UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934
	For the quarterly period ended ~~September 30, 2008.~~March 31, 2009.
OR
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 (605) 721-1700

Former name, former address, and former fiscal year if changed since last report
NONE

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

Yes

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

Yes

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

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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

Yes

As of ~~October 31, 2008,~~April 30, 2009, there were issued and outstanding 23,416,396 shares of the Registrant’s common stock, $1.00 par value, all of which were held beneficially and of record by Black Hills Corporation.

Reduced Disclosure

The Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this Form 10-Q with the reduced disclosure format.

TABLE OF CONTENTS

		Page

	GLOSSARY OF TERMS	3

PART 1.	FINANCIAL INFORMATION

Item 1.	Financial Statements

	Condensed Statements of Income –
	Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~	4

	Condensed Balance Sheets –
	~~September 30, 2008~~March 31, 2009 and December 31, ~~2007~~2008	5

	Condensed Statements of Cash Flows –
	~~Nine~~Three Months Ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~	6

	Notes to Condensed Financial Statements	7-12

Item 2.	Results of Operations	~~13-18~~13-17

Item 4.	Controls and Procedures	1817

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	18

Item 1A.	Risk Factors	~~18-20~~18

Item 6.	Exhibits	2018

	Signatures	2119

	Exhibit Index	2220

GLOSSARY OF TERMS

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

AFUDC	Allowance for Funds Used During Construction
BHC	Black Hills Corporation, the Parent Company
Black Hills Energy	The name used to conduct the business activities of Black Hills Utility
	Holdings, Inc., a direct subsidiary of the Parent Company
Black Hills Wyoming	Black Hills Wyoming, Inc., an indirect subsidiary of the Parent Company
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary
	of the Parent Company
~~Colorado Electric~~	~~Black Hills Colorado Electric Utility Company, LP, (doing business as~~
	~~Black Hills Energy), an indirect, wholly-owned subsidiary of~~
	~~Black Hills Utility Holdings, formed to hold the Colorado electric~~
	~~utility properties acquired from Aquila~~
CT	Combustion Turbine
Enserco	Enserco Energy, Inc., an indirect subsidiary of the Parent Company
FAS	Financial Accounting Standard
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FSP	FASB Staff Position
FSP FAS 107-1	FSP FAS 107-1, “Interim Disclosure About Fair Value of Financial
	Instruments”
FSP FAS 157-2	FSP FAS 157-2, “Effective Date of FASB Statement No. 157”
FSP FAS ~~157-3~~157-4	FSP FAS ~~157-3,~~157-4, “Determining ~~the Fair Value of~~Whether a ~~Financial Asset when that~~Market is Not Active and a
	~~Asset~~Transaction is Not ~~Active”~~Distressed”
GAAP	Generally Accepted Accounting Principles
LIBOR	London Interbank Offered Rate
MDU	MDU Resources Group, Inc.
MW	Megawatts
MWh	Megawatt-hours
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS ~~159~~	~~SFAS 159, “The Fair Value Option for Financial Assets and Financial~~
	~~Liabilities”~~
~~SFAS~~ 161	SFAS 161, “Disclosure about Derivative Instruments and Hedging Activities –
	an amendment of FASB Statement No. 133”
WRDC	Wyodak Resources Development Corp., an indirect subsidiary of the Parent
	Company

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended					Nine Months Ended					Three Months Ended
	September 30,										March 31,
	2008			2007		2008			2007		2009			2008
	(in thousands)										(in thousands)

Operating revenue	$	59,358	$		51,774	$	174,968	$		144,513	$	54,458	$		57,632

Operating expenses:
Fuel and purchased power		30,119			22,315		85,844			56,020		22,762			27,499
Operations and maintenance		7,604			6,392		23,615			19,073		7,638			7,097
Administrative and general		4,538			5,326		14,612			14,953		6,271			5,464
Depreciation and amortization		5,275			5,197		15,805			15,535		5,047			5,252
Taxes, other than income taxes		1,594			1,396		5,002			5,179		2,035			1,729
		49,130			40,626		144,878			110,760		43,753			47,041

Operating income		10,228			11,148		30,090			33,753		10,705			10,591

Other income (expense):
Interest expense		(2,751)			(2,937)		(7,957)			(8,856)		(2,585)			(2,693)
Interest income		171			256		290			669		112			95
Allowance for funds used
during construction – equity		1,183			161		2,072			402		1,401			284
Other income, net		17			27		185			190		289			115
		(1,380)			(2,493)		(5,410)			(7,595)		(783)			(2,199)

