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 ~~June~~September 30, 2010.
OR
o	TRANSITION ~~REPORT~~REPOR T PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT ~~O F~~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 ~~July 31,~~October 29, 2010, 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 ~~Re gistrant~~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~~TABLE OF CONTENTS
		Page
	GLOSSARY OF TERMS AND ABBREVIATIONS	3

~~GLOSSARY OF TERMS AND ABBREVIATIONS~~		3
PART 1.	FINANCIAL INFORMATION
~~Item 1. Financial Statements~~
~~Condensed Statements of Income - unaudited~~		4
~~Three and Six Months Ended June 30, 2010 and 2009~~

~~Condensed Balance Sheets - unaudited~~Item 1.		5
~~June 30, 2010 and December 31, 2009~~	Financial Statements

~~Cash Flow~~	Condensed Statements of Income - unaudited		64
~~Six~~	Three and Nine Months Ended ~~June~~September 30, 2010 and 2009

	Condensed Balance Sheets - unaudited	5
	September 30, 2010 and December 31, 2009

	Cash Flow Statements - unaudited	6
	Nine Months Ended September 30, 2010 and 2009

	Notes to Condensed Financial Statements - unaudited		7

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		1622

Item 4.	Controls and Procedures		2431
	&nb sp;
PART II.	OTHER INFORMATION		2532

Item 1.	Legal Proceedings	32
	25
Item 1A.	Risk Factors		2633

Item 6.
Exhibits		2734

~~Signatures~~	Signatures	2835

~~Exhibits~~	Exhibit Index		2936

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	Accounting Standards Codification
ASC 310-10-50	ASC 310-10-50, "Receivables"
ASC 810-10-15	ASC 810-10-15, "Consolidation of Variable Interest Entities"
ASC 820	ASC 820, "Fair Value Measurements"
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
Dodd-Frank	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE	Department of Energy
Enserco	Enserco Energy, Inc., an indirect subsidiary of the Parent Company
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GHG	Greenhouse Gases
IRS	Internal Revenue Service
LIBOR	London Interbank Offered Rate
JPB	Consolidated Wyoming Municipalities Electric Power System Joint Power Board
MDU	MDU Resources Group, Inc.
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt-hours
NOx	Nitrogen Oxide
Participation Agreement	Amendment and Restated Wygen III Participation Agreement dated July 14, 2010 between the Company, MDU and JPB, which includes JPB as partial owner of Wygen ~~I II~~III
PPA	Purchase Power Agreement
PPACA	Patient Protection and Affordability Care Act
SDPUC	South Dakota Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
SOx	Sulfur Dioxide
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., an indirect subsidiary of the Parent Company

																												BLACK HILLS POWER, INC.	CONDENSED STATEMENTS OF INCOME	(unaudited)

	Three Months Ended June 30,							Six Months Ended June 30,						Three Months Ended September 30,							Nine Months Ended September 30,
	2010				2009			2010			2009			2010			2009				2010				2009
	(in thousands)													(in thousands)

Operating revenue	$	56,438			$	46,836		$	110,927		$	101,294		$	59,051		$	53,086			$	169,978			$	154,380

Operating expenses:
Fuel and purcha sed power	21,616				19,753			45,852			42,515
Fuel and purchased power														20,944			24,254				66,796				66,769
Operations and maintenance	9,390				8,486			17,416			16,124			8,522			7,460				25 ,938				23,584
Gain on sale of operating assets														(6,238		)	—				(6,238		)		—
Administrative and general	7,441				6,972			13,633			13,243			6,883			6,385				20,516				19,628
Depreciation and amortization	5,684			&n bsp;	5,006			10,418			10,052			6,043			4,708				16,461				14,761
Taxes, other than income taxes	1,797				1,613			3,737			3,649			1,805			1,359				5,542				5,007
Total operating expenses	45,928				41,830			91,056			85,583			37,959			44,166				129,015				129,749

Operating income	10,510				5,006			19,871			15,711			21,092			8,920				40,963			&nb sp;	24,631

Other income (expense):
Interest expense	(5,616		)		(2,838		)	(9,482		)	(5,410		)	(4,212		)	(2,837		)		(13,694		)		(8,246		)
Interest income	1,029				65			1,424			164			68			48			1,492				211
AFUDC - equit y	230				1,276			2,237			2,677
AFUDC - equity														266			2,593				2,503				5,270
Other income, net	18				508			138			797			22			17				160				814
Total other income (expense)	(4,339		)		(989		)	(5,683		)	(1,772		)	(3,856		)	(179		)		(9,539		)		(1,951		)

Income before income taxes	6,171				4,017			14,188			13,939			17,236			8,741				31,424				22,680
Income tax expense	(2,069		)		(912		)	(4,152		)	(3,870		)	(3,158		)	(1,575		)		(7,310		)		(5,445		)
Net income	$	4,102		&n bsp;	$	3,105		$	10,036		$	10,069		$	14,078		$	7,166			$	24,114			$	17,235

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

														BLACK HILLS POWER, INC.	CONDENSED BALANCE SHEETS	(unaudited)
	June 30, 2010			December 31, 2009			September 30, 2010				December 31, 2009
	(in thousands)						(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	2,503		$	1,709		$	2,641			$	1,709
Receivables - customers, net	19,000			19,991			20,661				19,991
Receivables - affilia tes, net	4,929			4,146
Receivables - affiliates, net							11,491				4,146
Other receivables, net	2,428			5,293			3,147				5,293
Money pool notes receivable	—			57,737			57,143				57,737
Materials, supplies and fuel	19,422			18,825			20,620				18,825
Regulatory assets, current	6,438			7,467			8,805				7,467
Other current assets	2,884			1,639		6,653				1,639
Total current assets	57,604			116,807			131,161				116,807

Investments	4,337			4,197			4,354				4,197

Property, plant and equipm ent	984,695			950,577
Property, plant and equipment							951,127				950,577
Less accumulated depreciation and amortization	(298,811		)	(293,823		)	(304,879		)		(293,823		)
Total property, plant and equipment, net	685,884			656,754			646,248				656,754

