Black Hills Power 10K 2006 Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

Form 10-K

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

	For the fiscal year ended December 31, 2006

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

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

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

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.

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

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

Yes

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

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

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

Class	Outstanding at February 28, 2007
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

ITEMS 1. and 2.	BUSINESS AND PROPERTIES	3
	Safe Harbor for Forward Looking Information	3
	General	4
	Rate Regulation	7

ITEM 1A.	RISK FACTORS	8

ITEM 1B.	UNRESOLVED STAFF COMMENTS	10

ITEM 3.	LEGAL PROCEEDINGS	10

ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY AND
	RELATED STOCKHOLDER MATTERS	11

ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS
	OF OPERATIONS	11

ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	15

ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
	ON ACCOUNTING AND FINANCIAL DISCLOSURE	44

ITEM 9A.	CONTROLS AND PROCEDURES	44

ITEM 9B.	OTHER INFORMATION	45

ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	46

	SIGNATURES	48

	INDEX TO EXHIBITS	49

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 Securities and Exchange Commission, or SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-K that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including, 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 retail utility operations through regulatory proceedings and receive favorable rulings in periodic applications to recover costs for fuel and purchased power;

• The amount and timing of capital deployment in new investment opportunities or for the repurchase of debt or stock;

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

• The timing and extent of scheduled and unscheduled outages of power generation facilities;

• 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;

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

• 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 counterparty transactions;

• Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;

• Weather and other natural phenomena;

• Industry and market changes, including the impact of consolidations and changes in competition;

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

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

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

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

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

• General economic and political conditions, including tax rates or policies and inflation rates; 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, and overall performance and growth.

Distribution and Transmission

Distribution and Transmission. Our distribution and transmission businesses serve approximately 64,200 electric customers, with an electric transmission system of 447 miles of high voltage lines (greater than 69 KV) and 420 miles of lower voltage lines. In addition, we jointly own 47 miles of high voltage lines with Basin Electric Cooperative. Our service territory covers a 9,300 square mile area of western South Dakota, northeastern Wyoming and southeastern Montana with a strong and stable economic base. Approximately 91 percent of our retail electric revenues in 2006 were generated in South Dakota.

The following are characteristics of our distribution and transmission businesses:

• We have a diverse customer and revenue base. Our revenue mix for the year ended December 31, 2006 was comprised of 26 percent commercial, 21 percent residential, 13 percent contract wholesale, 22 percent wholesale off-system, 11 percent industrial and 7 percent municipal sales and other revenue. Approximately 84 percent of our large commercial and industrial customers are provided service under long-term contracts. We have historically optimized the utilization of our power supply resources by selling wholesale power to other utilities and to power marketers in the spot market and through short-term sales contracts primarily in the Western Electricity Coordinating Council (WECC) and Mid-Continent Area Power Pool (MAPP) regions.

• We are subject to regulation by the South Dakota Public Utility Commission (SDPUC), the Wyoming Public Service Commission (WPSC) and the Montana Public Service Commission (MTPSC). We operated under two consecutive retail rate freezes in South Dakota that were imposed in 1995 and expired on January 1, 2005. The rate freezes preserved a low-cost rate structure for our retail customers at levels below the national average and insulated them from changes in fuel and purchased power costs but allowed us to retain the benefits from cost savings and from wholesale “off-system” sales, which were not covered by the rate freezes. On June 30, 2006, we filed a rate case with the SDPUC to increase retail rates for South Dakota customers and to add tariff provisions for automatic adjustment of rates for changes in energy, fuel and transmission costs. The cost adjustments would require us to absorb a portion of power cost increases, depending in part on earnings on certain short-term wholesale sales of electricity. On December 28, 2006, we received an order from the SDPUC approving a 7.8 percent increase in retail rates and the addition of tariff provisions for automatic adjustments, effective January 1, 2007. 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.

• We own 35 percent and Basin Electric owns 65 percent 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 megawatts - 200 megawatts from West to East and 200 megawatts 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 megawatts 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 megawatts of power on PacifiCorp’s transmission system to wholesale customers in the Western region from 2007 through 2023.

• We have firm network transmission access to deliver power on PacifiCorp’s system to Sheridan, Wyoming to serve our power sales contract with Montana-Dakota Utilities Company (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 with MDU, which expired on December 31, 2006, for the sale of up to 55 megawatts of capacity and energy to serve the Sheridan, Wyoming electric service territory. Our new power purchase agreement with MDU, effective January 1, 2007 through the end of 2016, will supply up to 74 megawatts of capacity and energy for Sheridan, Wyoming; and

• an agreement with the City of Gillette, Wyoming, expiring in 2013, to provide the city’s first 23 megawatts of capacity and energy. The agreement renews automatically and requires a seven year notice of termination.

These consumers are integrated into our control area and considered part of our firm native load. We also provide 20 megawatts of energy and capacity to Municipal Energy Agency of Nebraska (MEAN) under a contract that expires in 2013. This contract is unit-contingent based on the availability of our Neil Simpson II plant.

Regulated Power Plants and Purchased Power. Our electric load is primarily served by our generating facilities in South Dakota and Wyoming, which provide 435 megawatts of generating capacity, with the balance supplied under purchased power and capacity contracts. Approximately 50 percent of our capacity is coal-fired, 39 percent is oil- or gas-fired, and 11 percent is supplied under the following purchased power contracts with PacifiCorp:

• a power purchase agreement expiring in 2023, involving the purchase by us of 50 megawatts of coal-fired baseload power; and

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

Since 1995, we have been a net producer of energy. We reached our peak system load of 415 megawatts in July 2006 with an average system load of 249 megawatts for the year ended December 31, 2006. 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.

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. Two consecutive rate freezes granted by the SDPUC, which were in effect for us since 1995, expired on January 1, 2005. During this ten-year term, we were prohibited, subject to certain limited exceptions, from filing for any increase in our rates or invoking any fuel and purchased power adjustment tariff which would take effect during the freeze period. On June 30, 2006, we filed an application with the SDPUC for an increase in electric rates for our South Dakota customers and to provide automatic adjustment of rates for changes in energy, fuel and transmission costs. On December 28, 2006, the SDPUC approved a rate increase of 7.8 percent along with the addition of tariff provisions which provide for the automatic adjustment of rates. The rates and new tariff provisions were effective beginning January 1, 2007. Terms of the settlement agreement with the SDPUC include the following:

• Annual cost adjustments reflecting changes in the costs of both electric transmission and fuel delivered to coal-fired power generation will be allowed, with adjustments reflected in monthly customer billings commencing in March following the year on which the calculation was made;

• Annual cost adjustments reflecting changes in the cost of natural gas used in power generation and purchased power, with adjustments, if any, reflected in monthly customer billings commencing in March following the year on which the calculation was made. We also agreed to share in such cost increases, under certain circumstances while retaining the benefits from off-system sales; and

• No additional base rate increases, with certain exceptions, for a period of three years ending December 31, 2009.

Regulatory Accounting

As it pertains to the accounting for our utility operations, we follow Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71), and our financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions in which we operate. If rate recovery becomes unlikely or uncertain, due to competition or regulatory action, these accounting standards may no longer apply to our generation operations. In the event we determine that we no longer meet the criteria for following SFAS 71, the accounting impact to us could be an extraordinary non-cash charge to operations of an amount that could be material.

New Accounting Pronouncements

See Note 1 of our Notes to Financial Statements in this Annual Report on Form 10-K for information on new accounting standards adopted in 2006 or pending adoption.

ITEM 1A. RISK FACTORS

The following specific risk factors and other risk factors that we discuss in our periodic reports from time to time should be considered for a better understanding of our Company. These factors and other matters discussed herein are important factors that could cause our actual results or outcomes to differ materially from those discussed in the forward looking statements included elsewhere in this document.

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

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

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

Our credit rating on our First Mortgage Bonds is “Baa1” by Moody’s Investors Services, Inc. (Moody’s) and “BBB” by Standard & Poor’s Rating Services (S&P). Any reduction in our ratings by Moody’s or S&P could adversely affect our ability to refinance or repay our existing debt and to complete new financings. In addition, a downgrade in our credit rating would increase our costs of borrowing under some of our existing debt obligations. A downgrade could also result in our business counterparties requiring us to provide additional amounts of collateral under new transactions.