Income before income taxes		8,848			8,655		24,680			26,158		9,922			8,392
Income taxes		(2,477)			(2,874)		(7,482)			(8,797)		(2,958)			(2,816)

Net income	$	6,371	$		5,781	$	17,198	$		17,361	$	6,964	$		5,576

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

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)

	September 30,		December 31,		March 31,		December 31,
	2008		2007		2009		2008
	(in thousands)				(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,351	$	2,033	$	620	$	4
Receivables (net of allowance for doubtful accounts
of $560 and $388, respectively) –
of $371 and $370, respectively) –
Customers		20,531		22,330		19,398		23,881
Affiliates		3,827		8,882		2,944		12,619
Other		1,553		2,198		902		2,111
Money pool note receivable – affiliates		—		10,304
Materials, supplies and fuel		18,094		15,628		19,571		19,309
Other current assets		6,984		3,862		6,511		5,730
		52,340		65,237		49,946		63,654

Investments		3,957		3,774		4,092		3,999

Property, plant and equipment		813,645		695,452		884,978		843,691
Less accumulated depreciation		(280,479)		(266,583)		(285,193)		(281,220)
		533,166		428,869		599,785		562,471

Other assets:
Regulatory assets		10,562		9,899		33,748		33,818
Other		5,483		5,901		2,231		2,842
		16,045		15,800		35,979		36,660
	$	605,508	$	513,680	$	689,802	$	666,784
LIABILITIES AND STOCKHOLDER’S EQUITY

Current liabilities:
Current maturities of long-term debt	$	2,014	$	2,009	$	32,019	$	2,016
Accounts payable		24,161		12,982		28,867		26,567
Accounts payable – affiliates		10,721		3,158		4,712		10,411
Notes payable – affiliates		49,796		—		85,673		70,184
Accrued liabilities		11,927		13,898		15,962		15,151
Deferred income taxes		823		18		1,119		732
		99,442		32,065		168,352		125,061

Long-term debt, net of current maturities		149,209		151,209		119,176		149,193

Deferred credits and other liabilities:
Deferred income taxes		75,997		69,761		87,093		85,504
Regulatory liabilities		13,312		11,085		14,026		13,573
Benefit plan liabilities						30,926		29,904
Other		18,009		17,140		8,331		8,626
		107,318		97,986		140,376		137,607
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized;
23,416,396 shares issued		23,416		23,416		23,416		23,416
Additional paid-in capital		39,575		39,575		39,575		39,575
Retained earnings		187,904		170,706		200,245		193,281
Accumulated other comprehensive loss		(1,356)		(1,277)		(1,338)		(1,349)
		249,539		232,420		261,898		254,923
	$	605,508	$	513,680	$	689,802	$	666,784

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

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended				Three Months Ended
	September 30,				March 31,
	2008		2007		2009		2008
	(in thousands)				(in thousands)

Operating activities:
Net income	$	17,198	$	17,361	$	6,964		$	5,576
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation and amortization		15,805		15,535		5,047			5,252
Provision for valuation allowances						1			185
Deferred income tax		6,580		3,034		1,867			594
Allowance for funds used during construction –
equity		(2,072)		(402)		(1,401)			(284)
Change in operating assets and liabilities –
Accounts receivable and other current assets		4,088		(5,928)		14,322			10,001
Accounts payable and other current liabilities		(1,048)		(4,948)		(9,684)			(740)
Other operating activities		(1,680)		2,063		1,454			240
		38,871		26,715		18,570			20,824
Investing activities:
Property, plant and equipment additions		(97,475)		(19,726)		(33,336)			(26,388)
Change in affiliate money pool borrowings, net		10,304		(4,918)
Change in money pool notes receivable from
affiliate, net						—			8,734
Other investing activities		(183)		(177)		(93)			(115)
		(87,354)		(24,821)		(33,429)			(17,769)

Financing activities:
Notes payable – affiliate		49,796		—
Long-term debt – repayments		(1,995)		(1,989)		(14)			(14)
Change in money pool note payable to
affiliate, net						15,489			—
		47,801		(1,989)		15,475			(14)

Decrease in cash and cash equivalents		(682)		(95)
Increase in cash and cash equivalents						616			3,041

Cash and cash equivalents:
Beginning of period		2,033		1,223		4			2,033
End of period	$	1,351	$	1,128	$	620		$	5,074

Supplemental disclosure of cash flow information:

Non-cash investing and financing activities:
Property, plant and equipment acquired
with accrued liabilities	$	15,750	$	764	$	22,524		$	5,372

Cash paid during the period for:
Interest (net of amounts capitalized)	$	9,833	$	9,935	$	4,017		$	4,480
Income taxes paid	$	3,396	$	14,847
Income taxes refunded					$	(218)		$	—

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

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in the Company’s ~~2007~~2008 Annual Report on Form 10-K)

(1)	MANAGEMENT’S STATEMENT

The condensed financial statements included herein have been prepared by Black Hills Power, Inc., (the ~~Company)~~“Company,” “we,” “us,” “our”) without audit, pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, ~~the Company believes~~we believe that the footnotes adequately disclose the information presented. These financial statements should be read in conjunction with the financial statements and the notes thereto, included in ~~the Company’s 2007~~our 2008 Annual Report on Form 10-K filed with the SEC.