Other assets:
Regulatory assets - non-current	32,227			31,305			32,153				31,305
Other, non-current assets	4,403			3,730			3,688				3,730
Total other assets	36,630			35,035			35,841				35,035
TOTAL ASSETS	$	784,455		$	812,793		$	817,604			$	812,793

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt	$	75		$	32,025		$	84			$	32,025
Accounts payable	14,248			24,175			14,808				24,175
Accounts payable - affiliates	6,984			10,030			34,569				10,030
Notes Payable - affiliates	13,028			—
Accrued liabilities	16,624			17,892			18,213				17,892
Regulatory liabilities, current	3,138			1,238			852				1,238
Deferred income tax liabilities - current	1,781			1,853			1,131				1,853
Total current liabilities	55,878			87,213			69,657			87,213

Long-term debt, net of current maturities	276,462			297,044			276,442				297,044

Deferred credits and other liabilities:
Deferred income tax liability - non-current	107,058			96,207			108,860				96,207
Regulatory liabilities, non-current	16,783			14,955			27,634				14,955
Benefit plan liabilities	30,093			28,224			22,249				28,224
Other, deferred credits and other liabilities	9,720			10,952			10,185				10,952
Total deferred credits and other liabilities	163,654			150,338			168,928				150,338

Stockholder's equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416			23,416			23,416				23,416
Additional paid-in capital	39,575			39,575			39,575				39,575
Retained earnings	226,456			216,420			240,534				216,420
Accumulated other comprehensive loss	(986		)	(1,213		)	(948		)		(1,213		)
Total stockholder's equity	288,461			278,198			302,577				278,198
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	784,455		$	812,793
TOTA L LIABILITIES AND STOCKHOLDER'S EQUITY							$	817,604			$	812,793

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


BLACK HILLS POWER, INC.	BLACK HILLS POWER, INC.						BLACK HILLS POWER, INC.
CONDENSED STATEMENTS OF CASH FLOWS	CONDENSED STATEMENTS OF CASH FLOWS						CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)	(unaudited)						(unaudited)
	Six Months Ended June 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(in thousands)						(in thousands)
Operating activities:										&n bsp;
Net income	$	10,036		$	10,069		$	24,114		$	17,235
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization	10,418			10,052			16,461			14,761
Deferred income tax	11,029			3,634			20,467			5,304
Employee benefits	2,043			2,180			3,060			3,337
Gain on sale of operating assets							(6,238		)	—
AFUDC - equity	(2,237		)	(2,677		)	(2,503		)	(5,270		)
Other non-cash adjustments	159			175			5,615			142
Change in operating assets and liabilities -
Accounts receivable and other current assets	(1,953		)	10,255			(14,663		)	13,494
Accounts payable and other current liabilities	(10,495		)	11,011			20,143			(9,249		)
Regulatory assets	(441		)	6			2,665			6,733
Regulatory liabilities	—			(142		)	1,245			(216		)
Contributions to employee benefit plans							(8,800		)	—
Other operating activities	2,027			1,305			(8,818		)	(6,258		)
Net cash provided by operating activities	20,586			45,868			52,748			40,013

Investing activities:
Property, plant and equipment additions	(40,241		)	(76,911		)	(62,935		)	(106,150		)
Proceeds from sale of ownership interest in plant	—			32,321			62,000			32,783
Change in money pool note receivable from affiliate, net	57,737			—			594			—
Other investing activities	3,392			(4,314		)	2,244			1,786
Net cash provided by (used in) investing activities	20,888			(48,904		)	1,903			(71,581		)

Financing activities:
Long-term debt - repayments	(52,532		)	(1,984		)	(52,543		)	(2,000		)
Change in money pool note payable to affiliates, net	13,028			5,642			—			34,714
Other financing activities	(1,176		)	—			(1,176		)	—
Net cash (used in) provided by financing activities	(40,680		)	3,658			(53,719		)	32,714

Increase in cash and cash equivalents	794			622			932			1,146

Cash and cash equivalents:
Beginning of period	1,709			4			1,709			4
End of period	$	2,503	;	$	626		$	2,641		$	1,150

See Note 11 for supplemental cash flow information	See Note 11 for supplemental cash flow information						See Note 11 for supplemental cash flow information

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

& nbsp;

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

~~( unaudited)~~(unaudited)

(Reference is made to Notes to Financial Statements

included in our 2009 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," or "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 2009 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 ~~June~~September 30, 2010, December 31, 2009 and ~~June~~September 30, 2009 financial information and are of a normal recurring nature. The results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2010 and our financial condition as of ~~June~~September 30, 2010 and December 31, 2009 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Certain prior year data presented in the financial statements has been reclassified to conform to the current year presentation. These reclassifications had no effect on total assets, net income, cash flows or earnings per share.

(2) RECENTLY ADOPTED AND RECENTLY ISSUED ACCOUNTING STANDARDS AND LEGISLATION

Recently Adopted Accounting Standards

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

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 also requires 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 with ongoing re-evaluation. The adoption of this standard had no impact on our financial statements.

Fair Value ~~Measu rements,~~Measurements, ASC 820

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

Recently Issued Accounting Standards and Legislation

Patient Protection and Affordable Care Act (HR 3590)

OnIn March ~~23,~~ 2010, the President of the United States signed into law ~~comprehensive~~comprehensi ve healthcare reform legislation under the ~~Patient Protection and Affordable Care Act,~~PPACA as amended by the Healthcare and Education Reconciliation Act. The potential impact on the Company, if any, cannot be determined until regulations are promulgated under the PPACA. Included among the provisions of the ~~law~~PPACA is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which ~~would affect~~affects our Non-Pension Postretirement Benefit Plan. Internal Revenue Code Section 139A has been amended to eliminate the deduction of the subsidy in reducing income for years beginning after December 31, 2012. The ~~application~~impact of this change in the tax treatment of the subsidy had an immaterial effect on our financial position, results of operations and cash flows. The Company will continue to assess the accounting implications of the PPACA as related regulations and interpretations become available.

Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173)

In July 2010, the President of the United States signed into law comprehensive financial reform legislation ~~resulted~~under Dodd-Frank. Title VII of Dodd-Frank effectively regulates many derivative transactions in the United States that were previously unregulated, including swap transactions in the over-the-counter market. Among other things, Dodd-Frank (i) mandates the clearing of some swaps through regulated central clearing organizations and the trading of clearing swaps through regulated exchanges or swap execution facilities, in each case subject to certain key exemptions, and (ii) authorizes regulators to establish collateral and margin requirements fo r certain swap transactions that are not cleared. Dodd-Frank provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions. Significant rule-making by numerous governmental agencies, particularly the CFTC with respect to non-security commodities, will be required over the next several months to implement the restrictions, limitations, and requirements contemplated by Dodd-Frank, and we will continue to evaluate the impact as these rules become available.

Disclosures About the Credit Quality of Financing Receivables and the Allowance for Credit Losse s (ASC 310-10-50)

In July 2010, the FASB issued an ~~adjustment~~amendment to ~~Regulatory as sets~~ASC 310-10-50, Receivables - Disclosures. The guidance requires additional disclosures that will facilitate financial statement user's evaluation of the nature of credit risk inherent in financing receivables, how that risk is analyzed in arriving at the allowance for credit losses, and ~~is not expected to~~the reason for any changes in the allowance for credit losses. These disclosures should be provided on a disaggregated basis but exempts trade receivables that have a ~~significant~~contractual maturity of one year or less, receivables measured at lower of cost or fair value, and receivables measured at fair value with the changes in fair value reported in earnings. The adoption of this amendment should have no impact on our financial position, results of operations or cash flows.

It is effective for interim and annual reporting periods ending on or after December 15, 2010.

(3) ACCOUNTS RECEIVABLE

We maintain an allowance for doubtful accounts which reflects our best estimate of potentially uncollectible trade receivables. We regularly review our trade ~~receivables allowances~~receivable allowance 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 accounts receivable balances (in thousands):


	June 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009

Accounts receivable trade	$	14,003		$	14,703		$	14,544		$	14,703
Unbilled revenues	5,220			5,547			6,315			5,547
Total accounts receivable - customers	19,223			20,250			20,859			20,250
Allowance for doubtful accounts	(223		)	(259		)	(198		)	(259		)
Receivables - customers, net	$	19,000		$	19,991		$	20,661		$	19,991

(4) REGULATORY ACCOUNTING

We had the following regulatory assets and liabilities (in thousands):


	Recovery Period	June 30, 2010		December 31, 2009		Recovery Period	September 30, 2010		December 31, 2009

Regulatory assets:
Unamortized loss on reacquired debt	14 years	$	3,141	$	2,207	14 years	$	3,079	$	2,207
AFUDC	Up to 45 years	7,106		7,579		Up to 45 years	7,106		7,579
Defined benefit postretirement plans	Up to 17 years	21,024		21,024		Up to 17 years	21,024		21,024
Deferred energy costs	Less than one year	6,438		7,467		Less than one year	5,817		7,467
Other		956		495			3,932		495
Total regulatory assets		$	38,665	$	38,772		$	40,958	$	38,772

Regulatory liabilities:
Cost of removal for utility plant	Up to 53 years	$	14,663	$	13,678	Up to 53 years	$	14,836	$	13,678
Defined benefit postretirement plan						Up to 17 years	11,320		11
Other		5,258		2,515			2,330		2,504
Total regulatory liabilities		$	19,921	$	16,193		$	28,486	$	16,193

Regulatory assets are primarily recorded for the probable future revenue to recover the costs associated with defined benefit postretirement plans, future income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt. To the extent that energy costs are under-recovered or over-recovered during the year, they are recorded as a regulatory asset or liability, respectively. Regulatory liabilities include the probable future decrease in rate revenues related to a decrease in deferred tax liabilities for prior reductions in statutory federal income tax rates, gains associated with regulated utilities' defined benefit postretirement plans and the cost of removal for utility plant, recovered through our electric utility rates. Regulatory assets are included in Regulatory assets, current and Regulatory assets, non-current on the accompanying Condensed Balance Sheet. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Condensed Balance Sheet.

(5) OTHER COMPREHENSIVE INCOME

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


	Three Months Ended June 30,
	2010			2009		Three Months Ended September 30, 2010
Net income	$	4,102		$	3,105			$	14,078
Other comprehensive income, net of tax:
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $4)	(6		)	—
Reclassification adjustments included in net income (net of tax of $(6) and $(6), respectively)	10			11
Fair value adjustment on derivatives designated as cash flow hedges						43
Taxes						(15	)
Fair value adjustment on derivatives designated as cash flow hedges, net of tax								28

Reclassification adjustments included in net income						16
Taxes						(6	)
Reclassification adjustments included in net income, net of tax								10

Comprehensive income	$	4,10 6		$	3,116			$	14,116

910


	Six Months Ended June 30,
	2010		2009		Nine Months Ended September 30, 2010
Net income	$	10,036	$	10,069			$	24,114
Other comprehensive income, net of tax:
Fair value adjustment on derivatives designated as cash flow hedges (net of tax of $(115))	206		—
Reclassification adjustments included in net income (net of tax of $(11) and $(11), respectively)	21		21
Fair value adjustment on derivatives designated as cash flow hedges					360
Tax					(125	)
Fair value adjustment on derivatives designated as cash flow hedges, net of tax							235

Reclassification adjustments included in net income					48
Tax					(18	)
Reclassification adjustments included in net income, net of tax							30

Comprehensive income	$	10,263	$	10,090			$	24,379


	Three Months Ended September 30, 2009
Net income			$	7,166
Other comprehensive income, net of tax:
Fair value adjustment on derivatives designated as cash flow hedges	(42	)
Taxes	15
Fair value adjustment on derivatives designated as cash flow hedges, net of tax			(27		)

Reclassification adjustments included in net income	16
Taxes	(6	)
Reclassification adjustments included in net income, net of tax			10

Comprehensive income			$	7,149


	Nine Months Ended September 30, 2009
Net income			$	17,235
Other comprehensive income, net of tax:
Fair value adjustment on derivatives designated as cash flow hedges	( 42	)
Tax	15
Fair value adjustment on derivatives designated as cash flow hedges, net of tax			(27		)

