows (in thousands):

	2009			2008

Derivatives designated as cash flow hedges	$	(893	)	$	(932	)
Employee benefit plans		(320	)		(417	)
Total accumulated other comprehensive loss	$	(1,213	)	$	(1,349	)

(9)	EMPLOYEE BENEFIT PLANS

Funded Status of Benefit Plans

The funded status of postretirement benefit plans is required to be recognized 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.

We apply accounting standards for regulated operations, and accordingly, the unrecognized net periodic benefit cost that would have been reclassified to Accumulated other comprehensive income (loss) was alternatively recorded as a regulatory asset or regulatory liability, net of tax.

The measurement date of plans should be the date of our year-end balance sheet. We had used a September 30 measurement date. During 2008, we changed the measurement date to December 31. Therefore, $0.2 million, net of tax, was recognized as an adjustment to retained earnings.

Defined Benefit Pension Plan

We have a noncontributory defined benefit pension plan (Plan) covering the employees 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. Our 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. We use a December 31 measurement date for the Plan.

In July 2009, the Board of Directors approved a freeze to our Defined Benefit Pension Plan (with the exception of bargaining unit participants). The freeze is effective January 1, 2010 and eliminates new non-bargaining unit employees from participation in the plan, and freezes the benefits of current non-bargaining unit participants except for the following group: those non-bargaining participants who are both 1) are age 45 or older as of December 31, 2009 and have 10 years or more of credited service as of January 1, 2010; and 2) elect to continue to accrue additional benefits under the pension plan and consequently forego the additional age- and points-based employer contribution under our 401(k) retirement savings plan. Plan assets and obligations were revalued July 31, 2009 in conjunction with the freeze, and we recognized a pre-tax curtailment expense of approximately $0.2 million in the third quarter of 2009.

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 adjusted long-term historical returns for the asset class. 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 2009 and 2008 plan years. For determining the expected long-term rate of return for equity assets, we reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2009, 8.1%, 11.1%, 9.7% and 9.3%, 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 6.9% from 1962 to 2009, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 1.0%, which was based upon current one-year LIBOR rates.

Plan Assets

Percentage of fair value of Plan assets at December 31:

	2009	2008

Equity	72%	68%
Fixed income	25	28
Cash	3	4
Total	100%	100%

The Investment Policy for the Pension Plans is to seek to achieve the following long-term objectives: 1) a rate of return in excess of the annualized inflation rate based on a five-year moving average; 2) a rate of return that meets or exceeds the assumed actuarial rate of return that meets or exceeds the assumed actuarial rate of return as stated in the Plan’s actuarial report; 3) a rate of return on investments, net of expenses, that is equal to or exceeds various benchmark rates on a moving three-year average, and 4) maintenance of sufficient income and liquidity to pay monthly retirement benefits. The policy strategy seeks to prudently invest in a diversified portfolio of predominately equity and fixed income assets.

The policy contains certain prohibitions on transactions in separately managed portfolios in which the Plan may invest, including prohibitions on short sales.

Cash Flows

We made no contributions to the Plan in 2009 and expect no contributions to the Plan in 2010.

Supplemental Non-qualified Defined Benefit Retirement Plans

We have various supplemental retirement plans for key executives. The Plans are non-qualified defined benefit plans. We use a December 31 measurement date for the Plans. Effective January 1, 2010, we eliminated a non-qualified pension plan in which some of our officers participated due to the partial freeze of our qualified pension plans. We also amended the NQDC, which was adopted in 1999. The NQDC is a non-qualified deferred compensation plan that provides executives with an opportunity to elect to defer compensation and receive benefits without reference to the limitations on contributions in the Plan or those imposed by the IRS. The amended NQDC provides for non-elective non-qualified restoration benefits to certain officers who are not eligible to continue accruing benefits under the Defined Benefit Pension Plans and associated non-qualified pension restoration plans. All contributions to the non-qualified plans are subject to a graded vesting schedule of 20% per year over five years with vesting credit beginning with service in the Plan on and after January 1, 2010.

Plan Assets

The Plan has no assets. We fund on a cash basis as benefits are paid.

Estimated Cash Flows

The estimated employer contribution is expected to be $0.1 million in 2010. Contributions are expected to be made in the form of benefit payments.