Accounting methods historically employed require certain estimates as of interim dates. The information furnished in the accompanying financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the ~~September 30, 2008,~~March 31, 2009, December 31, ~~2007~~2008 and ~~September 30, 2007~~March 31, 2008 financial information and are of a normal recurring nature. The results of operations for the ~~nine~~three months ended ~~September 30, 2008,~~March 31, 2009, are not necessarily indicative of the results to be expected for the full year.

(2)	RECENTLY ADOPTED ACCOUNTING PRONOUNCEMENTS

SFAS 157

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

~~SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. As of January 1, 2008, the Company~~We adopted the provisions of SFAS 157 on January 1, 2008 for all assets and liabilities measured at fair value ~~except~~for financial measurements. As permitted by FSP FAS 157-2, we deferred adoption for non-financial assets and liabilities measured at fair value on a non-recurring basis ~~as permitted by FSP FAS 157-2.~~until January 1, 2009. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with instruments carried at fair value. On October 10, 2008, the FASB issued FSP FAS 157-3. It was effective upon issuance including prior periods for which financial statements have not been issued. This FSP clarifies the application of FAS 157 in a market that is not active. The adoption of SFAS 157 and related FSPs did not have a material impact on ~~the Company’s~~our financial position, results of operations or cash flows.

~~SFAS 159~~

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

~~(3)~~

~~RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS~~

SFAS 161

In March 2008, the FASB issued SFAS 161 which requires enhanced disclosures about how derivative and hedging activities affect an entity’s financial position, financial performance and cash flows. ~~This Statement~~SFAS 161 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption.

At March 31, 2009, we do not hold any derivative instruments. We occasionally hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we occasionally utilize various derivative instruments in managing these risks. Additionally, we engage in activities to manage risk associated with changes in interest rates. In prior years, we entered into floating-to-fixed interest rate swap agreements to minimize our exposure to interest rate fluctuations associated with our floating rate debt obligations. These swaps were designated as cash flow hedges in accordance with SFAS 133, and accordingly the resulting gain or loss is carried in Accumulated other comprehensive loss on the accompanying Condensed Balance Sheets and amortized over the life of the related debt. For the three months ended March 31, 2009 and 2008, respectively, we amortized less than $0.1 million from Accumulated other comprehensive loss to Interest expense related to a settled interest rate swap designated as a cash flow hedge.

(3)	RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

FSP FAS 157-4

In April 2009, the FASB approved FSP FAS 157-4 effective for interim and annual periods ending after June 15, 2009. This FSP amends FAS 157 to address inactive markets. This FSP includes a two step model with the first step determining whether factors exist that indicate a market for an asset is not active. If step one results in the conclusion that there is not an active market, step two evaluates whether the quoted price is not associated with a distressed transaction. Additional disclosures will be required. We do not anticipate that the adoption of FSP FAS 157-4 will have an impact on our operating results, financial ~~statements issued~~position or cash flows.

FSP FAS 107-1

In April 2009, the FASB approved FSP FAS 107-1 effective for ~~fiscal years~~interim and ~~interim~~annual periods ~~beginning~~ending after ~~November~~June 15, ~~2008. The Company is~~2009. This FSP will require more frequent disclosures of fair value for public companies. We are currently ~~evaluating~~assessing the impact ofthat the adoption ~~of SFAS 161.~~will have on our disclosures.