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;

• the unavailability of equipment and labor supply;

• supply interruptions;

• work stoppages;

• labor disputes;

• social unrest;

• weather interferences;

• unforeseen engineering, environmental and geological problems; and

• unanticipated cost overruns.

The ongoing operation of our facilities involves all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants may employ recently developed and technologically complex equipment, especially in the case of newer environmental emission control technology. Any of these risks could cause us to operate below expected capacity levels, which in turn could reduce revenues, increase expenses, or cause us to incur higher maintenance costs and penalties. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses or liquidated damage payments.

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

A portion of the variability of our net income in recent years has been attributable to wholesale electricity sales. The related power prices are influenced by many factors outside our control, including:

• fuel prices;

• transmission constraints;

• supply and demand;

• weather;

• economic conditions; and

• the rules, regulations and actions of the system operators in those markets.

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

Our business is subject to substantial governmental regulation and permitting requirements as well as on-site environmental liabilities we assumed when we acquired some of our facilities. We may be adversely affected by any future inability to comply with existing or future regulations or requirements or the potentially high cost of complying with such requirements.

Our business is subject to extensive energy, environmental and other laws and regulations of federal, state and local authorities. We generally must obtain and comply with a variety of licenses, permits and other approvals in order to operate. In the course of complying with these requirements, we may incur significant additional costs. If we fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. In addition, existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to us or our facilities which could 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 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 assets we operate.

Ongoing changes in the United States utility industry, including state and federal regulatory changes, a potential increase in the number or geographic scale of our competitors or the imposition of price limitations to address market volatility, could adversely affect our profitability.

The United States electric utility industry is currently experiencing increasing competitive pressures as a result of:

• the Energy Policy Act of 2005 and the repeal of the Public Utility Holding Company Act of 1935;

• industry consolidation;

• consumer demands;

• transmission constraints;

• renewable resource supply requirements;

• technological advances; and

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

The Federal Energy Regulatory Commission (FERC) has implemented and continues to propose regulatory changes to increase access to the nationwide transmission grid by utility and non-utility purchasers and sellers of electricity. In addition, a number of states have implemented or are considering or currently implementing methods to introduce and promote retail competition. Industry deregulation in some states has led to the disaggregation of some vertically integrated utilities into separate generation, transmission and distribution businesses. Deregulation initiatives in a number of states may encourage further disaggregation. As a result, significant additional competitors could become active in the generation, transmission and distribution segments of our industry, which could negatively affect our ability to expand our asset base.

In addition, the independent system operators who oversee many of the wholesale power markets have in the past imposed, and may in the future continue to impose price limitations and other mechanisms to address some of the volatility in these markets. These types of price limitations and other mechanisms may adversely affect the profitability of generating facilities that sell energy into the wholesale power markets. Given the extreme volatility and lack of meaningful long-term price history in some of these markets and the imposition of price limitations by independent system operators, we may not be able to operate profitably in all wholesale power markets.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 3.

LEGAL PROCEEDINGS

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” subcaption within Item 8, Note 11, “Commitments and Contingencies”, of our Notes to Financial Statements in this Annual Report on Form 10-K.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS

All of our common stock is held by our parent company, Black Hills Corporation. Accordingly, there is no established trading market for our common stock.

ITEM 7.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

	2006		2005		2004
	(in thousands)

Revenue	$	193,166	$	189,005	$	173,745
Operating expenses		153,164		152,961		129,936
Operating income	$	40,002	$	36,044	$	43,809

Net income	$	18,724	$	18,005	$	19,209

The following table provides certain electric utility operating statistics:

Electric Revenue
(in thousands)

			Percentage			Percentage
Customer Base	2006		Change	2005		Change	2004

Commercial	$	49,756	1%	$	49,185	5%	$	46,791
Residential		40,491	3		39,348	8		36,536
Industrial		20,694	4		19,982	1		19,796
Municipal sales		2,401	6		2,268	3		2,200
Contract wholesale		24,705	6		23,384	3		22,720
Wholesale off-system		42,489	(11)		47,647	25		38,228
Total electric sales		180,536	(1)		181,814	9		166,271
Other revenue		12,630	76		7,191	(4)		7,474
Total revenue	$	193,166	2%	$	189,005	9%	$	173,745

Megawatt-Hours Sold

		Percentage		Percentage
Customer Base	2006	Change	2005	Change	2004

Commercial	667,220	2%	655,076	4%	627,326
Residential	499,152	4	480,053	7	447,166
Industrial	433,019	4	417,628	3	406,209
Municipal sales	32,961	10	30,084	4	28,934
Contract wholesale	647,444	5	619,369	1	614,700
Wholesale off-system	942,045	8	869,161	(6)	926,461
Total electric sales	3,221,841	5%	3,071,371	1%	3,050,796

We established a new summer peak load of 415 megawatts in July 2006 and a new winter peak load of 356 megawatts in December 2005. We own 435 megawatts of electric utility generating capacity and purchase an additional 50 megawatts under a long-term agreement expiring in 2023.

	2006	2005	2004
Regulated power plant
fleet availability:
Coal-fired plants	95.5%	93.3%	93.3%
Other plants	98.7%	99.3%	98.5%
Total availability	97.1%	96.3%	95.9%

		Percentage		Percentage
Resources	2006	Change	2005	Change	2004

Megawatt-hours generated:
Coal	1,729,636	0%	1,728,823	(1)%	1,753,693
Gas	54,299	46	37,239	34	27,825
	1,783,935	1	1,766,062	(1)	1,781,518

Megawatt-hours purchased	1,553,024	11	1,399,212	3	1,361,409
Total resources	3,336,959	5%	3,165,274	1%	3,142,927

	2006	2005	2004

Heating and cooling degree days:
Actual
Heating degree days	6,472	6,488	6,553
Cooling degree days	931	830	522

Variance from normal
Heating degree days	(10)%	(10)%	(9)%
Cooling degree days	56%	39%	(13)%

2006 Compared to 2005

Electric revenue increased 2 percent for the year ended December 31, 2006 compared to the same period in the prior year. Firm residential, industrial and contract wholesale sales increased 3 percent, 4 percent and 6 percent, respectively. For the year ended December 31, 2006, cooling degree days were 56 percent higher than normal and heating degree days were 10 percent lower than normal. Wholesale off-system sales decreased 11 percent due to an 18 percent decrease in average price received partially offset by an 8 percent increase in megawatt-hours sold.

Electric operating expenses were flat for the year ended December 31, 2006, compared to the prior year. Increases in fuel costs were primarily due to a 7 percent increase in average cost of steam generation and increased gas generation utilized for firm load demand and peaking needs due to scheduled and unscheduled outages at the Wyodak plant and warmer weather. Purchased power decreased primarily due to a 12 percent lower average cost per megawatt-hour offset by an 11 percent increase in megawatt-hours purchased. Operating expenses were also affected by increased repairs and maintenance costs for the Wyodak plant, incentive compensation costs and corporate allocations, partially offset by a decrease in power marketing legal costs relative to costs incurred in 2005 (See Note 11, “Commitments and Contingencies” to the Notes to Financial Statements in this Annual Report on Form 10-K for discussion of the power marketing legal settlement).

Income from continuing operations increased 4 percent primarily due to increased revenues and lower interest expense, offset by a 2005 deferred tax benefit adjustment of $1.9 million.

Rate Increase Settlement. During 2006 we filed an application with the SDPUC for an electric rate increase to be effective January 1, 2007. On December 28, 2006, we received an order from the SDPUC for a 7.8 percent increase in retail rates and approving the addition of tariff provisions for automatic adjustments. The cost adjustments will require us to absorb a portion of power cost increases partially depending on earnings on certain short-term wholesale sales of electricity. Absent certain conditions, the order also restricts us from requesting an increase in base rates that would go into effect prior to January 1, 2010. Our previous rate structure, in place since 1995, did not contain fuel or purchased power adjustment clauses and only provided the ability to request rate relief from energy costs in certain defined situations. South Dakota retail customers account for approximately 91 percent of our total retail revenues.