Reclassification adjustments included in net income	48
Tax	(17	)
Reclassification adjustments included in net income, net of tax			31

Comprehensive income			$	17,239

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


	June 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009
Derivatives designated as cash flow hedges	$	(666	)	$	(893	)	$	(628	)	$	(893	)
Employee benefit plans	(320		)	(320		)	(320		)	(320		)
Total Accumulated other comprehensive loss	$	(986	)	$	(1,213	)	$	(948	)	$	(1,213	)

&n bsp;

(6) RELATED-PARTY TRANSACTIONS

Receivables and Payables

We have accounts receivable and payable balances related to ~~transactions~~t ransactions with other BHC subsidiaries. The balances were ~~$4.9 million~~ ~~and~~ ~~$4.1 million~~as of ~~June 30, 2010~~ ~~and~~ ~~December 31, 2009, respectively. We also have accounts payable balances related to transactions with other BHC subsidiaries. The balances were~~ ~~$7.0 million~~ ~~and~~ ~~$10.0 million~~ ~~as of~~ ~~June 30, 2010~~ ~~and~~ ~~December 31, 2009, respectively.~~follows (in thousands):


	September 30, 2010		December 31, 2009

Accounts receivable with related parties	$	11,491	$	4,146
Accounts payable with related parties	$	34,569	$	10,030

~~Money~~Mo ney Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the "Agreement") with BHC, Cheyenne Light and Black Hills Energy. Under the Agreement, we may borrow from our Parent. The Agreement restricts us from loaning funds to our Parent or to any of our Parent's non-utility subsidiaries; the Agreement does not restrict us from making dividends to our 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~~We had the following balances with the Utility Money Pool ~~we had a net notes payable balance of~~ (in thousands):


	September 30, 2010		December 31, 2009

Notes receivable with Utility Money Pool, net	$	57,143	$	57,737

~~$13.1 million~~ on ~~June 30, 2010~~ ~~and a net notes receivable balance of~~ ~~$57.7 million~~ ~~as of~~ ~~December 31, 2009~~. Advances under these notes bear interest at 2.75% above the daily LIBOR rate (which equates to ~~0.35%~~3.01% at ~~June~~September 30, 2010). Net interest income ~~of less than $0.1 million and~~ ~~$0.1 million~~ ~~was recorded~~relating to balances for the ~~three and six months ended~~ ~~June 30, 2010, respectively. Net interest expense~~Utility Money Pool was ~~$0.7 million~~ ~~and~~ ~~$1.1 million~~ ~~for the three and six months ended~~ ~~June 30, 2009, respectively.~~as follows (in thousands):


	Three Mont hs Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010			2009
Net interest expense (income)	$	(121	)	$	42	$	(171	)	$	1,126

1013

Other Balances and Transactions

We ~~also received revenues of approximately~~ ~~$0.8 million~~transact various activities with related parties. The sales and ~~$0.2 million~~ ~~for the three months ended~~ ~~June 30, 2010~~ ~~and 2009, respectively, and~~ ~~$0.9 million~~ ~~and~~ ~~$0.4 million~~ ~~for the six months ended~~ ~~June 30, 2010~~ ~~and 2009, respectively from Black Hills Wyoming for the transmission of electricity.~~purchases with related parties were as follows (in thousands):

~~We received revenues of approximately~~ ~~$0.3 million~~ ~~and~~ ~~$0.4 million~~ ~~for the three months ended~~ ~~June 30, 2010~~ ~~and 2009, respectively, and~~ ~~$0.9 million~~ ~~and~~ ~~$0.7 million~~ ~~for the six months ended~~ ~~June 30, 2010~~ ~~and~~ ~~June 30, 2009~~ ~~from Cheyenne Light for the sale of electricity and dispatch services.~~

~~We purchase coal from WRDC. The amount purchased during the three months ended~~ ~~June 30, 2010~~ ~~and 2009 was~~ ~~$3.9 million~~ ~~and~~ ~~$3.2 million, respectively; and~~ ~~$8.0 million~~ ~~and~~ ~~$7.1 million~~ ~~for the six months ended~~ ~~June 30, 2010~~ ~~and~~ ~~June 30, 2009, respectively.~~

~~We purchase excess power generated by Cheyenne Light. The amount purchased during the three and six months ended~~ ~~June 30, 2010~~ ~~was~~ ~~$2.1 million~~ ~~and~~ ~~$4.7 million~~ ~~and includes~~ ~~$1.3 million~~ ~~and~~ ~~$2.5 million~~ ~~for wind-generated power, respectively. The amount purchased for the three and six month periods ended~~ ~~June 30, 2009~~ ~~was~~ ~~$2.0 million~~ ~~and~~ ~~$3.9 million~~ ~~and includes~~ ~~$0.5 million~~ ~~and~~ ~~$1.3 million~~ ~~of wind-generated power, respectively.~~

~~In order to fuel our combustion turbine, we purchase natural gas from Enserco. The amount purchased during the three months ended~~ ~~June 30, 2010~~ ~~and 2009 was~~ ~~$0.2 million~~ ~~and~~ ~~$0.5 million, respectively; and~~ ~~$0.7 million~~ ~~and~~ ~~$0.6 million~~ ~~for the six months ended~~ ~~June 30, 2010~~ ~~and 2009. These amounts are included in Fuel and purchased power on the accompanying Condensed Statements of Income.~~

~~In addition, we also pay our Parent for allocated corporate support service cost incurred on our behalf. Corporate costs allocated from our Parent were~~ ~~$4.2 million~~ ~~and~~ ~~$3.8 million~~ ~~for the three months ended~~ ~~June 30, 2010~~ ~~and 2009, respectively; and~~ ~~$8.2 million~~ ~~and~~ ~~$7.4 million~~ ~~for the six months ended~~ ~~June 30, 2010~~ ~~and 2009, respectively.~~


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Revenues:
Transmission of electricity sold to Black Hills Wyoming	$	216	$	223	$	1,158	$	653
Electricity and dispatch services sold to Cheyenne Light	$	171	$	598	$	1,045	$	1,286