(4)	OTHER COMPREHENSIVE INCOME

The following table presents the components of ~~the Company’s~~ Other comprehensive income (in thousands):

	Three Months Ended				Three Months Ended
	September 30,				March 31,
	2008		2007		2009		2008

Net income	$	6,371	$	5,781	$	6,964	$	5,576
Other comprehensive income, net of tax:
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges (net of
tax of $(6) and $34, respectively)		10		(62)
tax of $(6) and $(38), respectively)						11		71
Reclassification adjustments included
in net income (net of tax of $0 and $(5))		—		10
in net income (net of tax of $93)						—		(171)
Total comprehensive income	$	6,381	$	5,729	$	6,975	$	5,476

Nine Months Ended

September 30,

2008
2007

Net income
$
17,198
$
17,361
Other comprehensive income (loss), net of tax:

Fair value adjustment on derivatives

designated as cash flow hedges (net of

tax of $(18) and $197, respectively)

30

(366)
Reclassification adjustments included

in net income (net of tax of $60 and $154,

respectively)

(109)

(285)
Total comprehensive income
$
17,119
$
16,710

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

Derivatives
Employee

Designated as
Benefit

Cash Flow Hedges
Plans
Total

As of September 30, 2008
$
(940)
$
(416)
$
(1,356)

As of December 31, 2007
$
(861)
$
(416)
$
(1,277)

	Derivatives		Employee
	Designated as		Benefit
	Cash Flow Hedges		Plans		Total

As of March 31, 2009	$	(921)	$	(417)	$	(1,338)

As of December 31, 2008	$	(932)	$	(417)	$	(1,349)

(5)	RELATED-PARTY TRANSACTIONS

Receivables and Payables

~~The Company has~~We have accounts receivable balances related to transactions with other BHC subsidiaries. The balances were ~~$3.8~~$2.9 million and ~~$8.9~~$12.6 million as of ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007,~~2008, respectively. ~~The Company~~We also ~~has~~have accounts payable balances related to transactions with other BHC subsidiaries. The balances were ~~$10.7~~$4.7 million and ~~$3.2~~$10.4 million as of ~~September 30, 2008~~March 31, 2009 and December 31, ~~2007,~~2008, respectively.

Money Pool Notes Receivable and Notes Payable

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

~~The Company through~~Through the Utility Money Pool, we had net note payable balances of ~~$49.8~~$85.7 million and $70.2 million as of ~~September 30, 2008~~March 31, 2009 and ~~a net note receivable of $10.3 million as of~~ December 31, ~~2007.~~2008, respectively. Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (which equates to ~~4.63 percent~~1.2% at ~~September 30, 2008)~~March 31, 2009). Net interest expense ~~was approximately~~of $0.4 ~~million and $0.4 million for the three months and nine months ended September 30, 2008, respectively. Net interest income of $0.3 million and $0.7~~ million was recorded for the three months ended March 31, 2009 and ~~nine~~net interest income of less than $0.1 million for the three months ended ~~September 30, 2007, respectively.~~March 31, 2008.

Other Balances and Transactions

~~The Company~~We also received revenues of approximately ~~$0.3~~$0.2 million and ~~$0.6~~$0.3 million for the three months ended ~~September 30,~~March 31, 2009 and 2008, ~~and 2007, respectively; and $1.0 million and $1.6 million for the nine months ended September 30, 2008 and 2007,~~ respectively, from Black Hills Wyoming for the transmission of electricity.

~~The Company~~We recorded revenues of $0.2 million ~~and $1.3 million~~ for the ~~nine~~three months ended ~~September 30,~~March 31, 2008, ~~and 2007, respectively,~~ relating to payments received pursuant to a natural gas swap entered into with Enserco, with a third party transacted by Enserco on ~~the Company’s~~our behalf.

~~The Company~~We received revenues of approximately ~~$0.4~~$0.3 million and ~~$1.5~~$0.7 million for the three months ~~and nine months~~ ended ~~September 30,~~March 31, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.

On July 14, 2008, BHC purchased one electric utility in Colorado and four gas utilities in Colorado, Nebraska, Iowa and Kansas from Aquila, Inc. Through this acquisition, the Company became affiliated with these utilities now known as Black Hills Energy. Under a General Dispatch and Energy Management Agreement approved by FERC, the Company commenced providing services to Colorado Electric. The Company received revenues of $0.2 million for the three and nine months ended September 30, 2008.

~~The Company purchases~~We purchase coal from WRDC. The amount purchased during the three months ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~ was ~~$4.9~~$3.9 million and ~~$2.9~~$3.1 million, ~~respectively; and $10.8 million and $8.4 million for the nine months ended September 30, 2008 and 2007,~~ respectively.

~~The Company purchases~~We purchase excess power generated by Cheyenne Light. The amount purchased during the three months ended March 31, 2009 was $2.0 million, including $0.8 million for wind-generated power, and ~~nine~~$1.3 million for the three months ended ~~September 30,~~March 31, 2008. On August 28, 2008, ~~was $1.5 million and $4.6 million, respectively.~~we entered into a contract with Cheyenne Light ~~placed a 95~~under which Cheyenne Light sells up to 20 MW ~~base load coal-fired power plant into service on January 1, 2008.~~of wind-generated, renewable energy to us until 2028.