2005 Compared to 2004

Electric revenue increased 9 percent for the year ended December 31, 2005 compared to the same period in the prior year. Firm commercial, residential and contract wholesale sales increased 5 percent, 8 percent and 3 percent, respectively. Cooling degree days for the year were 59 percent higher than 2004 and heating degree days were 1 percent lower than 2004. Wholesale off-system sales increased 25 percent due to a 33 percent increase in average price received partially offset by a 6 percent decrease in megawatt-hours sold.

Electric operating expenses increased 18 percent for the year ended December 31, 2005, compared to the prior year. Higher operating expenses were primarily the result of an $18.5 million increase in fuel and purchased power costs. The increase in fuel and purchased power was due to a $16.9 million increase in purchased power, which includes $2.8 million of additional purchase power costs to cover the outage of Neil Simpson II, as well as a 31 percent increase in average price per megawatt-hour, and a 3 percent increase in megawatt-hours purchased. Fuel costs increased $1.6 million due to a 12 percent increase in average cost, partially offset by a 1 percent decrease in megawatt-hours generated. Megawatt-hours produced through coal-fired generation decreased while higher cost gas generation was utilized in 2005. Purchased power and gas generation were utilized for firm load demand and peaking needs due to unscheduled plant outages and warmer weather. The increase in operating expense was also affected by increased power marketing legal expense, compensation costs and corporate allocations, partially offset by lower maintenance costs due to scheduled and unscheduled plant maintenance in 2004.

Income from continuing operations decreased $1.2 million primarily due to increased fuel and purchased power costs, legal expense, compensation costs and corporate allocations, partially offset by increased revenues, lower maintenance costs, lower interest expense due to the pay down of debt, and a $1.9 million benefit from a deferred tax adjustment.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	16

Statements of Income for the three years ended December 31, 2006	17

Balance Sheets as of December 31, 2006 and 2005	18

Statements of Cash Flows for the three years ended December 31, 2006	19

Statements of Common Stockholder’s Equity and Comprehensive Income
for the three years ended December 31, 2006	20

Notes to Financial Statements	21-44

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the 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, 2006 and 2005, 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, 2006. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Black Hills Power, Inc. as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective as of December 31, 2006.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 13, 2007

BLACK HILLS POWER, INC.

STATEMENTS OF INCOME

Years ended December 31,	2006		2005		2004
	(in thousands)

Operating revenues	$	193,166	$	189,005	$	173,745

Operating expenses:
Fuel and purchased power		81,215		80,886		60,668
Operations and maintenance		24,304		22,586		26,030
Administrative and general		20,845		22,685		16,570
Depreciation and amortization		19,801		19,543		18,873
Taxes, other than income taxes		6,999		7,261		7,795
		153,164		152,961		129,936

Operating income		40,002		36,044		43,809

Other (expense) income:
Interest expense		(12,057)		(12,907)		(16,019)
Interest income		258		258		696
Allowance for funds used during construction - equity		405		—		—
Other expense		(1)		(110)		(213)
Other income		246		463		448
		(11,149)		(12,296)		(15,088)

Income from continuing operations before income taxes		28,853		23,748		28,721
Income taxes		(10,129)		(5,743)		(9,512)

Net income	$	18,724	$	18,005	$	19,209

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

BLACK HILLS POWER, INC.

BALANCE SHEETS

At December 31,	2006		2005
	(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	1,223	$	685
Receivables (net of allowance for doubtful accounts of $250 and $830 at 2006
and 2005, respectively) -
Customers		19,330		19,297
Affiliates		1,935		1,964
Other		785		996
Money pool note receivable		13,264		—
Materials, supplies and fuel		17,579		14,236
Deferred income taxes		—		835
Other current assets		1,853		820
		55,969		38,833

Investments		3,552		3,340

Property, plant and equipment		675,987		653,679
Less accumulated depreciation		(265,247)		(250,583)
		410,740		403,096
Other assets:
Regulatory assets		17,688		6,941
Other		2,658		11,448
		20,346		18,389
	$	490,607	$	463,658

LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	2,002	$	1,996
Accounts payable		9,466		10,290
Accounts payable – affiliate		3,414		1,624
Note payable – affiliate		—		1,842
Accrued liabilities		21,862		14,866
Deferred income taxes		138		—
		36,882		30,618

Long-term debt, net of current maturities		153,217		155,219

Deferred credits and other liabilities:
Deferred income taxes		65,164		67,942
Regulatory liabilities		7,775		5,740
Other		19,700		15,460
		92,639		89,142
Commitments and contingencies (Notes 5, 9 and 11)

Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized;
Issued: 23,416,396 shares in 2006 and 2005		23,416		23,416
Additional paid-in capital		39,575		39,549
Retained earnings		145,810		127,312
Accumulated other comprehensive loss		(932)		(1,598)
		207,869		188,679
	$	490,607	$	463,658

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,	2006		2005		2004
	(in thousands)
Operating activities:
Net income	$	18,724	$	18,005	$	19,209
Adjustments to reconcile net income to net cash
provided by operating activities –
Depreciation and amortization		19,801		19,543		18,873
Provision for valuation allowances		(586)		(82)		14
Deferred income taxes		(2,799)		(2,558)		3,781
Allowance for funds used during construction –
equity		(405)		—		—
Change in operating assets and liabilities –
Accounts receivable and other current assets		(2,513)		(4,206)		(3,895)
Accounts payable and other current liabilities		8,431		4,373		(8,833)
Other operating activities		1,346		4,331		3,005
Net cash provided by operating activities		41,999		39,406		32,154

Investing activities:
Property, plant and equipment additions		(24,147)		(16,918)		(12,946)
Notes receivable from associated companies, net		(13,264)		—		37,710
Other investing activities		(212)		3,076		(3,424)
Net cash (used in) provided by investing activities		(37,623)		(13,842)		21,340

Financing activities:
Dividends paid on common stock		—		—		(24,000)
Note payable to associated companies		(1,842)		(23,232)		25,074
Long-term debt – issuance		—		—		18,650
Long-term debt – repayments		(1,996)		(1,991)		(71,486)
Other financing activities		—		—		(2,440)
Net cash used in financing activities		(3,838)		(25,223)		(54,202)

Increase (decrease) in cash and cash equivalents		538		341		(708)

Cash and cash equivalents:
Beginning of year		685		344		1,052
End of year	$	1,223	$	685	$	344

Non-cash investing and financing activities –
Property, plant and equipment financed with
accrued liabilities	$	224	$	492	$	—

Supplemental disclosure of cash flow information:
Cash paid during the period for –
Interest	$	13,826	$	11,993	$	17,351
Income taxes	$	6,820	$	5,295	$	5,753

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

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

Balance at December 31, 2003	23,416	$	23,416	$	39,549	$	114,098	$	(1,494)	$	175,569
Comprehensive Income:
Net income	—		—		—		19,209		—		19,209
Other comprehensive income,
net of tax (see Note 8)	—		—		—		—		58		58
Total comprehensive income	—		—		—		19,209		58		19,267

Dividends on common stock	—		—		—		(24,000)		—		(24,000)

Balance at December 31, 2004	23,416		23,416		39,549		109,307		(1,436)		170,836
Comprehensive Income:
Net income	—		—		—		18,005		—		18,005
Other comprehensive loss,
net of tax, (see Note 8)	—		—		—		—		(162)		(162)
Total comprehensive income	—		—		—		18,005		(162)		17,843

Balance at December 31, 2005	23,416		23,416		39,549		127,312		(1,598)		188,679
Comprehensive Income:
Net income	—		—		—		18,724		—		18,724
Other comprehensive income,
net of tax, (see Note 8)	—		—		—		—		786		786
Total comprehensive income	—		—		—		18,724		786		19,510

Adoption of accounting
pronouncement (see Note 1)	—		—		—		—		(120)		(120)
Assumption of business unit
of affiliate company
(see Note 10)	—		—		26		(226)		—		(200)

Balance at December 31, 2006	23,416	$	23,416	$	39,575	$	145,810	$	(932)	$	207,869

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

NOTES TO FINANCIAL STATEMENTS

December 31, 2006, 2005 and 2004

(1)

BUSINESS DESCRIPTION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Business Description

Black Hills Power, Inc. (the Company) is an electric utility serving customers in South Dakota, Wyoming and Montana. The Company is a wholly owned subsidiary of Black Hills Corporation (the Parent), a public registrant listed on the New York Stock Exchange.