Non-pension Defined Benefit Postretirement Plan

Employees who are participants in our Postretirement Healthcare Plan and who retire on or after attaining age 55 after completing at least five years of service are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. We may amend or change the Plan periodically. We are not pre-funding our retiree medical plan. We use a December 31 measurement date for the Plan. In July 2009, the Board of Directors approved a freeze to the Plan which changed the structure of the Plan for non-union employees to a Retiree Medical Savings Account structure and expanded eligibility of Plan participants, effective January 1, 2010.

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, 2009, was an actuarial gain of approximately $0.9 million. The effect on 2009 net periodic postretirement benefit cost was a decrease of approximately $0.1 million.

Plan Assets

The Plan has no assets. We fund on a cash basis as benefits are paid.

Estimated Cash Flows

The estimated employer contributions are expected to be $0.4 million in 2010. Contributions are expected to be made in the form of benefit payments.

Fair Value Measurements

Accounting standards for fair value measurements provide a single definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and also requires disclosures and establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The fair value hierarchy ranks the quality and reliability of the information used to determine fair values giving the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and the lowest priority to unobservable inputs (level 3 measurements). The pension plan is able to classify fair value balances based on the observability of inputs.

Financial assets and liabilities carried at fair value are classified and disclosed in one of the following three categories:

Level 1 – Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities.

Level 2 – Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources.

As required by accounting standards for fair value measurements, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis as of December 31, 2009 and 2008 (in thousands):

Defined Benefit Pension Plan	At Fair Value as of December 31, 2009
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total

Registered Investment Companies	$	22,632	$	-	$	-	$	22,632
Common Collective Trust		-		16,408		-		16,408
Total investments measured at fair value	$	22,632	$	16,408	$	-	$	39,040

Defined Benefit Pension Plan	At Fair Value as of December 31, 2008
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Total

Registered Investment Companies	$	17,976	$	-	$	-	$	17,976
Common Collective Trust		-		14,124		-		14,124
Total investments measured at fair value	$	17,976	$	14,124	$	-	$	32,100

Plan Reconciliations

The following tables provide a reconciliation of the Employee Benefit Plan's obligations and fair value of assets for 2009 and 2008, components of the net periodic expense for the years ended 2009, 2008 and 2007 and elements of regulatory assets and liabilities and AOCI for 2009 and 2008 (in thousands):

Benefit Obligations

	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2009			2008			2009			2008			2009			2008
Change in benefit obligation:

Projected benefit obligation at beginning of year	$	51,965		$	48,937		$	1,672		$	1,958		$	7,393		$	6,649
Service cost		1,155			1,396			-			-			216			264
Interest cost		3,143			3,790			100			150			444			522
Actuarial loss		1,686			2,712			7			65			3,474			506
Amendments		100			-			-			-			(1,960	)		-
Discount rate change		1,047			-			-			-			-			-
Benefits paid		(2,312	)		(2,838	)		(89	)		(142	)		(579	)		(830	)
Asset transfer to affiliate		(121	)		(2,032	)		-			(359	)		(23	)		(297	)
Plan curtailment reduction		(1,048	)		-			-			-			-			-
Medicare Part D adjustment		-			-			-			-			46			71
Plan participant's contributions		-			-			-			-			421			508
Net increase (decrease)		3,650			3,028			18			(286	)		2,039			744
Projected benefit obligation at end of year	$	55,615		$	51,965		$	1,690		$	1,672		$	9,432		$	7,393

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

	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans				Non-pension Defined Benefit Postretirement Plans
	2009			2008			2009		2008		2009		2008

Beginning market value of plan assets	$	32,100		$	52,466		$	-	$	-	$	-	$	-
Investment income (loss)		9,337			(8,771	)		-		-		-		-
Benefits paid		(2,312	)		(2,249	)		-		-		-		-
Asset transfer to affiliate		(85	)		-			-		-		-		-
Ending market value of plan assets	$	39,040		$	41,446		$	-	$	-	$	-	$	-

Amounts recognized in the statement of financial position consist of (in thousands):

	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2009			2008			2009			2008			2009			2008

Regulatory asset (liability)	$	19,580		$	26,256		$	-		$	-		$	1,443		$	(11	)
Current liability	$	-		$	-		$	98		$	109		$	325		$	223
Non-current liability	$	(16,576	)	$	(19,864	)	$	(1,592	)	$	(1,564	)	$	(9,110	)	$	(7,169	)

Accumulated Benefit Obligation

	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2009			2008			2009			2008			2009			2008

Accumulated benefit obligation		$	47,745		$	43,894		$	1,645		$	1,622		$	9,432		$	7,393

