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.
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 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, 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, 2008 and 2007	4

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

	Condensed Statements of Cash Flows –
	Nine Months Ended September 30, 2008 and 2007	6

	Notes to Condensed Financial Statements	7-12

Item 2.	Results of Operations	13-18

Item 4.	Controls and Procedures	18

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	18

Item 1A.	Risk Factors	18-20

Item 6.	Exhibits	20

	Signatures	21

	Exhibit Index	22

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, 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
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FSP	FASB Staff Position
FSP FAS 157-2	FSP FAS 157-2, “Effective Date of FASB Statement No. 157”
FSP FAS 157-3	FSP FAS 157-3, “Determining the Fair Value of a Financial Asset when that
	Asset is Not Active”
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
	September 30,					September 30,
	2008			2007		2008			2007
	(in thousands)

Operating revenue	$	59,358	$		51,774	$	174,968	$		144,513

Operating expenses:
Fuel and purchased power		30,119			22,315		85,844			56,020
Operations and maintenance		7,604			6,392		23,615			19,073
Administrative and general		4,538			5,326		14,612			14,953
Depreciation and amortization		5,275			5,197		15,805			15,535
Taxes, other than income taxes		1,594			1,396		5,002			5,179
		49,130			40,626		144,878			110,760

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

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

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

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

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,
	2008		2007
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,351	$	2,033
Receivables (net of allowance for doubtful accounts
of $560 and $388, respectively) –
Customers		20,531		22,330
Affiliates		3,827		8,882
Other		1,553		2,198
Money pool note receivable – affiliates		—		10,304
Materials, supplies and fuel		18,094		15,628
Other current assets		6,984		3,862
		52,340		65,237

Investments		3,957		3,774

Property, plant and equipment		813,645		695,452
Less accumulated depreciation		(280,479)		(266,583)
		533,166		428,869

Other assets:
Regulatory assets		10,562		9,899
Other		5,483		5,901
		16,045		15,800
	$	605,508	$	513,680
LIABILITIES AND STOCKHOLDER’S EQUITY

Current liabilities:
Current maturities of long-term debt	$	2,014	$	2,009
Accounts payable		24,161		12,982
Accounts payable – affiliates		10,721		3,158
Notes payable – affiliates		49,796		—
Accrued liabilities		11,927		13,898
Deferred income taxes		823		18
		99,442		32,065

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

Deferred credits and other liabilities:
Deferred income taxes		75,997		69,761
Regulatory liabilities		13,312		11,085
Other		18,009		17,140
		107,318		97,986
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized;
23,416,396 shares issued		23,416		23,416
Additional paid-in capital		39,575		39,575
Retained earnings		187,904		170,706
Accumulated other comprehensive loss		(1,356)		(1,277)
		249,539		232,420
	$	605,508	$	513,680

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
	September 30,
	2008		2007
	(in thousands)

Operating activities:
Net income	$	17,198	$	17,361
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation and amortization		15,805		15,535
Deferred income tax		6,580		3,034
Allowance for funds used during construction –
equity		(2,072)		(402)
Change in operating assets and liabilities –
Accounts receivable and other current assets		4,088		(5,928)
Accounts payable and other current liabilities		(1,048)		(4,948)
Other operating activities		(1,680)		2,063
		38,871		26,715
Investing activities:
Property, plant and equipment additions		(97,475)		(19,726)
Change in affiliate money pool borrowings, net		10,304		(4,918)
Other investing activities		(183)		(177)
		(87,354)		(24,821)

Financing activities:
Notes payable – affiliate		49,796		—
Long-term debt – repayments		(1,995)		(1,989)
		47,801		(1,989)

Decrease in cash and cash equivalents		(682)		(95)

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

Supplemental disclosure of cash flow information:

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

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

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 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) 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 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 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, December 31, 2007 and September 30, 2007 financial information and are of a normal recurring nature. The results of operations for the nine months ended September 30, 2008, 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 adopted the provisions of SFAS 157 for all assets and liabilities measured at fair value except for non-financial assets and liabilities measured at fair value on a non-recurring basis, as permitted by FSP FAS 157-2. SFAS 157 also requires new disclosures regarding the level of pricing observability associated with instruments carried at fair value. On October 10, 2008, the FASB issued FSP FAS 157-3. It was effective upon issuance including prior periods for which financial statements have not been issued. This FSP clarifies the application of 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 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 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the impact of adoption of SFAS 161.

(4)	OTHER COMPREHENSIVE INCOME

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

	Three Months Ended
	September 30,
	2008		2007

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

	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)

(5)	RELATED-PARTY TRANSACTIONS

Receivables and Payables

The Company has accounts receivable balances related to transactions with other BHC subsidiaries. The balances were $3.8 million and $8.9 million as of September 30, 2008 and December 31, 2007, respectively. The Company also has accounts payable balances related to transactions with other BHC subsidiaries. The balances were $10.7 million and $3.2 million as of September 30, 2008 and December 31, 2007, respectively.