Basis of Presentation

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

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to allowance for uncollectible accounts receivable, long-lived asset values and useful lives, employee benefits plans and contingency accruals. Actual results could differ from those estimates.

Regulatory Accounting

The Company’s regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of FERC.

The Company’s electric operations follow the provisions of the Financial Accounting Standards Board (FASB) of SFAS 71 and its financial statements reflect the effects of the different ratemaking principles followed by the various jurisdictions regulating its electric operations. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply to the Company’s regulated generation operations. In the event the Company determines that it no longer meets the criteria for following SFAS 71, the accounting impact to the Company would be an extraordinary non-cash charge to operations of an amount that could be material.

At December 31, 2006 and 2005, the Company had regulatory assets of $17.7 million and $6.9 million and regulatory liabilities of $7.8 million and $5.7 million, respectively. 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 allowance for funds used during construction of utility assets and unamortized losses on reacquired debt. Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates, gains associated with regulated utilities’ defined benefit postretirement plans and the cost of removal for utility plant, recovered through the Company’s electric utility rates.

	2006		2005

Regulatory assets:
Unamortized loss on reacquired debt	$	2,694	$	2,879
Allowance for funds used during construction		3,926		4,062
Defined benefit postretirement plans		10,778		—
Other		290		—
	$	17,688	$	6,941

Regulatory liabilities:
Deferred income taxes	$	2,414	$	2,707
Cost of removal for utility plant		5,361		3,033
	$	7,775	$	5,740

Allowance for Funds Used During Construction

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, 2006, 2005 and 2004 was $0.6 million, $0.2 million, and $0.2 million, respectively. The equity component of AFUDC for 2006, 2005 and 2004 was $0.4 million, $0 million and $0.1 million, respectively. The borrowed funds component of AFUDC for 2006, 2005 and 2004 was $0.2 million, $0.1 million and $0.1 million, respectively. The equity component of AFUDC is included in Other income (expense), and the borrowed funds component of AFUDC is included in Interest expense on the accompanying Statements of Income.

Cash Equivalents

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

Materials, Supplies and Fuel

Materials, supplies and fuel used for construction, operation and maintenance purposes are generally stated at cost on a weighted-average 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, 2005, market adjustments related to fuel were $(0.2) million.

Deferred Financing Costs

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

Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost when placed in service. The cost of regulated electric property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage, is charged to accumulated depreciation. Removal costs associated with non-legal obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Ordinary repairs and maintenance of property are charged to operations as incurred.

Depreciation provisions for regulated electric property, plant and equipment is computed on a straight-line basis using an annual composite rate of 3.0 percent in 2006, 3.1 percent in 2005 and 3.0 percent in 2004.

Derivatives and Hedging Activities

The Company, from time to time, utilizes risk management contracts including forward purchases and sales and fixed-for-float swaps to hedge the price of fuel for its combustion turbines, maximize the value of its natural gas storage or to fix the interest on its variable rate debt. Certain of the contracts qualify as derivatives under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). SFAS 133 requires that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133 requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

SFAS 133 allows hedge accounting for qualifying fair value and cash flow hedges. SFAS 133 provides that the gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk be recognized currently in earnings in the same accounting period. SFAS 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income 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

The Company periodically evaluates whether events and circumstances have occurred which may affect the estimated useful life or the recoverability of the remaining balance of its long-lived assets. If such events or circumstances were to indicate that the carrying amount of these assets was not recoverable, the Company would estimate the future cash flows expected to result from the use of the assets and their eventual disposition. If the sum of the expected future cash flows (undiscounted and without interest charges) was less than the carrying amount of the long-lived assets, the Company would recognize an impairment loss. No impairment loss was recorded during 2006, 2005 or 2004.

Income Taxes

The Company uses the liability method in accounting for income taxes. Under the liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities, as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. The Company classifies deferred tax assets and liabilities into current and non-current amounts based on the classification of the related assets and liabilities.

The Company files a federal income tax return with other affiliates. For financial statement purposes, federal income taxes are allocated to the individual companies based on amounts calculated on a separate return basis.

Revenue Recognition

Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price, delivery has occurred or services have been rendered, and collectibility is reasonably assured.

Recently Adopted Accounting Pronouncements

SFAS 158

During September 2006, the FASB issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an Amendment of FASB Statements No. 87, 88, 106 and 132(R).” This Statement requires the recognition of the overfunded or underfunded status of defined benefit postretirement plans as an asset or liability in the statement of financial position, recognition of changes in the funded status in comprehensive income, measurement of the funded status of a plan as of the date of the year-end statement of financial position, and provides for related disclosures. SFAS 158 is effective for the recognition of the funded status as an asset or liability in the statement of financial position, recognition of changes in the funded status in comprehensive income and the related disclosures in financial statements issued for fiscal years ending after December 15, 2006.

The Company applied the recognition provisions of SFAS 158 as of December 31, 2006. Effective for fiscal years ending after December 15, 2008, SFAS 158 will require the measurement of the funded status of the plan to coincide with the date of the year end statement of financial position. See Note 9, “Employee Benefit Plans,” for further discussion of Defined Benefit Pension and Other Postretirement Plans.

Recently Issued Accounting Pronouncements

SFAS 157

During September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS 157) and applies under other accounting pronouncements that require or permit fair value measurements. This Statement defines fair value, establishes a framework for measuring fair value in Generally Accepted Accounting Principles (GAAP) and expands disclosures about fair value measurements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. Management is currently evaluating the impact SFAS 157 will have on the Company’s financial statements.

SFAS 159

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159), which establishes a fair value option under which entities can elect to report certain financial assets and liabilities at fair value, with changes in fair value recognized in earnings. SFAS 159 is effective for fiscal years beginning after November 15, 2007. Management is currently evaluating the impact SFAS 159 will have on the Company’s financial statements.

FIN 48

During June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes” (SFAS 109), and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006 with the impact of adoption to be reported as a cumulative effect of an accounting change. Management is currently evaluating the impact FIN 48 will have on the Company’s financial statements.

SAB No. 108 – Effects of Prior Year Misstatements on Current Year Financial Statements

During September 2006, the staff of the SEC released SAB No. 108 on Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how the effects of the carryover or reversal of prior year financial statement misstatements should be considered in quantifying a current year misstatement. Prior practice allowed the evaluation of materiality on the basis of (1) the error quantified as the amount by which the current year income statement was misstated (rollover method) or (2) the cumulative error quantified as the cumulative amount by which the current year balance sheet was misstated (iron curtain method). Reliance on either method in prior years could have resulted in misstatement of the financial statements. The guidance provided in SAB No. 108 requires both methods to be used in evaluating materiality. Immaterial prior year errors may be corrected with the first filing of prior year financial statements after adoption. The cumulative effect of the correction can either be reported in the carrying amounts of assets and liabilities as of the beginning of that fiscal year, and the offsetting adjustment made to the opening balance of retained earnings for that year, or by restating prior periods. Disclosure requirements include the nature and amount of each individual error being corrected in the cumulative adjustment, as well as a disclosure of when and how each error being corrected arose and the fact that the errors had previously been considered immaterial. SAB No. 108 is effective January 1, 2007. SAB No. 108 did not have an effect on the Company’s financial position, results of operation or cash flows.

