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, 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 x No o

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

Yes o No o

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

Large accelerated filer o Accelerated filer o

Non-accelerated filer x Smaller reporting company o

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

Yes o No x

As of October 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 AND ABBREVIATIONS	3
PART 1.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Condensed Statements of Income –
	Three and Nine Months Ended September 30, 2009 and 2008	4
	Condensed Balance Sheets –
	September 30, 2009 and December 31, 2008	5
	Condensed Statements of Cash Flows –
	Nine Months Ended September 30, 2009 and 2008	6
	Notes to Condensed Financial Statements	7-16
Item 2.	Results of Operations	17-23
Item 4.	Controls and Procedures	24
PART II.	OTHER INFORMATION
Item 1.	Legal Proceedings	25
Item 1A.	Risk Factors	25-27
Item 6.	Exhibits	28
	Signatures	29
	Exhibit Index	30

2

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
ASC 105	ASC 105, “FASB Accounting Standards Codification and the Hierarchy of
	Generally Accepted Accounting Principles – a replacement of FASB
	Standard No. 162”
ASC 715	ASC 715, “Compensation – Retirement Benefits”
ASC 810-10-15	ASC 810-10-15, “Consolidation of Variable Interest Entities”
ASC 815	ASC 815, “Derivative and Hedging”
ASC 820	ASC 820 “Fair Value Measurements and Disclosures”
ASC 825	ASC 825, “Financial Instruments”
ASC 855	ASC 855, “Subsequent Events”
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, LLC, an indirect subsidiary of the Parent Company
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the
	Parent Company
CO2	Carbon dioxide
Enserco	Enserco Energy, Inc., an indirect subsidiary of the Parent Company
EPA	U.S. Environmental Protection Agency
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 132(R)-1	FSP FAS 132(R)-1, “Employer’s Disclosures about Pensions and Other
	Postretirement Benefits” (Revised)
GAAP	Generally Accepted Accounting Principles
GHG	Greenhouse gas
LIBOR	London Interbank Offered Rate
MEAN	Municipal Energy Agency of Nebraska
MDU	MDU Resources Group, Inc.
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt-hours
PPA	Purchase Power Agreement
SDPUC	South Dakota Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SFAS 157	SFAS 157, “Fair Value Measurements”
SFAS 161	SFAS 161, “Disclosure about Derivative Instruments and Hedging Activities – an
	amendment of FASB Statement No. 133”
SFAS 165	SFAS 165, “Subsequent Events”
SFAS 167	SFAS 167, “Amendment to FASB Interpretation No. 46(R)”
SFAS 168	SFAS 168, “FASB Accounting Standards Codification and the Hierarchy of Generally
	Accepted Accounting Principles – a replacement of FASB Standard No. 162”
Silver Sage	Silver Sage Wind Power, LLC, a subsidiary of Duke Energy Corporation
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., an indirect subsidiary of the Parent
	Company

3

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME

(unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(in thousands)
Operating revenue	$	53,086		$	59,358		$	154,380		$	174,968
Operating expenses:
Fuel and purchased power		24,254			30,119			66,769			85,844
Operations and maintenance		7,460			7,604			23,584			23,615
Administrative and general		6,385			4,538			19,628			14,612
Depreciation and amortization		4,708			5,275			14,761			15,805
Taxes, other than income taxes		1,359			1,594			5,007			5,002
		44,166			49,130			129,749			144,878
Operating income		8,920			10,228			24,631			30,090
Other income (expense):
Interest expense		(2,837	)		(2,751	)		(8,246	)		(7,957	)
Interest income		48			171			211			290
Allowance for funds used
during construction – equity		2,593			1,183			5,270			2,072
Other income, net		17			17			814			185
		(179	)		(1,380	)		(1,951	)		(5,410	)
Income before income taxes		8,741			8,848			22,680			24,680
Income taxes		(1,575	)		(2,477	)		(5,445	)		(7,482	)
Net income	$	7,166		$	6,371		$	17,235		$	17,198

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

4

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)