Expenses:
Coal purchases from WRDC	$	4,033	$	4,183	$	13,569	$	11,254
Excess power generated at Cheyenne Light	$	2,545	$	1,864	$	7,255	$	5,810
Natural gas from Enserco	$	611	$	934	$	1,333	$	1,512
Corporate support services from Parent	$	3,101	$	3,840	$	11,317	$	11,274

We have funds on deposit from Black Hills Wyoming for transmission system reserve ~~in the amount of~~ ~~$2.0 million~~ ~~as of~~ ~~June 30, 2010~~ ~~and~~ ~~$2.0 million~~ ~~as of December 31, 2009, respectively,~~ which isare included in Other, ~~Deferr ed~~Deferred credits and other liabilities on the accompanying Condensed Balance Sheets. Interest on the funds accrues quarterly at an average quarterly prime rate ~~(3.10%~~(3.25% at ~~June~~Septe mber 30, 2010) ~~and was less than $0.1 million for the three and six months ended~~ . We have transmission system reserve balances as follows (in thousands)~~June 30, 2010~~ ~~and 2009, respectively.~~



	September 30, 2010		December 31, 2009

Deferred credits and other liabilities	2,027		$	1,978


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009

Interest expense	$	16	$	16	$	48	$	53

1114

(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.

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


													Three Months Ended						Nine Months Ended
	Three Months Ended June 30,						Six Months Ended June 30,						September 30,						September 30,
	2010			2009			2010			2009			2010			2009			2010			2009
Service cost	$	304		$	292		$	608		$	584		$	304		$	287		$	912		$	871
Interest cost	820			785			1,641			1,570			820			786			2,462			2,357
Expected return on plan assets	(752		)	(657		)	(1,504		)	(1,314		)	(752		)	(718		)	(2,256		)	(2,032		)
Prior service cost	15			28			30			56			15			18			45			74
Net loss	344			430			687			860			344			377			1,030			1,236
Curtailment expense													—			189			—			189
Net periodic benefit cost	$	731		$	878		$	1,462		$	1,756		$	731		$	939		$	2,193		$	2,695

~~Ther e were no contributions made~~Pension Plan

In September 2010, bargaining unit participants in the Black Hills Corporation Pension Plan (the “Pension Plan”) voted to ratify a partial freeze to the Pension Plan which is effective January 1, 2011. The partial freeze eliminates new bargaining unit employees from participation in the ~~first~~Pension Plan, and freezes the benefits of current participants except for the following group: those participants who both 1) are age 45 or older as of December 31, 2010 and have 10 years or more of credited service as of January 1, 2011; and 2) elect to continue to accrue additional benefits under the pension plan and consequently forgo the additional age- and points-based employer contribution under the Company's 401(k) retirement savings plan. The assets and obligations for the Black Hills Corporation Pension Plan will be revalued at December 31, 2010 during the year-end valuation process and any pre-tax curtailment expense related to t his partial freeze will be recorded by the Company in the fourth quarter of ~~2010. There are no further contributions expected to be made to the Plan in~~ 2010.

Non-pension Defined Benefit Postretirement Plans

Employees who are participants in the Postretirement Healthcare Plans (the "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 June 30, Six Months Ended June 30,
2010 2009 ; 2010 2009
Service cost $ 94 $ 54 $ 188 $ 108
Interest cost 149 111 298 222
Amortization of prior service cost (42 ) — (84 ) —
Net loss 56 — 112 —
Net transition obligation — 13 — 26
Net periodic benefit cost $ 257 $ 178 $ 514 $ 356

~~We anticipate that we will make contributions to the Healthcare Plan for the 2010 fiscal year of approximately $0.3 million. Contributi ons are expected to be made in the form of benefit payments.~~


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010			2009		2010			2009
Service cost	$	94		$	54	$	282		$	162
Interest cost	149			111		447			333
Amortization of prior service cost	(42		)	—		(126		)	—
Net loss	56			—		168			—
Net transition obligation	—			13		—			39
Net periodic benefit cost	$	257		$	178	$	771		$	534

It has been determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for ~~the~~th e Medicare Part D subsidy. The decrease in net periodic postretirement benefit cost due to the subsidy was less than $0.1 million.

1215

~~&nb sp;~~

Supplemental ~~Nonqualified~~Non-qualified 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				Nin e Months Ended
	Three Months Ended June 30,				Six Months Ended June 30,				September 30,				September 30,
	2010		2009		2010		2009		2010		2009		2010		2009
Interest cost	$	25	$	25	$	50	$	50	$	25	$	25	$	75	$	75
Net loss	7		11		14		22		7		11		21		33
Net periodic benefit cost	$	32	$	36	$	64	$	72
Net periodic benefi t cost									$	32	$	36	$	96	$	108

Contributions

We anticipate that we will make contributions to each of the benefit plans during 2010 and 2011. Contributions to the Healthcare Plan and the Supplemental ~~Plans for the 2010 fiscal year of approximately $0.1 million. Contributions~~Plan are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):


	Nine Months Ended September 30, 2010		Remaining Anticipated Contributions for 2010		Anticipated Contributions for 2011

Defined Benefit Pension Plan	$	8,800	$	—	$	—
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	244	$	81	$	400
Supplemental Non-qualified Defined Benefit Plan	$	74	$	24	$	112

(8) FAIR VALUE OF FINANCIAL INSTRUMENTS

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


	June 30, 2010				December 31, 2009				September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	2,503	$	2,503	$	1,709	$	1,709	$	2,641	$	2,641	$	1,709	$	1,709
Derivative financial instruments - other current assets	$	312	$	312	$	—	$	—	$	355	$	355	$	—	$	—
Derivative financial instruments - accrued liabilities	$	—	$	—	$	5	$	5	$	—	$	—	$	5	$	5
Long-term debt, including current maturities	$	276,537	$	313,767	$	329,069	$	344,942	$	276,526	$	293,009	$	329,069	$	344,942

The following ~~method s~~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.