(2)

PROPERTY, PLANT AND EQUIPMENT

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

			2006			2005
			Weighted			Weighted
			Average			Average
			Useful			Useful	Lives
	2006		Life	2005		Life	(in years)

Electric plant:
Production	$	325,616	47	$	317,792	45	25-58
Transmission		70,731	45		69,998	45	35-50
Distribution		232,299	37		222,305	32	20-40
Plant acquisition adjustment		4,870	—		4,870	—	—
General		34,885	22		32,030	18	7-40
Total electric plant		668,401			646,995
Less accumulated depreciation
and amortization		265,247			250,583
Electric plant net of accumulated
depreciation and amortization		403,154			396,412
Construction work in progress		7,586			6,684
Net electric plant	$	410,740		$	403,096

(3)

JOINTLY OWNED FACILITIES

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

• The Company owns a 20 percent interest and PacifiCorp owns an 80 percent interest in the Wyodak Plant (Plant), a 362 megawatt coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp is the operator of the Plant. The Company receives 20 percent of the Plant’s capacity and is committed to pay 20 percent of its additions, replacements and operating and maintenance expenses. As of December 31, 2006 and 2005, the Company’s investment in the Plant included $76.3 million and $73.8 million, respectively, in electric plant and $41.0 million and $38.8 million, respectively, in accumulated depreciation, and is included in the corresponding captions in the accompanying Balance Sheets. The Company’s share of direct expenses of the Plant was $7.9 million, $6.1 million and $6.0 million for the years ended December 31, 2006, 2005 and 2004, respectively, and is included in the corresponding categories of operating expenses in the accompanying Statements of Income.

• The Company also owns a 35 percent interest and Basin Electric Power Cooperative owns a 65 percent interest in the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. 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 Mid-Continent Area Power Pool, or MAPP region. The total transfer capacity of the tie is 400 megawatts – 200 megawatts West to East and 200 megawatts from East to West. The Company is committed to pay 35 percent of the additions, replacements and operating and maintenance expenses. The Company’s share of direct expenses was $0.1 million, $0.2 million and $0.1 million for the years ended December 31, 2006, 2005 and 2004 respectively. As of December 31, 2006 and 2005, the Company’s investment in the transmission tie was $19.8 million and $19.7 million, respectively, with $1.5 million and $0.9 million, respectively, of accumulated depreciation and is included in the corresponding captions in the accompanying Balance Sheets.

(4)

RISK MANAGEMENT

The Company holds natural gas in storage for use as fuel for generating electricity with its gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, the Company utilizes various derivative instruments in managing these risks. On December 31, 2006 and December 31, 2005, the Company had the following derivatives and related balances (in thousands):

											Pre-tax
					Non-				Non-		Accumulated
		Maximum	Current		current		Current		current		Other
		Terms in	Derivative		Derivative		Derivative		Derivative		Comprehensive		Unrealized
	Notional*	Years	Assets		Assets		Liabilities		Liabilities		Income/(Loss)		Gain
December 31,
2006

Natural gas
swaps	310,000	0.25	$	878	$	—	$	—	$	—	$	878	$	—

December 31,
2005

Natural gas
swaps	275,000	0.25	$	192	$	—	$	219	$	—	$	(219)	$	192

________________________

*gas in MMbtus

Based on December 31, 2006 market prices, a $0.9 million gain would be realized and reported in pre-tax earnings during the next twelve months related to derivatives designated as a cash flow hedge. These estimated realized gains for the next twelve months were calculated using December 31, 2006 market prices. Estimated and actual realized gains will likely change during the next twelve months as market prices change.

In addition, certain volumes of natural gas inventory were designated as cash flow hedges or the underlying hedged item in a “fair value” hedge transaction in 2005. These volumes were stated at market value using published spot industry quotations. Market adjustments for the fair value hedge transaction were recorded in inventory on the Balance Sheet and the related unrealized gain/loss on the Statement of Income. As of December 31, 2005, the market adjustments recorded in inventory were $(0.2) million.

(5)

LONG-TERM DEBT

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

	2006		2005
	(in thousands)
First mortgage bonds:
8.06% due 2010	$	30,000	$	30,000
9.49% due 2018		3,390		3,680
9.35% due 2021		24,975		26,640
7.23% due 2032		75,000		75,000
		133,365		135,320
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		3,204		3,245
		21,854		21,895

Total long-term debt		155,219		157,215
Less current maturities		(2,002)		(1,996)
Net long-term debt	$	153,217	$	155,219

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

Scheduled maturities are approximately $2.0 million a year for the years 2007 through 2009, $32.0 million in 2010, $2.0 million in 2011 and $115.2 million thereafter.

(6)

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

	2006				2005
	Carrying Amount		Fair Value		Carrying Amount		Fair Value

Cash and cash equivalents	$	1,223	$	1,223	$	685	$	685
Derivative financial
instruments – assets	$	878	$	878	$	192	$	192
Derivative financial
instruments – liabilities	$	—	$	—	$	219	$	219
Long-term debt	$	155,219	$	177,217	$	157,215	$	183,491

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

Cash and Cash Equivalents

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

Derivative Financial Instruments

These instruments are carried at fair value. Descriptions of the instruments the Company uses are available in Note 4.

Long-Term Debt

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

(7)

INCOME TAXES

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

	2006		2005		2004

Current	$	12,928	$	8,301	$	5,731
Deferred		(2,799)		(2,558)		3,781
	$	10,129	$	5,743	$	9,512

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

Years ended December 31,	2006		2005

Deferred tax assets, current:
Asset valuation reserve	$	87	$	291
Employee benefits		361		550
Items of other comprehensive income		—		76
Other		—		110
		448		1,027

Deferred tax liabilities, current:
Prepaid expenses		177		192
Items of other comprehensive income		307		—
Other		102		—
		586		192

Net deferred tax (liability) asset, current	$	(138)	$	835

Deferred tax assets, non-current:
Plant related differences	$	1,204	$	949
Regulatory asset		776		898
ITC		189		271
Employee benefits		6,896		2,929
Items of other comprehensive income		265		217
Other		128		204
		9,458		5,468

Deferred tax liabilities, non-current:
Accelerated depreciation and other plant related differences		63,457		65,459
AFUDC		2,551		2,640
Regulatory liability		1,374		1,422
Employee benefits		6,297		2,880
Deferred costs		102		—
Other		841		1,009
		74,622		73,410

Net deferred tax liability, non-current	$	65,164	$	67,942

Net deferred tax liability	$	65,302	$	67,107

The following table reconciles the change in the net deferred income tax liability from December 31, 2005, to December 31, 2006, to the deferred income tax benefit (in thousands):

	2006

Decrease in deferred income tax liability from the preceding table	$	(1,805)
Deferred taxes related to regulatory assets and liabilities		(450)
Deferred taxes associated with other comprehensive loss		(359)
Deferred taxes, other		(185)
Deferred income tax benefit for the period	$	(2,799)

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

	2006	2005	2004

Federal statutory rate	35.0%	35.0%	35.0%
Amortization of excess deferred and investment tax credits	(1.3)	(1.7)	(1.5)
Deferred tax adjustments primarily related to
plant-related changes in estimate	—	(8.2)	—
IRS tax exam adjustment*	2.6	—	—
Other	(1.2)	(0.9)	(0.4)
	35.1%	24.2%	33.1%

__________________________

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

(8)

OTHER COMPREHENSIVE INCOME (LOSS)

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

	2006
	Pre-tax				Net-of-tax
	Amount		Tax Expense		Amount

Pension liability adjustment	$	48	$	(17)	$	31
Amortization of cash flow hedges settled and deferred in
accumulated other comprehensive income (loss) and
reclassified into interest expense		64		(22)		42
Net change in fair value of derivatives designated as
cash flow hedges		1,097		(384)		713
Other comprehensive income	$	1,209	$	(423)	$	786

	2005
	Pre-tax				Net-of-tax
	Amount		Tax Benefit		Amount

Minimum pension liability adjustment	$	(94)	$	33	$	(61)
Amortization of cash flow hedges settled and deferred in
accumulated other comprehensive income (loss) and
reclassified into interest expense		64		(22)		42
Net change in fair value of derivatives designated as
cash flow hedges		(219)		76		(143)
Other comprehensive loss	$	(249)	$	87	$	(162)