	September 30,			December 31,
	2009			2008
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,150		$	4
Receivables, net –
Customers		19,025			23,881
Affiliates		2,236			12,619
Other		4,071			2,111
Materials, supplies and fuel		18,836			19,309
Other current assets		9,422			5,730
		54,740			63,654
Investments		4,156			3,999
Property, plant and equipment		919,746			843,691
Less accumulated depreciation		(292,610	)		(281,220	)
		627,136			562,471
Other assets:
Regulatory assets		26,965			33,818
Other		1,546			2,842
		28,511			36,660
	$	714,543		$	666,784
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Current maturities of long-term debt	$	32,023		$	2,016
Accounts payable		24,568			26,567
Accounts payable – affiliates		5,895			10,411
Notes payable – affiliates		104,898			70,184
Accrued liabilities		16,618			15,151
Deferred income taxes		1,043			732
		185,045			125,061
Long-term debt, net of current maturities		117,186			149,193
Deferred credits and other liabilities:
Deferred income taxes		90,088			85,504
Regulatory liabilities		14,791			13,573
Benefit plan liabilities		26,057			29,904
Other		9,214			8,626
		140,150			137,607
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		210,516			193,281
Accumulated other comprehensive loss		(1,345	)		(1,349	)
		272,162			254,923
	$	714,543		$	666,784

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

5

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)

	Nine Months Ended
	September 30,
	2009			2008
	(in thousands)
Operating activities:
Net income	$	17,235		$	17,198
Adjustments to reconcile net income to cash
provided by operating activities:
Depreciation and amortization		14,761			15,805
Provision for valuation allowances		(111	)		172
Deferred income tax		5,304			6,580
Allowance for funds used during construction –
equity		(5,270	)		(2,072	)
Change in operating assets and liabilities –
Accounts receivable and other current assets		13,494			4,088
Accounts payable and other current liabilities		(9,249	)		(1,048	)
Regulatory assets and liabilities		6,517			(3,811	)
Other operating activities		(2,668	)		1,959
		40,013			38,871
Investing activities:
Property, plant and equipment additions		(106,150	)		(97,475	)
Proceeds from sale of ownership interest in plant		32,783			—
Change in money pool notes receivable from
affiliate, net		—			10,304
Other investing activities		1,786			(183	)
		(71,581	)		(87,354	)
Financing activities:
Long-term debt – repayments		(2,000	)		(1,995	)
Change in money pool note payable to
affiliate, net		34,714			49,796
		32,714			47,801
Increase (decrease) in cash and
cash equivalents		1,146			(682	)
Cash and cash equivalents:
Beginning of period		4			2,033
End of period	$	1,150		$	1,351
Supplemental disclosure of cash flow information:
Non-cash investing and financing activities:
Property, plant and equipment acquired
with accrued liabilities	$	19,344		$	15,750
Cash paid during the period for:
Interest (net of amounts capitalized)	$	9,098		$	9,833
Income taxes paid	$	494		$	3,396

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

6

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 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,” “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, 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 our 2008 Annual Report on Form 10-K filed with the SEC.  These financial statements include consideration of events through November 11, 2009.

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, 2009, December 31, 2008 and September 30, 2008 financial information and are of a normal recurring nature.  The results of operations for the three and nine months ended September 30, 2009 and our financial condition as of September 30, 2009 and December 31, 2008 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

(2) RECENTLY ADOPTED ACCOUNTING STANDARDS

FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles – a replacement of FASB Standard No. 162, ASC 105 (SFAS 168)

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

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

Fair Value Measurements and Disclosures, ASC 820 (SFAS 157)

The ASC for Fair Value Measurements and Disclosures defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements.  This does not expand the application of fair value accounting to any new circumstances, but applies the framework to other applicable GAAP that requires or permits fair value measurement.  We apply fair value measurements to certain assets and liabilities, primarily commodity derivatives.  The adoption of this standard did not have a material impact on the Company’s financial position, results of operations or cash flows.

7

Derivative and Hedging, ASC 815 (SFAS 161)

The ASC for Derivative and Hedging Disclosures requires enhanced disclosures about derivative and hedging activities and their affect on an entity’s financial position, financial performance and cash flows.  ASC 815 encourages, but does not require, disclosures for earlier periods presented for comparative purposes at initial adoption.  Required comparative disclosures for periods subsequent to January 1, 2009 are provided in Note 9.