1317

(9) RISK MANAGEMENT ACTIVITIES AND DERIVATIVES

We hold natural gas in storage for use as fuel for generating electricity with our gas-fired combustion turbines. To minimize associated price risk and seasonal storage level requirements, we utilize various derivative instruments in managing ~~these risks.~~risks associated with prices and seasonal level requirements.

As of ~~June~~September 30, 2010 and December 31, 2009, we had the following swaps and related balances (dollars, in thousands):


	Natural Gas Swaps					Natural Gas Swaps
	June 30, 2010		December 31, 2009			September 30, 2010		December 31, 2009
Notional*	232,500		232,500
Notional - forward purchase *						232,500		232,500
Notional - forward sale *						232,500		—
Maximum terms in months	4		10			1		10
Current derivative asset	$	312	$	—		$	355	$	—
Non-current derivative asset	$	—	$	—		$	—	$	—
Current derivative liability	$	—	$	5		$	—	$	5
Non-current derivative liability	$	—	$	—		$	—	$	—
Pre-tax accumulated other comprehensive income (loss) included in the Condensed Balance Sheets	$	312	$	(5	)	$	355	$	(5	)
Unrealized gain/(loss)	$	—	$	—		$	—	$	—

* Gas in MMBtus.

(10) LONG-TERM DEBT

In February 2010, our Series AC bonds matured. These were paid in full for $30.0 million of principal plus accrued interest of $1.2 million.

In ~~February~~March 2010, we ~~provided notice to the bondholders~~completed redemption of our ~~intent to call the~~ Series Y 9.49% bonds in full. These bonds were originally due in 2018. A total of $2.7 million was paid on March 31, 2010, which included the principal balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and ~~will be~~is being amortized over the remaining term of the original bonds.

In ~~April~~June 2010, we ~~provided notice to the bondholders~~completed redemption of our ~~intent to call the~~ Series Z 9.35% bonds in full. These bonds were originally due to mature in 2021. A total of $21.8 million was paid on June 1, 2010, ~~which~~whi ch included the principal balance of $20.0 million plus accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and ~~will be~~is being amortized over the remaining term of the original bonds.

1418

(11) SUPPLEMENTAL CASH FLOWS INFORMATION


	Six Months ended						Nine Months Ended September 30,
	June 30, 2010			June 30, 2009			January 1, 2010			January 1, 2009
	(in thousands)						(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment financed with accrued liabilities	$	5,897		$	27,782
Property, plant and equipment financed with accrued l iabilities							$	2,920		$	19,344

Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,959	)	$	(4,970	)	$	(14,247	)	$	(9,098	)
Income taxes	$	6,517		$	(621	)	$	8,392		$	(494	)

(12) COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 12 of the Notes to our Financial Statements in our 2009 Annual Report on Form 10-K. There have been no material developments in any previously reported proceedings or any new material ~~proceedings~~procee dings that have developed or material proceedings that have terminated during the first ~~six~~nine months of 2010.

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 ~~June~~September 30, 2010, cannot be reasonably determined and could have a material adverse effect on ~~ou r~~our results of operations, financial position or cash flows.

Purchase Power Agreement and Partial Sale of Wygen III

In March 2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette, Wyoming effective April 2010 that replaces a previous agreement. This PPA provided the City of Gillette, through the JPB, with an option to purchase a 23% ownership interest in our Wygen III facility which commenced commercial operations on April 1, 2010. The City of Gillette notified us of their intent to exercise the option to purchase the 23% ownersh ip interest in Wygen III and the transaction closed in July 2010. The PPA terminated upon the closing of the transaction. (See Note 13)

~~(13)~~ ~~SUBSEQUENT EVENT~~

~~Partial Sale of Wygen III~~

On July 14, 2010, we sold a 23% ownership interest in Wygen III to the JPB for $62.0 million. We recognized a gain of $6.2 million on the sale. The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The transaction entitles the JPB tot o approximately 25.3 MW for the life of the plant. The purchase terminates the current PPA with the City of Gillette, and the Participation Agreement provides that the City of Gillette pay us for administrative services and share in the costs of operating the plant for the life of the facility.

(13) SUBSEQUENT EVENT

Osage Power Plant

On October 1, 2010 we suspended the operations of our 62 year old, 34.5 MW coal-fired Osage power plant located in Osage, Wyoming which was put into operations in 1948. Osage will remain an asset in the generation portf

1520

olio and maintain all operating permits so the plant will have the ability to resume full operations, if needed.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS


													Three Months Ended								Nine Months Ended
	Three Months Ended June 30,						Six Months Ended June 30,						September 30,								September 30,
	2010			2009			2010			2009			2010				2009				2010				2009
	(in thousands)												(in thousands)
Revenues	$	56,438		$	46,836		$	110,927		$	101,294		$	59,051			$	53,086			$	169,978			$	1 54,380
Fuel and purchased power	21,616			19,753			45,852			42,515			20,944				24,254				66,796				66,769
Gross margin	34,822			27,083			65,075			58,779			38,107			28,832				103,182				87,611

Operating, general and administrative expenses	24,312			22,077			45,204			43,068
Operations and maintenance, administrative and general, depreciation expenses													23,253				19,912				68,457				62,980
Gain on sale of operating assets													(6,238		)		—				(6,238		)		—
Operating income	10,510			5,006			1 9,871			15,711			21,092				8,920				40,963				24,631

Interest expense, net	(4,587		)	(2,773		)	(8,058		)	(5,246		)	(4,144		)		(2,789		)		(12,202		)		(8,035		)
Other income	18			508			138			797
Other income, net													22				17				160				814
AFUDC - equity	230			1,276			2,237			2,677			266				2,593				2,503				5,270
Income tax expense	(2,069		)	(912		)	(4,152		)	(3,870		)	(3,158		)		(1,575		)		(7,310		)		(5,445		)
Net income	$	4,102		$	3,105		$	10,036		$	10,069		$	14,078			$	7,166			$	24,114			$	17,235

1622

The following tables provide certain operating statistics (dollars in thousands):