	2004
	Pre-tax				Net-of-tax
	Amount		Tax Expense		Amount

Minimum pension liability adjustment	$	25	$	(9)	$	16
Amortization of cash flow hedges settled and deferred in
accumulated other comprehensive income (loss) and
reclassified into interest expense		64		(22)		42
Other comprehensive income	$	89	$	(31)	$	58

(9)

EMPLOYEE BENEFIT PLANS

SFAS 158

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

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

The following table discloses the incremental effect of applying SFAS 158 in the Company’s 2006 Balance Sheet (in thousands):

	Before		Impact from		Impact of		After
	Application of		Adoption of		SFAS 71		Application of
	SFAS 158		SFAS 158		Adjustment		SFAS 158

Regulatory asset	$	14,125	$	(7,215)	$	10,778	$	17,688

Accrued liabilities	$	21,034	$	828	$	—	$	21,862

Deferred income taxes	$	65,230	$	(3,838)	$	3,772	$	65,164

Deferred credits and
other liabilities - other	$	16,778	$	2,922	$	—	$	19,700

Accumulated other
comprehensive (loss)
income	$	(811)	$	(7,127)	$	7,006	$	(932)

Defined Benefit Pension Plan

The Company has a noncontributory defined benefit pension plan (Plan) covering the employees of the Company who meet certain eligibility requirements. The benefits are based on years of service and compensation levels during the highest five consecutive years of the last ten years of service. The Company’s funding policy is in accordance with the federal government’s funding requirements. The Plan’s assets are held in trust and consist primarily of equity and fixed income investments. The Company uses a September 30 measurement date for the Plan.

The Plan’s expected long-term rate of return on assets assumption is based upon the weighted average expected long-term rate of returns for each individual asset class. The asset class weighting is determined using the target allocation for each asset class in the Plan portfolio. The expected long-term rate of return for each asset class is determined primarily from long-term historical returns for the asset class, with adjustments if it is anticipated that long-term future returns will not achieve historical results.

The expected long-term rate of return for equity investments was 9.5 percent for the 2006 and 2005 plan years. For determining the expected long-term rate of return for equity assets, the Company reviewed interest rate trends and annual 20-, 30-, 40-, and 50-year returns on the S&P 500 Index, which were, at December 31, 2006, 11.8 percent, 12.4 percent, 11.0 percent and 10.6 percent, respectively. Fund management fees were estimated to be 0.18 percent for S&P 500 Index assets and 0.45 percent for other assets. The expected long-term rate of return on fixed income investments was 6.0 percent; the return was based upon historical returns on 10-year treasury bonds of 7.1 percent from 1962 to 2006, and adjusted for recent declines in interest rates. The expected long-term rate of return on cash investments was estimated to be 4.0 percent; expected cash returns were estimated to be 2.0 percent below long-term returns on intermediate-term bonds.

Plan Assets

Percentage of fair value of Plan assets at September 30:

	2006	2005

Domestic equity	50.3%	52.9%
Foreign equity	25.3	40.6
Fixed income	15.6	3.4
Cash	8.8	3.1
Total	100.0%	100.0%

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

Asset Class	Target Allocation

US Stocks	50%
Foreign Stocks	25%
Fixed Income	25%
Cash	0%

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

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

Cash Flows

The Company made no contributions to the Plan in 2006 and does not anticipate any employer contributions to the Plan in 2007.

Supplemental Nonqualified Defined Benefit Retirement Plans

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

Plan Assets

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

Estimated Cash Flows

The estimated employer contribution is expected to be $0.1 million in 2007. Contributions are expected to be made in the form of benefit payments.

Non-pension Defined Benefit Postretirement Plan

Employees who are participants in the Company’s Postretirement Healthcare Plan and who retire from the Company on or after attaining age 55 after completing at least five years of service to the Company are entitled to postretirement healthcare benefits. These benefits are subject to premiums, deductibles, co-payment provisions and other limitations. The Company may amend or change the Plan periodically. The Company is not pre-funding its retiree medical plan. The Company uses a September 30 measurement date for the Plan.

It has been determined that the Plan’s post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The effect of the Medicare Part D subsidy on the accumulated postretirement benefit obligation for the fiscal year ending December 31, 2006, was an actuarial gain of approximately $1.0 million. The effect on 2007 net periodic postretirement benefit cost will be a decrease of approximately $0.1 million.

Plan Assets

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

Estimated Cash Flows

The estimated employer contribution is expected to be $0.2 million in 2007. Contributions are expected to be made in the form of benefit payments.

The following tables provide a reconciliation of the Employee Benefit Plan’s obligations and fair value of assets for 2006 and 2005, a statement of funded status for 2005, components of the net periodic expense for the years ended 2006, 2005 and 2004 and elements of accumulated other comprehensive income for 2006.

Benefit Obligations

					Supplemental Nonqualified
					Defined Benefit				Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans				Benefit Postretirement Plans
	2006		2005		2006		2005		2006		2005
	(in thousands)
Change in benefit obligation:

Projected benefit obligation at
beginning of year	$	49,311	$	46,176	$	2,022	$	1,886	$	7,167	$	7,861
Service cost		1,085		991		—		—		249		292
Interest cost		2,720		2,700		113		110		398		465
Actuarial (gain) loss		156		9		(35)		143		(573)		(1,359)
Amendments		—		—		—		—		(205)		—
Discount rate change		—		1,630		—		—		—		—
Benefits paid		(2,095)		(2,122)		(101)		(117)		(526)		(469)
Asset transfer to affiliate		(837)		(592)		—		—		(135)		(26)
Mortality assumption change		—		519		—		—		—		—
Plan participant’s contributions		—		—		—		—		416		403
Net increase (decrease)		1,029		3,135		(23)		136		(376)		(694)
Projected benefit obligation at
end of year	$	50,340	$	49,311	$	1,999	$	2,022	$	6,791	$	7,167

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

					Supplemental Nonqualified
					Defined Benefit				Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans				Benefit Postretirement Plans
	2006		2005		2006		2005		2006		2005
					(in thousands)

Beginning market value of
plan assets	$	43,859	$	39,844	$	—	$	—	$	—	$	—
Investment income		5,899		6,729		—		—		—		—
Benefits paid		(2,096)		(2,122)		—		—		—		—
Asset transfer to affiliate		(746)		(592)		—		—		—		—
Ending market value of
plan assets	$	46,916	$	43,859	$	—	$	—	$	—	$	—

Amounts recognized in the statement of financial position consist of:

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

	2006		2006		2006
	(in thousands)
Regulatory asset	$	10,637	$	—	$	141
Current liability	$	—	$	630	$	198
Non-current liability	$	3,423	$	1,343	$	6,486

Funded Status

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

	2005		2005		2005
	(in thousands)

Funded status	$	(5,452)	$	(2,022)	$	(7,167)
Unrecognized net loss		12,915		858		409
Unrecognized prior service cost		766		3		(208)
Unrecognized transition obligation		—		—		817
Contributions		—		25		13
Net amount recognized	$	8,229	$	(1,136)	$	(6,136)

Amounts recognized in statement of financial position consist of:

			Supplemental Nonqualified
			Defined Benefit		Non-pension Defined
	Defined Benefit Pension Plans		Retirement Plans		Benefit Postretirement Plans
	(a)		(b)
	2005		2005		2005
	(in thousands)
Amounts recognized in balance
sheets consist of:
Net asset (liability)	$	8,229	$	(1,785)	$	(6,136)
Intangible asset		—		3		—
Contributions		—		26		—
Accumulated other comprehensive
loss		—		620		—
Net amount recognized	$	8,229	$	(1,136)	$	(6,136)

___________________________

(a)

The provisions of SFAS 87 required the Company to record a net pension asset of $8.2 million at
December 31, 2005. This amount is included in Other assets, Other on the accompanying Balance Sheet.

(b)

The provisions of SFAS 87 required the Company to record a net pension liability of $1.8 million at
December 31, 2005. This amount is included in Deferred credits and other liabilities, Other on the accompanying Balance Sheet.