Subsequent Events, ASC 855 (SFAS 165)

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

Financial Instruments, ASC 825 (FSP FAS 107-1)

The ASC for Financial Instruments requires public companies to provide more frequent disclosures about the fair value of their financial instruments for interim and annual periods ending after June 15, 2009.  These disclosures are included in Note 8.

(3) RECENTLY ISSUED ACCOUNTING STANDARDS

Consolidation of Variable Interest Entities, ASC 810-10-15 (SFAS 167)

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

Compensation – Retirement Benefits, ASC 715 (FSP FAS 132(R)-1)

The ASC for Compensation – Retirement Benefits provides guidance on an employer’s disclosures about plan assets in a defined benefit pension or other postretirement plan to provide users of financial statements with an understanding of:

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

· The major categories of plan assets;

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

· The effect of fair value measurements using significant unobservable inputs on changes in plan assets for the period; and

· Significant concentrations of risk within plan assets.

These disclosures are effective for fiscal years ending after December 15, 2009.

8

(4) ALLOWANCE FOR DOUBTFUL ACCOUNTS

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

Following is a summary of receivables (in thousands):

	September 30,			December 31,
	2009			2008
Accounts receivable – customers	$	19,284		$	24,251
Allowance for doubtful accounts		(259	)		(370	)
Net accounts receivable	$	19,025		$	23,881

(5) OTHER COMPREHENSIVE INCOME

The following table presents the components of Other comprehensive income (loss) (in thousands):

	Three Months Ended
	September 30,
	2009			2008
Net income	$	7,166		$	6,371
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges (net of
tax of $15 and $0, respectively)		(27	)		—
Reclassification adjustments included in
net income (net of tax of $(6) and $(6),
respectively)		10			10
Total comprehensive income	$	7,149		$	6,381

	Nine Months Ended
	September 30,
	2009			2008
Net income	$	17,235		$	17,198
Other comprehensive income (loss), net of tax:
Fair value adjustment on derivatives
designated as cash flow hedges (net of
tax of $15 and $(18), respectively		(27	)		30
Reclassification adjustments included
in net income (net of tax of $(17) and $60,
respectively)		31			(109	)
Total comprehensive income	$	17,239		$	17,119

9

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

	September 30,			December 31,
	2009			2008
Derivatives designated as cash flow hedges	$	(928	)	$	(932	)
Employee benefit plans	$	(417	)	$	(417	)
Total	$	(1,345	)	$	(1,349	)

(6) RELATED-PARTY TRANSACTIONS

Receivables and Payables

We have accounts receivable balances related to transactions with other BHC subsidiaries.  The balances were $2.2 million and $12.6 million as of September 30, 2009 and December 31, 2008, respectively.  We also have accounts payable balances related to transactions with other BHC subsidiaries.  The balances were $5.9 million and $10.4 million as of September 30, 2009 and December 31, 2008, respectively.

Money Pool Notes Receivable and Notes Payable

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

Through the Utility Money Pool, we had net note payable balances and interest payable of $105.1 million and $70.2 million as of September 30, 2009 and December 31, 2008, respectively.  Advances under this note bear interest at 0.70 percent above the daily LIBOR rate (which equates to 0.95% at September 30, 2009).  Net interest expense of less than $0.1 million and $1.1 million was recorded for the three months and nine months ended September 30, 2009, respectively.  Net interest expense was approximately $0.4 million and $0.4 million for the three and nine months ended September 30, 2008, respectively.

Other Balances and Transactions

We also received revenues of approximately $0.2 million and $0.3 million for the three months ended September 30, 2009 and 2008, respectively; and $0.7 million and $1.0 million for the nine months ended September 30, 2009 and 2008, respectively, from Black Hills Wyoming for the transmission of electricity.

We received revenues of approximately $0.6 million and $0.4 million for the three months ended September 30, 2009 and 2008, respectively; and $1.3 million and $1.5 million for the nine months ended September 30, 2009 and 2008, respectively, from Cheyenne Light for the sale of electricity and dispatch services.

We recorded revenues of $0.2 million for the nine months ended September 30, 2008 relating to payments received pursuant to a natural gas swap entered into with Enserco, with a third party transacted by Enserco on our behalf.