Components of Net Periodic Expense

	Defined Benefit Pension Plans									Supplemental Nonqualified Defined Benefit Retirement Plans						Non-pension Defined Benefit Postretirement Plans
	2009			2008			2007			2009		2008		2007		2009		2008			2007

Service cost	$	1,155		$	1,117		$	1,137		$	-	$	-	$	-	$	216	$	211		$	211
Interest cost		3,143			3,032			2,923			100		120		116		444		417			398
Expected return on assets		(2,780	)		(4,374	)		(3,885	)		-		-		-		-		-			-
Amortization of prior service cost		87			112			103			-		1		1		-		-			-
Amortization of transition obligation		-			-			-			-		-		-		51		51			51
Recognized net actuarial loss (gain)		1,586			-			408			43		44		57		-		(1	)		-
Curtailment expense		189			-			-			-		-		-		-		-			-
Net periodic expense	$	3,380		$	(113	)	$	686		$	143	$	165	$	174	$	711	$	678		$	660

Accumulated Other Comprehensive Income (Loss)

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 (in thousands):

	Defined Benefit Pension Plans						Supplemental Nonqualified Defined Benefit Retirement Plans								Non-pension Defined Benefit Postretirement Plans
	2009			2008			2009				2008				2009			2008

Net loss		$	-		$	-		$	(324	)		$	(347	)		$	-		$	-
Prior service cost			-			-			-				(1	)			-			-
Transition obligation			-			-			-				-				-			-
		$	-		$	-		$	(324	)		$	(348	)		$	-		$	-

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 2010 are as follows (in thousands):

	Defined Benefits Pension Plans		Supplemental Nonqualified Defined Benefit Retirement Plans		Non-pension Defined Benefit Postretirement Plans

Net loss	$	895	$	20	$	111
Prior service cost		41		-		(91	)
Transition obligation		-		-		-
Total net periodic benefit cost expected to be recognized during calendar year 2010	$	936	$	20	$	20

Assumptions

	Defined Benefit Pension Plans			Supplemental Nonqualified Defined Benefit Retirement Plans			Non-pension Defined Benefit Postretirement Plans

Weighted-average assumptions used to determine benefit obligations:	2009	2008	2007	2009	2008	2007	2009	2008	2007

Discount rate	6.05%	6.20%	6.35%	6.10%	6.20%	6.35%	5.90%	6.10%	6.35%
Rate of increase in compensation levels	4.25%	4.25%	4.34%	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:	2009	2008	2007	2009	2008	2007	2009	2008	2007

Discount rate	6.25%	6.35%	5.95%	6.20%	6.35%	5.95%	6.10%	6.35%	5.95%
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	4.25%	4.34%	4.31%	5.00%	N/A	5.00%	N/A	N/A	N/A

_____________________________

*	The expected rate of return on plan assets changed to 8.00% for the calculation of the 2010 net periodic pension cost.

The healthcare cost trend rate assumption for 2009 fiscal year benefit obligation determination and 2010 fiscal year expense is a 10% increase for 2009 grading down until a 4.5% ultimate trend rate is reached in fiscal year 2027. The healthcare cost trend rate assumption for the 2008 fiscal year benefit obligation determination and 2009 fiscal year expense was 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 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 22% and the accumulated periodic postretirement benefit obligation $1.3 million or 14%. A 1% decrease would reduce the service and interest cost by $0.1 million or 17% and the accumulated periodic postretirement benefit obligation $1.0 million or 11%.

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

					Non-pension Defined Benefit Postretirement Plans
	Defined Benefit Pension Plans		Supplemental Nonqualified Defined Benefit Retirement Plan		Expected Gross Benefit Payments		Expected Medicare Part D Drug Benefit Subsidy			Expected Net Benefit Payments

2010	$	2,584	$	98	$	405	$	(80	)	$	325
2011		2,743		112		486		(86	)		400
2012		2,833		94		544		(94	)		450
2013		2,975		77		585		(101	)		484
2014		3,152		93		628		(107	)		521
2015-2019		18,086		557		3,683		(624	)		3,059

Defined Contribution Plan

The Parent sponsors a 401(k) retirement savings plan in which employees may participate. Participants may elect to invest up to 50% of their eligible compensation on a pre-tax basis, up to a maximum amount established by the Internal Revenue Service. We provide 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. Our matching contributions were $0.7 million for 2009, $0.7 million for 2008 and $0.6 million for 2007.