Accumulated Benefit Obligation

					Supplemental Nonqualified
					Defined Benefit				Non-pension Defined
	Defined Benefit Pension Plans				Retirement Plans				Benefit Postretirement Plans
	2006		2005		2006		2005		2006		2005
					(in thousands)

Accumulated benefit obligation	$	42,130	$	41,191	$	1,815	$	1,785	$	6,791	$	7,167

Components of Net Periodic Expense

								Supplemental Nonqualified
								Defined Benefit								Non-pension Defined Benefit
	Defined Benefit Pension Plans							Retirement Plans								Postretirement Plans
	2006		2005			2004		2006			2005			2004		2006		2005		2004
								(in thousands)

Service cost	$	1,085	$	991	$		959	$	—	$		—	$		—	$	249	$	292	$	300
Interest cost		2,720		2,700			2,621		113			109			110		398		465		486
Expected return on assets		(3,557)		(3,480)			(3,420)		—			—			—		—		—		—
Amortization of prior
service cost		103		156			166		1			1			1		(19)		(19)		(19)
Amortization of transition
obligation		—		—			—		—			—			—		117		117		116
Recognized net actuarial
loss		665		854			1,080		67			48			53		—		74		144
Net periodic expense	$	1,016	$	1,221	$		1,406	$	181	$		158	$		164	$	745	$	929	$	1,027

Accumulated Other Comprehensive Income

In accordance with SFAS 158, amounts included in accumulated other comprehensive income (loss), after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31, 2006 are as follows:

			Supplemental Nonqualified		Non-pension
	Defined Benefit		Defined Benefit		Defined Benefit
	Pension Plans		Retirement Plans		Postretirement Plans
	2006		2006		2006
	(in thousands)

Net loss	$	—	$	(491)	$	—
Prior service cost		—		(1)		—
Transition obligation		—		—		—
	$	—	$	(492)	$	—

The amounts in accumulated other comprehensive income, regulatory assets or regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2007 are as follows:

			Supplemental
			Nonqualified		Non-pension
	Defined Benefits		Defined Benefit		Defined Benefit
	Pension Plans		Retirement Plans		Postretirement Plans
	(in thousands)

Net loss	$	265	$	38	$	—
Prior service cost		67		—		—
Transition obligation		—		—		33
Total net periodic benefit cost
expected to be recognized
during calendar year 2007	$	332	$	38	$	33

Additional Information

			Supplemental Nonqualified		Non-pension
	Defined Benefit		Defined Benefit		Defined Benefit
	Pension Plans		Retirement Plans		Postretirement Plans
	2005		2005		2005
	(in thousands)

Pre-tax amount included in other
comprehensive income (loss) arising
from a change in the additional
minimum pension liability	$	—	$	94	$	—

Assumptions

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

Weighted-average
assumptions used to
determine benefit
obligations:	2006	2005	2004	2006	2005	2004	2006	2005	2004

Discount rate	5.95%	5.75%	6.00%	5.95%	5.75%	6.00%	5.95%	5.75%	6.00%
Rate of increase in
compensation levels	4.31%	4.34%	4.39%	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:	2006	2005	2004	2006	2005	2004	2006	2005	2004

Discount rate	5.75%	6.00%	6.00%	5.75%	6.00%	6.00%	5.75%	6.00%	6.00%
Expected long-term rate
of return on assets*	8.50%	9.00%	9.50%	N/A	N/A	N/A	N/A	N/A	N/A
Rate of increase in
compensation levels	4.34%	4.39%	5.00%	5.00%	5.00%	5.00%	N/A	N/A	N/A

_____________________________

The expected rate of return on plan assets remained at 8.5 percent for the calculation of the 2007 net periodic pension cost.

The healthcare trend rate assumption for 2006 fiscal year benefit obligation determination and 2007 fiscal year expense is a 10 percent increase for 2006 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2011. The healthcare cost trend rate assumption for the 2005 fiscal year benefit obligation determination and 2006 fiscal year expense was an 11 percent increase for 2005 grading down 1 percent per year until a 5 percent ultimate trend rate is reached in fiscal year 2011.

The healthcare cost trend rate assumption has a significant effect on the amounts reported. A 1 percent increase in the healthcare cost trend assumption would increase the service and interest cost $0.1 million or 22 percent and the accumulated periodic postretirement benefit obligation $1.2 million or 18 percent. A 1 percent decrease would reduce the service and interest cost by $0.1 million or 17 percent and the accumulated periodic postretirement benefit obligation $1.1 million or 14 percent.

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

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

2007	$	2,235	$	108	$	223	$	(25)	$	198
2008		2,342		125		238		(28)		210
2009		2,460		113		275		(31)		244
2010		2,605		117		323		(33)		290
2011		2,743		112		360		(36)		324
2012-2016		15,704		434		2,068		(231)		1,837

(10)

RELATED-PARTY TRANSACTIONS

Receivables and Payables

The Company has accounts receivable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $1.9 million and $2.0 million as of December 31, 2006 and 2005, respectively. The Company also has accounts payable balances related to transactions with other Black Hills Corporation subsidiaries. The balances were $3.4 million and $1.6 million as of December 31, 2006 and 2005, respectively.

Money Pool Notes Receivable and Notes Payable

In August 2005, the Company entered into a Utility Money Pool Agreement with the Parent and Cheyenne Light, Fuel and Power, (Cheyenne Light) an electric and gas utility subsidiary of the Parent. Under the agreement, the Company may borrow from the Parent. The Agreement restricts the Company from loaning funds to the Parent or to any of the Parent’s non-utility subsidiaries; the Agreement does not restrict the Company from making dividends to the Parent. Borrowings under the agreement bear interest at the daily cost of external funds as defined under the Agreement, or if there are no external funds outstanding on that date, then the rate will be the daily one month LIBOR rate plus 100 basis points.

The Company through the Utility Money Pool had a net note receivable balance from Cheyenne Light of $13.3 million on December 31, 2006 and a net note payable balance to the Parent of $1.8 million on December 31, 2005, respectively. Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (6.02 percent at December 31, 2006).

Other Balances and Transactions

The Company also received revenues of approximately $2.4 million, $2.2 million and $1.1 million for the years ended December 31, 2006, 2005 and 2004, respectively, from Black Hills Wyoming, Inc., an indirect subsidiary of the Parent, for the transmission of electricity.

The Company recorded revenues of $3.3 million and $1.5 million for the years ending December 31, 2006 and 2005, respectively, relating to payments received pursuant to a natural gas swap entered into with Enserco Energy, an indirect subsidiary of the Parent.

The Company purchases coal from Wyodak Resources Development Corp., an indirect subsidiary of the Parent. The amount purchased during the years ended December 31, 2006, 2005 and 2004 was $10.8 million, $10.1 million and $9.6 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.

In order to fuel its combustion turbine, the Company purchased natural gas from Enserco Energy, an indirect subsidiary of the Parent. The amount purchased during the years ended December 31, 2006, 2005 and 2004 was approximately $7.2 million, $6.4 million and $2.7 million, respectively. These amounts are included in Fuel and purchased power on the accompanying Statements of Income.

The Company also pays the Parent for allocated corporate support service cost incurred on its behalf. Corporate costs allocated from the Parent were $10.5 million and $10.7 million for the years ended December 31, 2006 and 2005, respectively.

The Company has a transmission system reserve deposit from Black Hills Wyoming in the amount of $1.7 million and $1.5 million at December 31, 2006 and 2005, 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 (8.17 percent at December 31, 2006).

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

(11)

COMMITMENTS AND CONTINGENCIES

Power Purchase and Transmission Services Agreements – Pacific Power

In 1983, the Company entered into a 40 year power purchase agreement with PacifiCorp providing for the purchase by the Company of 75 megawatts of electric capacity and energy from PacifiCorp’s system. An amended agreement signed in October 1997 reduces the contract capacity by 25 megawatts (5 megawatts per year starting in 2000). The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants. Costs incurred under this agreement were $10.1 million in 2006, $10.1 million in 2005 and $10.0 million in 2004.