10

We purchase coal from WRDC.  The amount purchased during the three months ended September 30, 2009 and 2008 was $4.2 million and $4.9 million, respectively; and $11.3 million and $10.8 million for the nine months ended September 30, 2009 and 2008, respectively.

We purchase excess power generated by Cheyenne Light.  The amount purchased during the three months and nine months ended September 30, 2009 was $1.9 million and $5.8 million, respectively and includes $0.3 million and $1.5 million for wind-generated power for the three and nine months ended September 30, 2009, respectively.  The amount purchased for the three and nine month periods ended September 30, 2008 was $1.5 million and $4.6 million, respectively.  On August 28, 2008, we entered into a contract with Cheyenne Light under which Cheyenne Light sells up to 20 MW of wind-generated, renewable energy to us until 2028.

In order to fuel our combustion turbine, we purchase natural gas from Enserco.  The amount purchased during the three months ended September 30, 2009 and 2008 was $0.9 million and $3.0 million, respectively; and $1.5 million and $6.6 million for the nine months ended September 30, 2009 and 2008, respectively.  These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.

In addition, we also pay the Parent for allocated corporate support service cost incurred on our behalf.  Corporate costs allocated from the Parent were $3.8 million and $2.8 million for the three months ended September 30, 2009 and 2008, respectively; and $11.3 million and $8.9 million for the nine months ended September 30, 2009 and 2008, respectively.

We have funds on deposit from Black Hills Wyoming for transmission system reserve in the amount of $2.0 million as of September 30, 2009 and $1.9 million as of December 31, 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 (3.25% at September 30, 2009).

(7) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

We have a noncontributory defined benefit pension plan (the “Plan”) covering the employees who meet certain eligibility requirements.

In July 2009, the Board of Directors approved a resolution, effective January 1, 2010, to freeze our Defined Benefit Pension Plan to new participants and to transfer certain existing participants to an age and service based defined contribution plan.  Plan assets and obligations were revalued July 31, 2009 in conjunction with the curtailment of these plans and we recognized curtailment expense of approximately $0.2 million in the three months ended September 30, 2009.

11

The following table sets forth the projected benefit obligation as of December 31, 2008 and July 31, 2009.  The July 31, 2009 projected benefit obligation reflects the curtailment of the plan:

	Defined Benefit
	Pension Plans
	July 31, 2009
	(in thousands)
Change in benefit obligation:
Projected benefit obligation at
December 31, 2008	$	51,965
Service cost		682
Interest cost		1,831
Actuarial gain		(88	)
Benefits paid		(1,317	)
Benefits curtailed		(1,048	)
Change in discount rate		(335	)
Net increase (decrease)		(275	)
Projected benefit obligation at
July 31, 2009	$	51,690

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,
	2009			2008			2009			2008
Service cost	$	287		$	279		$	871		$	837
Interest cost		786			758			2,357			2,274
Expected return on plan assets		(718	)		(1,094	)		(2,032	)		(3,282	)
Prior service cost		18			28			74			84
Net loss		377			—			1,236			—
Curtailment expense		189			—			189			—
Net periodic benefit cost (gain)	$	939		$	(29	)	$	2,695		$	(87	)

A contribution totaling less than $0.1 million was made to the Plan in the first quarter of 2009.  There are no further contributions expected to be made to the Plan in 2009.

12

Supplemental Nonqualified Defined Benefit Plans

We have various supplemental retirement plans for key executives (the “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,
	2009			2008			2009			2008
Interest cost		$	25		$	30		$	75		$	90
Net loss			11			11			33			33
Net periodic benefit cost		$	36		$	41		$	108		$	123

We anticipate that we will make contributions to the Supplemental Plans for the 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 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 ousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Service cost	$	54	$	52	$	162	$	156
Interest cost		111		104		333		312
Net transition obligation		13		13		39		39
Net periodic benefit cost	$	178	$	169	$	534	$	507

We anticipate that we will make contributions to the Healthcare Plan for the 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 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 was $0.1 million.