In order to fuel ~~its~~our combustion turbine, ~~the Company purchased~~we purchase natural gas from Enserco. The amount purchased during the three months ended ~~September 30,~~March 31, 2009 and 2008 ~~and 2007~~ was ~~$3.0~~$0.1 million and ~~$2.7~~less than $0.1 million, ~~respectively; and $6.6 million and $4.3 million for the nine months ended September 30, 2008 and 2007,~~ respectively. These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.

In addition, ~~the Company~~we also ~~pays~~pay the Parent for allocated corporate support service cost incurred on ~~its~~our behalf. Corporate costs allocated from the Parent were ~~$2.8~~$3.6 million and ~~$3.0~~$3.1 million for the three months ended ~~September 30,~~March 31, 2009 and 2008, ~~and 2007, respectively; and $8.9 million and $8.5 million for the nine months ended September 30, 2008 and 2007,~~ respectively.

~~The Company has~~We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $1.9 million as of ~~September 30, 2008~~March 31, 2009 and ~~$1.8 million as of~~ December 31, ~~2007,~~2008, respectively, which is included in Other, Deferred credits and other liabilities on the accompanying Condensed Balance Sheets. Interest on the funds accrues quarterly at an average quarterly prime rate ~~(5.3 percent~~(4.52% at ~~September 30, 2008)~~March 31, 2009).

~~On August 28, 2008 the Company entered into a contract with Cheyenne Light under which Cheyenne Light will sell up to 20 MW wind-generated, renewable energy to the Company until 2028.~~

(6)	EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

~~The Company has~~We have a noncontributory defined benefit pension plan (Plan) covering the employees ~~of the Company~~ who meet certain eligibility requirements.

The components of net periodic benefit cost for the Plan are as follows (in thousands):

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,								March 31,
	2008		2007		2008		2007		2009		2008

Service cost	$	279	$	284	$	837	$	852	$	292	$	279
Interest cost		758		731		2,274		2,193		785		758
Expected return on plan assets		(1,094)		(971)		(3,282)		(2,913)		(657)		(1,094)
Prior service cost		28		26		84		78		28		28
Net loss		—		102		—		306		430		—

Net periodic benefit cost	$	(29)	$	172	$	(87)	$	516	$	878	$	(29)

~~The Company does not anticipate that it will need to make a~~A contribution totaling less than $0.1 million was made to the Plan in the ~~2008 fiscal year.~~first quarter of 2009. There are no further contributions expected to be made to the Plan in 2009.

Supplemental Nonqualified Defined Benefit Plans

~~The Company has~~We have various supplemental retirement plans for key executives ~~of the Company~~ (Supplemental Plans). The Supplemental Plans are non-qualified defined benefit plans.

The components of net periodic benefit cost for the Supplemental Plans are as follows (in thousands):

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,								March 31,
	2008		2007		2008		2007		2009		2008

Interest cost	$	30	$	28	$	90	$	84	$	25	$	30
Net loss		11		14		33		42		11		11

Net periodic benefit cost	$	41	$	42	$	123	$	126	$	36	$	41

~~The Company anticipates~~We anticipate that itwe will make contributions to the Supplemental Plans for the ~~2008~~2009 fiscal year of approximately $0.1 million. Contributions are expected to be in the form of benefit payments.

Non-pension Defined Benefit Postretirement Plans

Employees who are participants in the ~~Company’s~~ Postretirement Healthcare Plans (Healthcare Plans) and who meet certain eligibility requirements are entitled to postretirement healthcare benefits.

The components of net periodic benefit cost for the Healthcare Plans are as follows (in thousands):

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,								March 31,
	2008		2007		2008		2007		2009		2008

Service cost	$	52	$	52	$	156	$	156	$	54	$	52
Interest cost		104		100		312		300		111		104
Net transition obligation		13		13		39		39		13		13

Net periodic benefit cost	$	169	$	165	$	507	$	495	$	178	$	169

~~The Company anticipates~~We anticipate that itwe will make contributions to the Healthcare Plan for the ~~2008~~2009 fiscal year of approximately $0.2 million. Contributions are expected to be made in the form of benefit payments.

It has been determined that the ~~Company’s~~ post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy ~~is not material to the Company.~~was $0.1 million.

(7)	LEGAL PROCEEDINGS

~~The Company is~~We are subject to various legal proceedings, claims and litigation as described in Note 11 of the Notes to Financial Statements in ~~the Company’s 2007~~our 2008 Annual Report on Form 10-K. There have been no material developments in any previously reported proceedings or any new material proceedings that have developed or material proceedings that have terminated during the first ~~nine~~three months of ~~2008.~~2009.