The Company also has a firm point-to-point transmission service agreement with PacifiCorp that expires on December 31, 2023. The agreement provides that the following amounts of capacity and energy be transmitted: 32 megawatts in 2001, 27 megawatts in 2002, 22 megawatts in 2003, 17 megawatts in 2004-2006 and 50 megawatts in 2007-2023. Costs incurred under this agreement were $0.4 million in 2006, $0.4 million in 2005 and $0.4 million in 2004.

Long-Term Power Sales Agreements

• The Company has a ten-year power sales contract with the Municipal Energy Agency of Nebraska (MEAN) for 20 megawatts of contingent capacity from the Neil Simpson Unit #2 plant. The contract expires in February 2013.

• The Company had a contract with MDU, which expired January 1, 2007, for the sale of up to 55 megawatts of energy and capacity to service the Sheridan, Wyoming electric service territory. The Company entered into a new power purchase agreement with MDU for the supply of up to 74 megawatts of capacity and energy for Sheridan, Wyoming from 2007 through 2016, which is subject to regulatory approval by the WPSC. The Company also has a contract with the City of Gillette, Wyoming, expiring in 2012, to provide the city’s first 23 megawatts of capacity and energy. The agreement renews automatically and requires a seven-year notice of termination. Both contracts are served by the Company and are integrated into its control area and are treated as part of the Company’s firm native load.

Legal Proceedings

Forest Fire Claims

The Company has settled governmental claims related to the Grizzly Gulch Fire and the Hell Canyon Fire. On August 25, 2006, the U. S. District Court approved a full and final settlement of all governmental claims relating to both fires. The settlement agreements provided for the release and dismissal of all claims against the Company. For its part, the Company did not admit liability for the fires, but agreed to make settlement payments for the Grizzly Gulch and Hell Canyon fires. The settlements did not have a material adverse effect on the Company’s financial condition or results of operations.

While the government case was pending, a number of private claims for damages arising out of the Grizzly Gulch Fire were filed in Lawrence County Circuit Court, South Dakota. Counsel for these litigants had agreed to a stay of the proceedings pending the resolution of governmental claims. As a result of the settlement of the governmental cases, the private claims will now proceed through discovery. No trial date or other scheduling order has been set for these matters. The Company will continue to defend these matters. While the outcome of the remaining private suits is uncertain, they are not expected to have a material impact upon the Company’s financial condition or results of operations.

PPM Energy, Inc. Demand for Arbitration

The Company received a Demand for Arbitration from PPM Energy, Inc. (PPM) on January 2, 2004, that alleged claims for breach of contract and requested a declaration of the parties’ rights and responsibilities under an Exchange Agreement executed in April of 2001. PPM asserted the Exchange Agreement obligated the Company to accept receipt and cause corresponding delivery of electric energy, and to grant access to transmission rights allegedly covered by the Agreement. PPM requested an award of damages in an amount not less than $20.0 million. The Company filed its Response to Demand, including a counterclaim that sought recovery of sums PPM had refused to pay pursuant to the Exchange Agreement. The dispute was presented to the arbitrator in August 2005 and the arbitrator delivered his decision on June 5, 2006.

The arbitrator concluded both parties failed to perform the Exchange Agreement, in certain respects. The Company paid PPM a net settlement of $1.1 million in accordance with the decision, but prevailed on other substantial claims for payment and performance. The Company does not believe that the decision will have a material impact on its ability to market surplus power in the future.

Ongoing Litigation

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

(12)

QUARTERLY HISTORICAL DATA (Unaudited)

The Company operates on a calendar year basis. The following table sets forth selected unaudited historical operating results data for each quarter of 2006 and 2005.

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(in thousands)
2006:
Operating revenues	$	43,968	$	47,036	$	53,190	$	48,972
Operating income		10,097		6,491		12,767		10,647
Net income		4,899		2,436		5,764		5,625

2005:
Operating revenues	$	43,147	$	42,261	$	49,274	$	54,323
Operating income		9,495		8,120		5,463		12,966
Net income		4,322		3,409		1,888		8,386

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, 2006. Based on their evaluation, they have concluded that our disclosure controls and procedures are adequate and effective to ensure that material information relating to us that is required to be disclosed in our reports filed under the Exchange Act is recorded, processed, summarized and reported within the required time periods.

Internal control over financial reporting

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.

PART IV

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder of

Black Hills Power, Inc.

Rapid City, South Dakota

We have audited the financial statements of Black Hills Power, Inc. (the “Company”) as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, and have issued our report thereon dated March 13, 2007, (which expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of Statement of Financial Accounting Standards No. 158 Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, effective as of December 31, 2006); such financial statements and report are included in your 2006 Annual Report on Form 10-K and are included elsewhere in this Form 10-K. Our audits also included the financial statement schedule of the Company listed in Item 15. The financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

Minneapolis, Minnesota

March 13, 2007

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, 2006, 2005 and
		2004.

		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, 2006, 2005 AND 2004

Additions

	Balance		Charged				Balance
	at beginning		to costs				at end
Description	of year		and expenses		Deductions		of year

	(in thousands)
Allowance for
doubtful accounts:
2006	$	830	$	163	$	(743)	$	250
2005		912		41		(123)		830
2004		898		190		(176)		912

Exhibits

Exhibit Number	Description

2*	Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation’s Registration Statement on Form S-4 (No. 333-52664)).
3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).
3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).
4.1*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as an exhibit to Black Hills Holding Corporation’s Registration Statement on Form S-4 (No. 333-52664)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002).
10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant’s Form 10-K for 1992).
10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant’s Form 10-K for 1997).
10.3*	Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1987).
10.4*	Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant’s Form 10-K for 1999).
31.1	Certification 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 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

(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, President
	and Chief Executive Officer

Dated: March 21, 2007

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
David R. Emery, Chairman, President and	Principal Executive Officer	March 21, 2007
Chief Executive Officer

/s/ MARK T. THIES	Principal Financial and
Mark T. Thies, Executive Vice President and	Accounting Officer	March 21, 2007
Chief Financial Officer

/s/ DAVID C. EBERTZ	Director	March 21, 2007
David C. Ebertz

/s/ JACK W. EUGSTER	Director	March 21, 2007
Jack W. Eugster

/s/ JOHN R. HOWARD	Director	March 21, 2007
John R. Howard

/s/ KAY S. JORGENSEN	Director	March 21, 2007
Kay S. Jorgensen

/s/ RICHARD KORPAN	Director	March 21, 2007
Richard Korpan

/s/ STEPHEN D. NEWLIN	Director	March 21, 2007
Stephen D. Newlin

/s/ JOHN B. VERING	Director	March 21, 2007
John B. Vering

/s/ THOMAS J. ZELLER	Director	March 21, 2007
Thomas J. Zeller

INDEX TO EXHIBITS

Exhibit Number	Description

2*	Plan of Exchange Between Black Hills Corporation and Black Hills Holding Corporation (filed as an exhibit to the Black Hills Holding Corporation’s Registration Statement on Form S-4 (No. 333-52664)).
3.1*	Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).
3.2*	Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).
3.3*	Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).
4.1*	Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as an exhibit to the Registrant’s Registration Statement on Form S-4 (No. 333-52664)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and JPMorgan Chase Bank, as Trustee (filed as Exhibit 10.1 to the Registrant’s Form 10-Q for the quarter ended September 30, 2002).
10.1*	Restated and Amended Coal Supply Agreement for NS II dated February 12, 1993 (filed as Exhibit 10(c) to the Registrant’s Form 10-K for 1992).
10.2*	Second Restated and Amended Power Sales Agreement dated September 29, 1997, between PacifiCorp and Black Hills Power, Inc. (filed as Exhibit 10(e) to the Registrant’s Form 10-K for 1997).
10.3*	Reserve Capacity Integration Agreement dated May 5, 1987, between Pacific Power & Light Company and Black Hills Power, Inc. (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1987).
10.4*	Rate Freeze Extension (filed as Exhibit 10(t) to the Registrant’s Form 10-K for 1999).
31.1	Certification 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 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 Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

__________________________

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

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Black Hills Power 10-K2006 FY Annual report

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