13

(8) FAIR VALUE OF FINANCIAL INSTRUMENTS

The estimated fair values of our financial instruments at September 30 are as follows (in thousands):

	2009
	Carrying Amount		Fair Value
Cash and cash equivalents	$	1,150	$	1,150
Derivative financial instruments – liabilities	$	42	$	42
Long-term debt, including current maturities	$	149,209	$	171,273

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

Cash and Cash Equivalents

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

Derivative Financial Instruments

These instruments are carried at fair value.  Pricing is based on quoted prices for identical or similar assets and liabilities in active and inactive markets, inputs other than quoted prices that are observable and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means.

Long-Term Debt

The fair value of our long-term debt is estimated based on quoted market rates for debt instruments having similar maturities and similar debt ratings.

(9) RISK MANAGEMENT ACTIVITIES AND DERIVATIVES

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.  These transactions are marked-to-market, designated as cash flow hedges, and recorded in Accrued liabilities and Accumulated other comprehensive loss on the accompanying Condensed Balance Sheet.  Gains or losses on these transactions will be recorded in gross margins upon settlement.

14

On September 30, 2009, we had the following swaps and related balances (dollars, in thousands):

	Natural Gas Swaps
Notional*		232,500
Maximum terms in months		12
Current derivative asset	$	—
Non-current derivative asset	$	—
Current derivative liability	$	42
Non-current derivative liability	$	—
Pre-tax accumulated other comprehensive
income (loss)	$	(42	)
Unrealized gain/(loss)	$	—

___________________________

* Gas in MMBtus.

Additionally, we engage in activities to manage risk associated with changes in interest rates.  We occasionally enter 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 generally accepted accounting for derivatives, 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 nine months ended September 30, 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.

(10) COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 11 of the Notes to our Financial Statements in 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 months of 2009.

In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations.  We believe the amounts provided in our financial statements are adequate in light of the probable and estimable contingencies.  However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed below, and to comply with applicable laws and regulations, will not exceed the amounts reflected in our financial statements.  As such, costs, if any, that may be incurred in excess of those amounts provided as of September 30, 2009, cannot be reasonably determined and could have a material adverse effect on our results of operations, financial position or cash flows.

15

Extension of Long-Term Power Sales Agreement with MEAN

In March 2009, our 10-year power sales contract between 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 amounts from Wygen III and Neil Simpson II plants are as follows:

2009-2017	20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Partial Sale of Wygen III to MDU

On April 9, 2009, we sold to MDU a 25% ownership interest in our Wygen III generation facility currently under construction.  At closing, MDU made a payment to us for its 25% share of the costs to date on the ongoing construction of the facility.   Proceeds of $32.8 million were received.  MDU will continue to reimburse us for its 25% of the total costs paid to complete the project.  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.  In conjunction with the sales transaction, we also modified our 2004 PPA with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.  The PPA with MDU now provides that once online, the first 25 MW of MDU’s required 74 MW will be supplied from its ownership interest in Wygen III.  During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with its 25 MW from our other generation facilities or system purchases.

(11) SUBSEQUENT EVENT

Bond Issuance

On October 27, 2009, we completed a $180 million first mortgage bond issuance.  The bonds were priced at 99.931% of par and a reoffer yield of 6.13%.  The bonds mature November 1, 2039 and carry an annual interest rate of 6.125%, which will be paid semi-annually.  We received proceeds of $178.3 million net of underwriting fees which were used to repay intercompany borrowings from BHC, primarily incurred to fund the construction of Wygen III.  Estimated deferred finance costs of $1.9 million were capitalized and will be amortized over the life of the bonds.

Renewable Energy Contracts

On October 1, 2009, we entered into a renewable energy sales agreement with Cheyenne Light to purchase renewable energy and associated environmental energy credits produced by Silver Sage.  Silver Sage commenced commercial operations on October 1, 2009.  This agreement allows us to buy 20 MW of the unit-contingent renewable energy purchased by Cheyenne Light from Silver Sage.