(8)	SUBSEQUENT EVENTS

On April 9, 2009, we sold a 25% ownership interest in our Wygen III generation facility to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility. MDU will continue to reimburse us for its 25% of the total costs paid to complete the project. In conjunction with the sales transaction, we also modified a 2004 power purchase agreement under which we supplied MDU with 74 MW of capacity and energy through 2016.

Extension of Long-Term Power Sales Agreement with MEAN

In March 2009, our 10-year power sales contract with MEAN that originally expired in 2013 was re-negotiated and extended until 2023. Under the new contract, MEAN will purchase 20 MW of unit-contingent capacity from the Neil Simpson II and the Wygen III plants with capacity purchase decreasing to 15 MW in 2018, 12 MW in 2020 and 10 MW in 2022. The unit-contingent capacity from Wygen III and Neil Simpson II plants are as follows:

20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II

15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II

10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

ITEM 2.

RESULTS OF OPERATIONS

	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,								March 31,
	2008		2007		2008		2007		2009		2008
	(in thousands)								(in thousands)

Revenue	$	59,358	$	51,774	$	174,968	$	144,513	$	54,458	$	57,632
Fuel and purchased power		30,119		22,315		85,844		56,020		22,762		27,499
Gross margin		29,239		29,459		89,124		88,493		31,696		30,133

Operating expenses		19,011		18,311		59,034		54,740		20,991		19,542
Operating income	$	10,228	$	11,148	$	30,090	$	33,753	$	10,705	$	10,591

Net income	$	6,371	$	5,781	$	17,198	$	17,361	$	6,964	$	5,576

The following tables provide certain operating ~~statistics for the Company:~~statistics:

	Electric Revenue										Electric Revenue
	(in thousands)										(in thousands)

	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
			Percentage					Percentage						Percentage
Customer Base	2008		Change	2007		2008		Change	2007		2009			Change		2008

Commercial	$	15,735	(4)%	$	16,328	$	42,231	(1)%	$	42,502	$	14,643	9%		$		13,484
Residential		11,168	(11)		12,564		34,187	(1)		34,662		14,281	10				12,966
Industrial		5,500	(1)		5,558		16,337	1		16,137		4,750	(10)				5,296
Municipal sales		783	(3)		808		2,047	1		2,033		636	2				625
Total retail sales		33,186	(6)		35,258		94,802	(1)		95,334		34,310	6				32,371
Contract wholesale		6,862	5		6,566		20,064	7		18,855		6,553	(5)				6,931
Wholesale off system		13,315	86		7,157		47,650	125		21,155		9,220	(39)				15,097
Total electric sales		53,363	9		48,981		162,516	20		135,344		50,083	(8)				54,399
Other revenue		5,995	115		2,793		12,452	36		9,169		4,375	34				3,233
Total revenue	$	59,358	15%	$	51,774	$	174,968	21%	$	144,513	$	54,458	(6)%		$		57,632

	Megawatt Hours Sold

	Three Months Ended March 31,
			Percentage
Customer Base	2009		Change		2008

Commercial		175,256		1%		173,459
Residential		163,476		—		163,034
Industrial		85,984		(16)		102,669
Municipal sales		8,095		(1)		8,208
Total retail sales		432,811		(3)		447,370
Contract wholesale		168,679		(2)		171,620
Wholesale off system		243,786		7		227,741
Total electric sales		845,276		—%		846,731

	Electric Utility Power Plant Availability

	Three Months Ended March 31,
	2009	2008

Coal-fired plants	96.5%	94.9%
Other plants	99.5%	94.9%
Total availability	97.8%	94.9%

Megawatt Hours Sold

Three Months Ended September 30,
Nine Months Ended September 30,

Percentage

Percentage

Customer Base
2008
Change
2007
2008
Change
2007

Commercial

195,661
(2)%

199,239

531,433
1%

525,815
Residential

120,888
(11)

136,297

398,028
1

395,820
Industrial

107,380
(5)

112,541

319,077
(1)

321,798
Municipal sales

10,228
(4)

10,681

26,073
1

25,890
Total retail sales

434,157
(5)

458,758

1,274,611
—

1,269,323
Contract wholesale

165,872
(2)