	Electric Revenue												Electric Revenue
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,							Nine Months Ended September 30,
Customer Base	2010		Percentage Change		2009		2010		Percentage Change		2009		2010			Percentage Change		2009		2010			Percentage Change		2009
Commercial	$	16,104	11	%	$	14,551	$	30,643	5	%	$	29,194	$	18,529		18	%	$	15,694	$	49,172		10	%	$	44,888
Residential	11,546		11	%	10,391		26,025		5	%	24,672		13,492			21	%	11,132		39,517			10	%	35,804
Industrial	6,204		23	%	5,030		10,841		11	%	9,780		5,402			15	%	4,714		16,243			12	%	14,494
Municipal Sales	748		13	%	660		1,401		8	%	1,296		850		;	9	%	778		2,251			9	%	2,074
Total retail sales	34,602		13	%	30,632		68,910		6	%	64,942		38,273			18	%	32,318		107,183			10	%	97,260
Contract wholesale	7,078		26	%	5,631		13,796		13	%	12,184		4,758			(27	)%	6,488		18,554			(1	)%	18,672
Wholesale off system	8,539		48	%	5,765		17,255		15	%	14,985		9,695			1	%	9,625		26,950		&nb sp;	10	%	24,610
Total electric sale	50,219		19	%	42,028		99,961		9	%	92,111		52,726			9	%	48,431		152,687			9	%	140,542
Other revenues	6,219		29	%	4,808		10,966		19	%	9,183		6,325			36	%	4,655		17,291			25	%	13,838
Total revenues	$	56,438	21	%	$	46,836	$	110,927	10	%	$	101,294	$	59,051		11	%	$	53,086	$	169,978		10	%	$	154,380


	Megawatt Hours Sold										Megawatt Hours Sold
	Three Months Ended June 30,					Six Months Ended June 30,	Three Months Ended September 30,					Nine Months Ended September 30,
Customer Base	2010	Percentage Change			2009	2010		Percentage Change		2009	2010		Percentage Change		2009	2010		Percentage Change		2009
Commercial	164,863	(3	)%		169,955	349,301		1	%	345,211	195,634		(6	)%	207,939	544,935		(1	)%	553,150
Residential	113,903	(4	)%		119,123	288,438		2	%	282,599	122,123		8	%	113,266	410,561		4	%	395,865
Industrial	101,425	8	%		93,984	188,088		5	%	179,968	90,426		13	%	80,222	278,514		7	%	260,190
Municipal sales	7,577	0	%		7,567	15,803		1	%	15,662	9,008		(9	)%	9,894	24,811		(3	)%	25,556
Total retail sales	387,768	(1	)%		390,629	841,630		2	%	823,440	417,191		1	%	411,321	1,258,821		2	%	1,234,761
Contract wholesale	120,258	(16	)%		143,248	288,723		(7	)%	311,927	83,013		(49	)%	161,796	371,736		(22	)%	473,723
Wholesale off system	299,064	30	%	&n bsp;	230,617	530,111		12	%	474,403	309,297		(0	)%	309,770	839,408	;	7	%	784,173
Total electric sales	807,090	6	%		764,494	1,660,464		3	%	1,609,770	809,501		(8	)%	882,887	2,469,965		(1	)%	2,492,657
Losses and company use	43,792	7	%		41,104	53,511		(20	)%	67,293	42,203		37	%	30,764	95,714		(2	)%	98,057
Total energy	850,882	6	%		805,598	1,713,975		2	%	1,677,063	851,704		(7	)%	913,651	2,565,679		(1	)%	2,590,714


	Electric Utility Power Plant Availability								Electric Utility Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,						Nine Months Ended September 30,
	2010		2009		2010		2009		2010			2009			2010			2009
Coal-fired plants *	90.9	%	77.4	%	91.4	%	87.0	%	94.8	%	^(a)	97.7	%	^(b)	93.1	%	^(a)	90.5	%	^(b)
Other plants	98.8	%	92.2	%	99.3	%	95.8	%	98.2	%		99.6	%		98.9	%		97.1	%
Total availability	93.8	%	83.9	%	94.4	%	90.8	%	96.1	%		98.5	%		95.4	%		93.4	%

___________________________

(a) 2010 reflect the addition of Wygen III which commenced commercial operations on April 1, 2010. Wygen III's availability during the three and nine months ended September 30, 2010 was 96.6% and 91.2%, respectively.

*(b) 2009 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.

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	Megawatt Hours Generated and Purchased								Megawatt Hours Generated and Purchased
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
Generated -	2010	Percentage Change		2009	2010	Percentage Change		2009	2010	Percentage Change		2009	2010		Percentage Change		2009
Coal-fired	559,258	60	%	348,657	989,831	26	%	786,208	525,000	13	%	465,068	1,514,831		21	%	1,251,276
Gas-fired	1,106	(81	)%	5,750	3,944	(42	)%	6,825	11,780	(58	)%	28,251	15,724		(55	)%	35,076
	560,364	58	%	354,407	993,775	25	%	793,033	536,780	9	%	493,319	1,530,555		19	%	1,286,352

Purchased	290,518	(36	)%	451,191	720,200	(19	)%	884,030	314,924	(25	)%	420,332	1,035,124	&n bsp;	(21	)%	1,304,362
Total Generated and Purchased	850,882	6	%	805,598	1,713,975	2	%	1,677,063	851,704	(7	)%	913,651	2,565,679		(1	)%	2,590,714


	Degree Days				Degree Days				Degree Days
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009		2010		2009		2010		2009
Heating and cooling degree days:
Actual -
Heating degree days	904		1,273		4,296		4,527		188		178		4,484		4,705
Cooling degree days	65		51		65		51		456		303		521		354

Variance from normal -
Heating degree days	9	%	28	%	4	%	5	%	(17	)%	(22	)%	(3	)%	4	%
Cooling degree days	(37	)%	(50	)%	(37	)%	(50	)%	(8	)%	(39	)%	(12	)%	(41	)%

Amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in comparative amounts may result due to rounding.