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ITEM 2. RESULTS OF OPERATIONS

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
	(in thousands)
Revenue	$	53,086	$	59,358	$	154,380	$	174,968
Fuel and purchased power		24,254		30,119		66,769		85,844
Gross margin		28,832		29,239		87,611		89,124
Operating expenses		19,912		19,011		62,980		59,034
Operating income	$	8,920	$	10,228	$	24,631	$	30,090
Net income	$	7,166	$	6,371	$	17,235	$	17,198

The following tables provide certain operating statistics:

	Electric Revenue
	(in thousands)
	Three Months Ended September 30,									Nine Months Ended September 30,
				Percentage									Percentage
Customer Base	2009			Change			2008			2009			Change			2008
Commercial		$	15,694		(5	)%		$	16,581		$	44,888		2	%		$	43,804
Residential			11,132		(16	)			13,189			35,804		—				35,784
Industrial			4,714		(14	)			5,500			14,494		(11	)			16,338
Municipal sales			778		(3	)			802			2,074		—				2,069
Total retail sales			32,318		(10	)			36,072			97,260		(1	)			97,995
Contract wholesale			6,488		(5	)			6,862			18,672		(7	)			20,063
Wholesale off system			9,625		(27	)			13,213			24,610		(48	)			47,548
Total electric sales			48,431		(14	)			56,147			140,542		(15	)			165,606
Other revenue			4,655		45				3,211			13,838		48				9,362
Total revenue		$	53,086		(11	)%		$	59,358		$	154,380		(12	)%		$	174,968

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	Megawatt Hours Sold
	Three Months Ended September 30,						Nine Months Ended September 30,
			Percentage						Percentage
Customer Base	2009		Change		2008		2009		Change		2008
Commercial		207,939		6%		195,661		553,150		4%		531,433
Residential		113,266		(6)		120,888		395,865		(1)		398,028
Industrial		80,222		(25)		107,380		260,190		(18)		319,077
Municipal sales		9,894		(3)		10,228		25,556		(2)		26,073
Total retail sales		411,321		(5)		434,157		1,234,761		(3)		1,274,611
Contract wholesale		161,796		(2)		165,872		473,723		(4)		494,457
Wholesale off system		309,770		28		241,546		784,173		4		753,057
Total electric sales		882,887		5		841,575		2,492,657		(1)		2,522,125
Losses and company
use		30,764		22		25,313		98,057		72		56,911
Total energy		913,651		5%		866,888		2,590,714		—		2,579,036

	Electric Utility Power Plant Availability
	Three Months Ended September 30,				Nine Months Ended September 30,
	2009		2008		2009		2008
Coal-fired plants		97.7%		95.8%**		90.5%*		91.8%**
Other plants		99.6%		98.7%		97.1%		90.6%
Total availability		98.5%		97.1%		93.4%		91.3%

___________________________

  * Reflects major outages at Neil Simpson I and Neil Simpson II coal-fired plants.  The Neil Simpson I outage was scheduled for 31 days and was subsequently extended to 39 days.  The Neil Simpson II outage was scheduled for 18 days and was subsequently extended to 27 days.  The outages were extended on both units for major rotor damage discovered during the overhauls.

** 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.  All the plants were online by the end of the second quarter of 2008.

	Megawatt Hours Generated and Purchased
	Three Months Ended September 30,							Nine Months Ended September 30,
			Percentage							Percentage
Resources	2009		Change			2008		2009		Change			2008
Coal		465,068		3	%		450,884		1,251,276		(1	)%		1,268,514
Gas		28,251		138			11,856		35,076		(35	)		53,687
		493,319		7			462,740		1,286,352		(3	)		1,322,201
MWhs purchased		420,332		4			404,148		1,304,362		4			1,256,835
Total resources		913,651		5	%		866,888		2,590,714		—			2,579,036

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	Heating and Cooling Degree Days
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Heating and cooling degree days:
Actual
Heating degree days		178		223		4,705		4,814
Cooling degree days		303		453		354		482
Variance from normal
Heating degree days		(22)%		(2)%		4%		6%
Cooling degree days		(39)%		(8)%		(41)%		(19)%

Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008.  Net income increased $0.8 million from the prior period primarily due to the following:

· Increased other margins of $1.5 million primarily due to an increase in transmission rates effective January 1, 2009;

· A $0.3 million increase in retail margins primarily due to lower purchase power and fuel costs partially offset by lower MWh sold due to lower industrial sales; and

· Increased AFUDC of $1.5 million primarily due to construction of Wygen III in 2009.

Partially offsetting the increases were the following:

· A $2.2 million decrease in margins from off-system sales reflecting the lower margins available in the current low energy price environment; and

· A $0.7 million increase in employee benefit costs.

Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008.  Net income was comparable to the prior period primarily due to the following:

· A $6.0 million decrease in margins from off-system sales reflecting the lower margins available in the current low energy price environment; and

· A $2.8 million increase in employee benefit costs.

Partially offsetting the decreases were the following:

· Increased gross margins of $4.5 million primarily due to an increase in transmission rates effective January 1, 2009; and

· Increased AFUDC of $4.0 million primarily due to construction of Wygen III in 2009.

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Wygen III Power Plant Project and Partial Sale of Wygen III to MDU

In March 2008, we received final regulatory approval for construction of Wygen III.  Construction began immediately and the 110 MW coal-fired base load electric generating facility is expected to be completed by June, 2010.  The expected cost of construction is approximately $255 million, which includes estimates for AFUDC.  Our 2004 PPA with MDU included an option for MDU to purchase an ownership interest in Wygen III.  MDU exercised this option, and under an agreement entered into in April 2009, we will retain an undivided ownership of 75% of the facility with MDU owning the remaining 25%.  At closing, MDU reimbursed us for its 25%, or $32.8 million, of the total costs incurred to date on the ongoing construction of the facility.  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.  In conjunction with the sales transaction, we also modified our 2004 PPA with MDU under which we supplied MDU with 74 MW of capacity and energy through 2016.  The PPA with MDU now provides that once online, the first 25 MW of MDU’s required 74 MW will be supplied from its ownership interest in Wygen III.  During periods of reduced production at Wygen III, or during periods when Wygen III is offline, we will provide MDU with such 25 MW from our other generation facilities or system purchases.

Extension of Long-Term Power Sales Agreement with MEAN

In March 2009, our 10-year power sales contract between 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 amounts from Wygen III and Neil Simpson II plants are as follows:

2009-2017	20 MW – 10 MW contingent on Wygen III and 10 MW contingent on Neil Simpson II
2018-2019	15 MW – 10 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II
2020-2021	12 MW – 6 MW contingent on Wygen III and 6 MW contingent on Neil Simpson II
2022-2023	10 MW – 5 MW contingent on Wygen III and 5 MW contingent on Neil Simpson II

Purchase Power Agreement with MEAN

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

Rate Case Filed with the SDPUC

On September 30, 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets and increased operating expenses incurred during the past four years.  We are seeking a 26.6%, increase in annual utility revenues and we anticipate that the new rates will be effective for our South Dakota customers on or around April 1, 2010.  The proposed rate increase is subject to approval by the SDPUC.

20

Rate Case Filed with the WPSC

On October 19, 2009, we filed a rate case with the WPSC requesting an electric revenue increase to recover costs associated with Wygen III and other generation, transmission and distribution assets, and increased operating expenses incurred since 1995.  We are seeking a 38.95%, increase in annual utility revenues and we anticipate that the new rates will be effective for our Wyoming customers on or around April 1, 2010, although recovery could be delayed until August 2010 as part of the regulatory process.  The proposed rate increase is subject to approval by the WPSC.

Financing Transactions and Short-Term Liquidity

Financing Plans

In October 2009, we completed the issuance of a long-term first mortgage bond of approximately $180 million.  Proceeds of the transaction will be used to fund capital expenditures, including construction costs related to the Wygen III facility, and to fund the approximate $30 million maturity of our Series AC, 8.06% first mortgage bonds due in February 2010.

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements.  As of September 30, 2009, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:

Rating Agency	Rating	Outlook
Moody’s	A3	Stable
S&P	BBB	Stable
Fitch	A-	Stable

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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.  Forward-looking statements involve risks and uncertainties, and certain important factors can cause actual results to differ materially from those anticipated.  In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “projects,” “predicts,” “potentials,” or “continue” or the negative of these terms or other similar terminology.  There are various factors that could cause actual results to differ materially from those suggested by the forward-looking statements; accordingly, there can be no assurances that such indicated results will be realized.  The forward-looking statements include the factors discussed above, the risk factors described in Item 1A of our 2008 Annual Report on Form 10-K, 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 access the bank loan and debt capital markets depends on market conditions beyond our control.  If the credit markets remain tight and do not improve, we may not be able to permanently refinance some short-term debt and fund our power generation projects on reasonable terms, if at all;

· Our ability to raise capital in the debt capital markets depends upon our financial condition and credit ratings, among other things.  If our financial condition deteriorates unexpectedly, or our credit ratings are lowered, we may not be able to refinance some short-term debt and fund our power generation projects on reasonable terms, if at all;

· 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;

22

· 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;

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

· 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;

· 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.