Effective January 1, 2010 in conjunction with the partial freeze of our defined benefit pension plan, we amended our 401(k) Retirement Savings Plan. This freeze covers all employees with the exception of the bargaining unit employees and certain other employees grandfathered under a prior defined benefit plan election. The amendment provides for a matching contribution of 100% of the eligible employee's annual contribution up to a maximum of 6% of eligible compensation. The amendment also provides certain eligible participants an age and service-based employer contribution.

(10)	RELATED-PARTY TRANSACTIONS

Receivables and Payables

We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $4.1 million and $12.6 million as of December 31, 2009 and 2008, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. The balances were $10.0 million and $10.4 million as of December 31, 2009 and 2008, respectively.

Money Pool Notes Receivable and Notes Payable

We have a Utility Money Pool Agreement with the Parent, Cheyenne Light and Black Hills Utility Holdings. Under the agreement, we may borrow from the Parent. The Agreement restricts us from loaning funds to the Parent or to any of the Parent's non-utility subsidiaries; the Agreement does not restrict us 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.

Through the Utility Money Pool, we have a net note receivable balance to the Parent of $57.7 million as of December 31, 2009 and a net note payable balance of $70.2 million as of December 31, 2008. Advances under this note bear interest at 0.70% above the daily LIBOR rate (0.93% at December 31, 2009). Net interest expense of $1.1 million and $0.9 million was recorded for the years ended December 31, 2009 and 2008, respectively. During 2007, we had a note receivable of $10.3 million for which we received $0.9 million of interest income.

Other Balances and Transactions

We received revenues of approximately $0.9 million, $1.2 million and $1.9 million for the years ended December 31, 2009, 2008 and 2007, respectively, from Black Hills Wyoming, Inc. for the transmission of electricity.

We received revenues of approximately $1.8 million and $2.8 million for the years ended December 31, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.

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

We purchase coal from WRDC. The amount purchased during the years ended December 31, 2009, 2008 and 2007 was $16.3 million, $15.5 million and $12.6 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.

We purchase excess power generated by Cheyenne Light. The amount purchased during the years ended December 31, 2009 and 2008 was $8.6 million and $6.4 million, respectively.

In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the years ended December 31, 2009, 2008 and 2007 was approximately $2.3 million, $8.0 million and $4.5 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.

In addition, we also pay the Parent for allocated corporate support service cost incurred on our behalf. Corporate costs allocated from the Parent were $15.0 million, $12.4 million and $11.3 million for the years ended December 31, 2009, 2008 and 2007, respectively.

We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0 million and $1.9 million at December 31, 2009 and 2008, 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 (3.25% at December 31, 2009). We paid interest expense of $0.1 million for each of the years ended December 31, 2009, 2008 and 2007, respectively.

We have two contracts with Cheyenne Light under which Cheyenne Light sells up to 40 MW of wind-generated, renewable energy to us. Purchases from these agreements during 2009 were $2.8 million and $0.6 million in 2008.

(11)	SUPPLEMENTAL CASH FLOWS INFORMATION

Years ended December 31,	2009			2008			2007
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment financed with accrued liabilities	$	10,191		$	13,294		$	1,323
Distribution to Parent	$	225,000		$	-		$	-
Borrowing from Parent	$	200,000		$	-		$	-

Supplemental disclosure of cash flow information:
Cash paid during the period for -
Interest (net of amounts capitalized)	$	14,252		$	11,578		$	11,782
Income taxes (refunded) paid	$	(3,700	)	$	(5,877	)	$	17,284

(12)	COMMITMENTS AND CONTINGENCIES

Partial Sale of Wygen III to MDU

On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility currently under construction. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. Proceeds of $32.8 million were received of which $30.2 million was used to pay down a portion of the Acquisition Facility. MDU will continue to reimburse us for its 25% of the total costs paid to complete the project. In conjunction with the sales transaction, we also modified a 2004 PPA between us and MDU.

Power Purchase and Transmission Services Agreements

We have the following purchase power and transmission agreements as of December 31, 2009:

A PPA with PacifiCorp expiring in 2023, which provides for the purchase by us of 50 MW of electric capacity and energy. 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 $11.8 million in 2009, $11.6 million in 2008 and $10.9 million in 2007.

A firm point-to-point transmission access agreement to deliver up to 50 MW of power on PacifiCorp's transmission system to wholesale customers in the western region through 2023. Costs incurred under this agreement were $1.2 million in each of the years ended 2009, 2008 and 2007, respectively.