169,211

494,457
2

486,149
Wholesale off system

241,546
70

141,930

753,057
77

426,143
Total electric sales

841,575
9%

769,899

2,522,125
16%

2,181,615

	Megawatt Hours Generated and Purchased

	Three Months Ended March 31,
		Percentage
Resources	2009	Change	2008

Coal	437,551	1%	432,882
Gas	1,075	(97)	37,000
	438,626	(7)	469,882

MWhs purchased	432,839	13	384,581
Total resources	871,465	2%	854,463

Electric Utility Power Plant Availability

Three Months Ended September 30,
Nine Months Ended September 30,

2008
2007
2008
2007

Coal-fired plants
95.8%
96.6%
91.8%*
95.5%
Other plants
98.7%
99.8%
90.6%
99.6%
Total availability
97.1%
98.0%
91.3%
97.3%

~~___________________________~~

Reflects major maintenance outages at our Ben French, Neil Simpson I and Osage coal-fired plants. The Ben French outage was scheduled for 25 days and was subsequently extended to accelerate major maintenance originally scheduled for 2009. The actual outage was 88 days and resulted in the plant’s output being restored to its full rated capacity. The Osage outage was originally scheduled for approximately 10 days and lasted 52 days as a result of additional unplanned required maintenance. The plants were all online by the end of the second quarter.

Megawatt Hours Generated and Purchased

Three Months Ended September 30,
Nine Months Ended September 30,

Percentage

Percentage

Resources
2008
Change
2007
2008
Change
2007

Coal
450,884
2%
441,626
1,268,514
(4)%
1,316,851
Gas
11,856
(65)
34,117
53,687
(22)
68,458

462,740
(3)%
475,743
1,322,201
(5)%
1,385,309

MWhs purchased
404,148
26%
321,396
1,256,835
44%
870,447
Total resources
866,888
9%
797,139
2,579,036
14%
2,255,756

	Heating Degree Days

	Three Months Ended
	March 31,
	2009	2008
Heating degree days:
Actual
Heating degree days	3,254	3,361

Variance from normal
Heating degree days	(1)%	2%

Heating and Cooling Degree Days

Three Months Ended
Nine Months Ended

September 30,
September 30,

2008
2007
2008
2007
Heating and cooling degree days:

Actual

Heating degree days
223
171
4,814
4,083
Cooling degree days
453
830
482
1,033

Percent of normal

Heating degree days
98%
81%
106%
91%
Cooling degree days
92%
168%
81%
174%

Three Months Ended ~~September 30, 2008~~March 31, 2009 Compared to Three Months Ended ~~September 30, 2007.~~March 31, 2008. Net income increased ~~$0.6~~$1.4 million from the prior period primarily due to the following:

• ~~Income related~~Retail and wholesale sales margins increased $1.4 million primarily due to ~~the impact~~transmission rate increases effective January 1, 2009; and

• Increased AFUDC of ~~$1.7~~$1.6 million ~~of AFUDC~~ primarily attributable to the ongoing construction of Wygen III.

Partially offsetting the increases were the following:

• Retail and wholesale sales margins decreased due to increased fuel costs and lower MWhs sold. We have a pass-through mechanism for increased purchase power costs for South Dakota customers, which is subject to a $2.0 million threshold before those costs can be passed on to South Dakota customers. As of September 30, 2008, we have met the $2.0 million threshold;

•Margins from wholesale off-system sales decreased ~~$0.4~~$1.0 million due to ~~increased purchase power cost partially offset by increased wholesale off-system MWhs sold of 70 percent;~~decreases in energy prices; and

• Increased ~~operating expense due to increased repair and maintenance expenses and labor/overhead costs.~~

~~Nine Months Ended September 30, 2008 Compared to Nine Months Ended September 30, 2007.~~ ~~Net income decreased $0.2 million from the prior period primarily due to the following:~~

• ~~A $1.9 million reduction in retail and wholesale sales margins due to increased fuel and purchased power~~benefit plan costs ~~primarily due to scheduled and unscheduled outages at our Ben French, Osage and Neil Simpson I coal-fired plants. The plants were back online at the end~~ of the second quarter. The duration of the Ben French Plant outage was approximately three months as we accelerated the completion of maintenance projects that were originally scheduled for this plant in 2009. We have a pass-through mechanism for increased purchase power costs for South Dakota customers, which is subject to a $2.0 million threshold before those costs can be passed on to South Dakota customers. As of September 30, 2008, we have met the $2.0 million threshold; and

• ~~Increased operating expense due to increased repair and maintenance expenses and outside services primarily related to the plant outages and personnel costs.~~

~~Partially offsetting the increased costs were the following:~~

• ~~Margins from wholesale off-system sales increased $2.4~~$1.0 million. Total MWhs increased 77 percent as we were able to take advantage of favorable market conditions and high MIDC pricing due to below normal temperatures, partially offset by higher cost purchased power and increased cost of fuel; and