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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, 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, 2009 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

24

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 our 2008 Annual Report on Form 10-K and Note 8 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 8 is incorporated by reference into this item.

Item 1A.                      Risk Factors

Except to the extent updated or described below, our Risk Factors are documented in Item IA. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2008.

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

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

On April 2, 2007, the U.S. Supreme Court issued a decision in the case of Massachusetts v. U.S. Environmental Protection Agency, holding that CO2 and other GHG emissions are pollutants subject to regulation under the motor vehicle provisions of the Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or alternatively, to explain why GHG emissions should not be regulated.  On April 17, 2008, the EPA issued its proposed endangerment finding under Section 202 of the Clean Air Act. Although this proposal does not specifically address stationary sources, such as power generation plants, the general endangerment finding relative to GHG’s could support such a proposal by the EPA for stationary sources. On March 10, 2009, the EPA released proposed rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions.  Finally, federal legislation is currently under consideration in the U.S. Congress, including H.R. 2454, “the American Clean Energy and Security Act of 2009”, which was approved by the U.S. House of Representatives on June 26, 2009. This legislation would affect electric generation and electric and natural gas distribution companies. H.R. 2454 would establish mandatory GHG reduction targets, utilizing a Federal emissions cap-and-trade program. H.R.2454 also proposes a national renewable electricity standard, which would implement a phased process ultimately mandating that 20% of electricity sold by retail suppliers be met by energy efficiency improvements and renewable energy resources by 2020. The Senate is expected to consider its own version of the legislation later in 2009 or in 2010.

25

In addition, the EPA published in the October 27, 2009 Federal Register a proposed rule that would tailor the major source applicability thresholds for GHG emissions under the Prevention of Significant Deterioration (PSD) and Title V programs of the Clean Air Act and set a PSD significance level for GHG emissions.  EPA states this rule is necessary because they expect to soon promulgate regulations under the Clean Air Act to control GHG emissions and as a result, trigger PSD and Title V applicability requirements.  This proposed rule would phase in the applicability thresholds for both the PSD and Title V programs for sources of GHG emissions.  The first phase, which would last 6 years, would establish a temporary level for the PSD and Title V applicability thresholds at 25,000 tons per year on a carbon dioxide equivalent basis and would also establish temporary PSD significance levels.  All our generating units would exceed this threshold and if the pending rule to control GHG emissions is published and finalized, we would be required upon Title V permit renewal, to evaluate options for reducing GHG emissions, to possibly include a Best Available Control Technology review that could result in more stringent emissions control practices and technologies.  In the second phase of this proposed rule, EPA would within 5 years of the rule being final, review the first phase and promulgate revised applicability and significance level thresholds as appropriate.

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

More stringent GHG emissions limitations or other energy efficiency requirements, however, could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base, we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by our non-regulated power plants. Any unrecovered costs could have a material impact on our results of operations and financial condition. In addition, future changes in environmental regulations governing air emissions could render some of our power generating units more expensive or uneconomical to operate and maintain.

26

We own electric utilities that serve customers in Montana, South Dakota and Wyoming. Montana has adopted mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If this state increases its 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. Although we will seek to recover these higher costs in rates, any unrecovered costs could have a material negative impact on our results of operations and financial condition.

27

Item 6. Exhibits

Exhibit 4	Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon, as Trustee to Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (previously filed as Exhibit 4.21 to the Company’s Post-Effective Amendment No. 2 to the Registration Statement on Form S-3 (File No. 333-150669) and incorporated by reference herein).
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.

28

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 12, 2009

29

EXHIBIT INDEX

Exhibit Number	Description
Exhibit 4	Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon, as Trustee to Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (previously filed as Exhibit 4.21 to the Company’s Post-Effective Amendment No. 2 to the Registration Statement on Form S-3 (File No. 333-150669) and incorporated by reference herein).
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.

30