Money Pool Notes Receivable and Notes Payable

The Company has entered into a Utility Money Pool Agreement with BHC, Cheyenne Light and Black Hills Energy. 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 net note payable balances of $49.8 million as of September 30, 2008 and a net note receivable of $10.3 million as of December 31, 2007. Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (which equates to 4.63 percent at September 30, 2008). Net interest expense was approximately $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 and nine months ended September 30, 2007, respectively.

Other Balances and Transactions

The Company also received revenues of approximately $0.3 million and $0.6 million for the three months ended September 30, 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 recorded revenues of $0.2 million and $1.3 million for the nine months ended September 30, 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 behalf.

The Company received revenues of approximately $0.4 million and $1.5 million for the three months and nine months ended September 30, 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 coal from WRDC. The amount purchased during the three months ended September 30, 2008 and 2007 was $4.9 million and $2.9 million, respectively; and $10.8 million and $8.4 million for the nine months ended September 30, 2008 and 2007, respectively.

The Company purchases excess power generated by Cheyenne Light. The amount purchased during the three months and nine months ended September 30, 2008 was $1.5 million and $4.6 million, respectively. Cheyenne Light placed a 95 MW base load coal-fired power plant into service on January 1, 2008.

In order to fuel its combustion turbine, the Company purchased natural gas from Enserco. The amount purchased during the three months ended September 30, 2008 and 2007 was $3.0 million and $2.7 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 also pays the Parent for allocated corporate support service cost incurred on its behalf. Corporate costs allocated from the Parent were $2.8 million and $3.0 million for the three months ended September 30, 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 funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $1.9 million as of September 30, 2008 and $1.8 million as of December 31, 2007, 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 at September 30, 2008).

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 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
	September 30,				September 30,
	2008		2007		2008		2007

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

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

The Company does not anticipate that it will need to make a contribution to the Plan in the 2008 fiscal year.

Supplemental Nonqualified Defined Benefit Plans

The Company has 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
	September 30,				September 30,
	2008		2007		2008		2007

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

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

The Company anticipates that it will make contributions to the Supplemental Plans for the 2008 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
	September 30,				September 30,
	2008		2007		2008		2007

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

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

The Company anticipates that it will make contributions to the Healthcare Plan for the 2008 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.

(7)	LEGAL PROCEEDINGS

The Company is subject to various legal proceedings, claims and litigation as described in Note 11 of the Notes to Financial Statements in the Company’s 2007 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 months of 2008.

ITEM 2.

RESULTS OF OPERATIONS

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

Revenue	$	59,358	$	51,774	$	174,968	$	144,513
Fuel and purchased power		30,119		22,315		85,844		56,020
Gross margin		29,239		29,459		89,124		88,493

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

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

The following tables provide certain operating statistics for the Company:

	Electric Revenue
	(in thousands)

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

Commercial	$	15,735	(4)%	$	16,328	$	42,231	(1)%	$	42,502
Residential		11,168	(11)		12,564		34,187	(1)		34,662
Industrial		5,500	(1)		5,558		16,337	1		16,137
Municipal sales		783	(3)		808		2,047	1		2,033
Total retail sales		33,186	(6)		35,258		94,802	(1)		95,334
Contract wholesale		6,862	5		6,566		20,064	7		18,855
Wholesale off system		13,315	86		7,157		47,650	125		21,155
Total electric sales		53,363	9		48,981		162,516	20		135,344
Other revenue		5,995	115		2,793		12,452	36		9,169
Total revenue	$	59,358	15%	$	51,774	$	174,968	21%	$	144,513

	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

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

• Income related to the impact of $1.7 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 million due to increased purchase power cost partially offset by increased wholesale off-system MWhs sold of 70 percent; 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 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 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 MW coal-fired base load electric generating facility is expected to take 24 to 30 months to complete. The expected cost of construction is approximately $255 million, which includes estimates for AFUDC. We expect to retain ownership of 75 MW of the facility’s capacity with MDU currently being expected to take ownership of the remaining 25 MW. We will retain responsibility for operations of the facility with a life-of-plant site lease, and operations and coal supply agreements in place with MDU.

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 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. 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 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 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 have been no material changes in our Risk Factors from those reported in Item 1A. of Part I of our 2007 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 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 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 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 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 14, 2008

EXHIBIT INDEX

Exhibit Number	Description


Exhibit 31.1	Certification 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 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 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 pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes – Oxley Act of 2002.

Date: November 14, 2008

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

Date: November 14, 2008

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