• ~~Income related to the impact of $3.0 million of AFUDC primarily attributable to the ongoing construction of Wygen III.~~

Wygen III Power Plant Project

In March 2008, we received final regulatory approval for construction of Wygen III. Construction began immediately and the ~~100~~110 MW coal-fired base load electric generating facility is expected to ~~take 24 to 30 months to complete.~~be completed in June 2010. The expected cost of construction is approximately $255 million, which includes estimates for AFUDC. A 2004 agreement with MDU included an option to purchase an ownership interest in Wygen III. In April 2009, MDU exercised this option, and we sold a 25% ownership interest in Wygen III to MDU. We ~~expect to~~will retain ownership of ~~75 MW~~75% of the facility’s capacity with MDU ~~currently being expected to take ownership of~~owning the remaining ~~25 MW.~~25%. We will retain responsibility for operations of the facility with a life-of-plant site lease, and agreements with MDU for operations and coal ~~supply agreements in place with MDU.~~supply.

SAFE HARBOR FOR FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including the risk factors described in Item 1A of our ~~2007~~2008 Annual Report on Form 10-K and in Item 1A. of Part II of this Quarterly Report on Form 10-Q filed with the SEC, and the following:

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

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

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

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

• The timing and extent of scheduled and unscheduled outages 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.

ITEM 4.

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 ~~September 30, 2008.~~March 31, 2009. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the quarter ended ~~September 30, 2008~~March 31, 2009 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

BLACK HILLS POWER, INC.

Part II – Other Information

Item 1.

Legal Proceedings

For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of ~~the Company’s 2007~~our 2008 Annual Report on Form 10-K and Note 7 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 7 is incorporated by reference into this item.

Item 1A.

Risk Factors

~~Except as set forth below, there~~There have been no material changes in our Risk Factors from those reported in Item 1A. of Part I of our ~~2007~~2008 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

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

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

Recent financial distress within the global economy has caused significant disruption in the credit markets. Among other things, long-term interest rates on debt securities have increased significantly and the volume of equity and debt security issuances has decreased. Recent actions taken by the United States government, the Federal Reserve and other governmental and regulatory bodies may be insufficient to stabilize these markets. The longer such conditions persist, the more significant the implications become for the Company.

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

Recent concerns over inflation, energy costs, the availability and cost of credit, and increased unemployment have contributed to an economic slowdown and fears of recession. These factors could lead to an increase in late payments from utility customers and uncollectible accounts could increase, which could materially reduce our earnings and cash flows.

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

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

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

We own regulated coal-fired power plants in Wyoming. Air emissions of coal-fired power plants are subject to federal and state regulation. Recent changes in federal and state laws governing air emissions from coal-burning power plants will result in more stringent emission limitations. As the issue of climate change, particularly with respect to CO₂ emissions by coal-fired power plants, receives increased attention, further emission limitations could be imposed. To the extent our coal-fired power plants are included in rate base, we will attempt to recover costs associated with complying with emission standards; however, there can be no assurance that we will be permitted to recover such compliance costs in customer rates. In addition, future changes in environmental regulations governing air pollutants could render some of our electric generating units more expensive or uneconomical to operate and maintain.

We serve electric utility customers in Montana, South Dakota, and Wyoming. Montana has adopted renewable portfolio standards that require electric utilities to source a minimum percentage of the power delivered to customers by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If Montana increases their renewable energy portfolio standards, or if similar standards are imposed by the other states in which we operate electric utilities, our power supply costs will further increase (and could increase materially). Although we will seek to recover these higher costs in rates, we can provide no assurance that we will be able to fully recover such costs.

Item 6.

Exhibits

Exhibit 31.1		Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 31.2		Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

BLACK HILLS POWER, INC.

Signatures

Pursuant to the requirements 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.


	/S/ DAVID R. EMERY
	David R. Emery, Chairman
	and Chief Executive Officer


	/S/ ANTHONY S. CLEBERG
	Anthony S. Cleberg, Executive Vice President
	and Chief Financial Officer

Dated: ~~November~~May 14, ~~2008~~2009

EXHIBIT INDEX

Exhibit Number	Description


Exhibit 31.1	Certification of Chief Executive Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 31.2	Certification of Chief Financial Officer pursuant to Rule 13a – 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

Exhibit 32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

	Heating and Cooling Degree Days

	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2008	2007	2008	2007
Heating and cooling degree days:
Actual
Heating degree days	223	171	4,814	4,083
Cooling degree days	453	830	482	1,033

Percent of normal
Heating degree days	98%	81%	106%	91%
Cooling degree days	92%	168%	81%	174%