Cheyenne Light entered into a 20-year PPA with Happy Jack for 29.4 MW of energy. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 MW of energy from Happy Jack to us;

Cheyenne Light entered into a 20-year PPA with Silver Sage for 30 MW of energy. Commercial operations commenced on October 1, 2009. Under a separate inter-company agreement, Cheyenne Light has agreed to sell 20 MW of energy from Silver Sage to us; and

A Generation Dispatch Agreement with Cheyenne Light that requires us to purchase all of Cheyenne Light's excess energy.

Long-Term Power Sales Agreements

We have the following power sales agreements as of December 31, 2009:

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. This contract is integrated into our control area and is treated as part of our firm native load. As of December 31, 2009, neither party to the agreement had given notice of termination;

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 exercised its option to participate in the ownership of the Wygen III plant that is currently being constructed. Under an agreement entered into in April 2009, MDU purchased a 25% undivided interest in the Wygen III plant. We retain responsibility for operations of the facility with a life-of-plant lease and agreements with MDU for operations and coal supply. In conjunction with the sales transaction, we also modified the 2004 PPA under which we supplied MDU with 74 MW of capacity and energy through 2016. The PPA with MDU will be supplied from its ownership interest in Wygen III. During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with its first 25 MW from our other generation facilities or from system purchases; and

2010-2017 20 MW - 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II

2018-2019 15 MW - 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

2020-2021 12 MW - 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II

2022-2023 10 MW - 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II; and

A five-year PPA with MEAN which commences the month following the onset of commercial operations of Wygen III. Under this contract, MEAN will purchase 5 MW of unit-contingent capacity from Neil Simpson II and 5 MW of unit-contingent capacity from Wygen III.

Legal Proceedings

Ongoing Litigation

We are 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 our financial position, results of operations or cash flows.

(13)	QUARTERLY HISTORICAL DATA (Unaudited)

We operate on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter of 2009 and 2008 (in thousands):

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2009:
Operating revenues	$	54,458	$	46,836	$	53,086	$	52,699
Operating income		10,705		5,006		8,920		10,174
Net income		6,964		3,105		7,166		5,904

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

(14)	SUBSEQUENT EVENT

In February 2010, we provided notice to the bondholders of our intent to call the BHP Series Y bonds in full. These bonds were originally due in 2018. The balance of $2.5 million plus an early redemption premium of 2.6% will be paid on March 31, 2010.

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, 2009. 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 26 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.

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, 2009, 2008 and 2007.

		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, 2009, 2008 AND 2007

Additions

Description	Balance at beginning of year			Charged to costs and expenses			Deductions			Balance at end of year
	(in thousands)
Allowance for doubtful accounts:
2009		$	370		$	316		$	(427)		$	259
2008		$	388		$	637		$	(655)		$	370
2007		$	250		$	320		$	(182)		$	388

Exhibits

Exhibit Number	Description

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 Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

10.3*	Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

23	Independent Auditors' Consent

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.

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 10, 2010

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 10, 2010
David R. Emery, Chairman and	Principal Executive Officer
Chief Executive Officer

/s/ ANTHONY S. CLEBERG	Principal Financial and	March 10, 2010
Anthony S. Cleberg, Executive Vice President	Accounting Officer
and Chief Financial Officer

/s/ DAVID C. EBERTZ	Director	March 10, 2010
David C. Ebertz

/s/ JACK W. EUGSTER	Director	March 10, 2010
Jack W. Eugster

/s/ JOHN R. HOWARD	Director	March 10, 2010
John R. Howard

/s/ KAY S. JORGENSEN	Director	March 10, 2010
Kay S. Jorgensen

/s/ STEPHEN D. NEWLIN	Director	March 10, 2010
Stephen D. Newlin

/s/ GARY L. PECHOTA	Director	March 10, 2010
Gary L. Pechota

/s/ WARREN L. ROBINSON	Director	March 10, 2010
Warren L. Robinson

/s/ JOHN B. VERING	Director	March 10, 2010
John B. Vering

/s/ THOMAS J. ZELLER	Director	March 10, 2010
Thomas J. Zeller

INDEX TO EXHIBITS

Exhibit Number	Description

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 Exhibit 4.19 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10.1 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10.2 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

10.3*	Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10.3 to the Registrant's Post-Effective Amendment No. 1 to the Registrant's Registration Statement on Form S-3 (No. 333-150669-01)).

23	Independent Auditors’ Consent

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.

BLACK HILLS POWER INC - FORM 10-K - March 10, 2010

Attached files

BLACK HILLS POWER INC Reports