;

Three Months Ended ~~June~~September 30, 2010 Compared to Three Months Ended ~~June~~September 30, 2009. Net income was $~~4.1~~14.1 million compared to $~~3.1~~7.2 million for the same period in the prior year primarily due to the following:

~~G ross~~Gross margin: Gross margin increased $~~7.7~~9.3 million primarily due to an increase of $6.2 million related to the impact of ~~$5.9 million related to~~ the outcome of the rate case ~~where interim rates were put into effect on April 1,~~during 2010, an increase of ~~$0.3~~$2.1 million in off-system ~~sales, a decrease in purchased power costs of $0.9 million due to the commencement of commercial operations of Wygen III,~~margins, and increased intercompany revenues of ~~$0.6~~$0.3 million related to a shared services agreement.

Operating, general and administrative, depreciation expenses: Operating expenses ~~increas ed~~increased $~~2.2~~3.3 million primarily due to additional operating costs of $1.4 million and an increase of ~~$0.9~~$1.3 million in depreciation expense associated with ~~depreciation for~~ the Wygen III plant which commenced commercial operations on April 1, 2010, ~~an increase of $0.4 million in labor and employee benefit costs, an increase in property taxes of $0.2 million~~ and an increase of ~~$0.8~~$0.6 million in intercompany costs associated with a shared services agreement.

Gain on sale of operating assets: Gain on sale of operating assets of $6.2 million resulted from the partial sale of Wygen III to the City of Gillette.

Interest expense, net: Interest expense, net increased $~~1.8~~1.4 million primarily due to higher interest expense of ~~$1.9~~$1.0 million on the first mortgage bonds ~~and~~partially off set by a $0.6 million decrease in AFUDC associated with the borrowed funds ~~with~~component due to the completed construction at Wygen III.

Other income, net: Other income, net decreased $~~1.5~~2.3 million primarily due to a decrease in AFUDC-equity.

Income tax, expense: ~~Income~~The effective tax ~~expense increased~~ ~~$1.2 million~~ ~~primarily due to an increase in earnings before taxes compared~~rate was comparable to the same period in the prior ~~year and a higher~~year. However, the effective tax rate was impacted by a $2.2 million tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of the associated tax benefit resulting from ~~the~~a rate case settlement offset by lower tax benefit from AFUDC-equity which decreased upon commercial operations of Wygen III.

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~~Six~~Nine Months Ended ~~June~~September 30, 2010 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2009. Net income was $~~10.0~~24.1 million compared to $~~10.1~~17.2 million for the same period in prior year primarily due to the following:

Gross margin: Gross margin increased $~~6.3~~15.6 million primarily due to the impact of ~~$5.9~~$12.1 million related to the outcome of the rate case ~~where interim rates that went into effect on April 1,~~during 2010, an increase of ~~$0.7~~$2.6 million from off-system ~~sales,~~margins, and increased intercompany revenues of ~~$1.2~~$1.5 million associated with a shared services ~~agreement, partially offset by an increase in purchased power cost s of $2.1 million not recoverable through the energy cost adjustment.~~agreement.

Operating expenses: Operating expenses increased $~~2.1~~5.5 million primarily due to ana $2.7 million increase ~~of $0.9 million~~ in ~~depreciation expense~~operating expenses associated with ~~depreciation for~~ the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of ~~$0.2~~$1.7 million in ~~labor and employee benefit costs~~depreciation expense primarily associated with the Wygen III plant which commenced commercial operations on April 1, 2010, an increase of $0.7 million in property taxes and an increase of ~~$1.2~~$1.8 million in intercompany costs associated with a shared services agreement.

Gain on sale of operating assets: Gain on sale of op erating assets of $6.2 million resulted from the partial sale of Wygen III to the City of Gillette.

Interest expense, net: Interest expense, net increased $~~2.8~~4.2 million primarily due to a higher interest expense on the first mortgage bonds partially offset by a ~~$0.2~~$0.4 million ~~increase~~decrease in AFUDC associated with the borrowed funds ~~from~~component due to the completed construction at Wygen III.

Other income, net: Other income decreased $~~1.1~~3.4 million primarily due to a decrease in AFUDC-equity of $2.8 million and ~~prior year's~~ recognition of $0.5 million from the sale of Wygen ~~III.~~III in the prior year.

Income tax, expense: The effective tax rate ~~for the six months ended June 30, 2010~~ was comparable to the same period in the prior year. However, the effective tax rate was impacted by a $2.2 million tax benefit for a repairs deduction taken for tax purposes and the ~~six months ended June 30, 2009.~~flow-through treatment of the associated tax benefit resulting from a rate case settlement partially offset by lower tax benefit from AFUDC-equity which decreased upon commercial operations of Wygen III.

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Significant Events

Osage Power Plant

On October 1, 2010 we suspended the operations of our 62 year old, 34.5 MW coal-fired Osage Power Plant located in Osage, Wyoming. The Osage plant consumed 103,100 tons of coal during the first six months of 2010 and 247,100 tons of coal during 2009. Osage will remain an asset in the generation portfolio and maintain all operating permits so the plant will have the ability to resume full operations, if needed.

Sale of Partial Ownership in Wygen III

In March 2010, we entered into a seven-year PPA and Purchase Option Agreement with the City of Gillette, Wyoming effective April 2010 that replaced a previous PPA entered into in 1998. This new agreement ~~also~~ provided the City of Gillette, through the JPB, with an option to purchase a 23% ownership interest, or approximately 25.3 MW, in our Wygen III facility which commenced commercial operations on April 1, 2010. ~~the JBP~~The JPB exists for the purpose of, among other things, financing the electrical system of the City of Gillette. The City of Gillette exercised this option on July 14, 2010 and the JPB purchased the 23% ownership interest in Wygen III for $62.0 million for which wew e will recognize a gain on the sale of approximately ~~$5.0 million to $6.0~~$6.2 million. WeUnder the Participation Agreement among the owners of Wygen III, we will continue to operate Wygen III and ~~through the Participation Agreement,~~ the City of Gillette will pay us for administrative services and its share in the costs of operating the ~~plant.~~plant for the life of the facility. The PPA dated March 2010 terminated upon the closing of the transaction.

Smart Grid Funding

In April 2010, we reached an agreement with the DOE for smart grid funding through grants totaling $9.6 ~~million. The funds are~~mill ion made available through the American Recovery and Reinvestment Act of ~~2009 and, combined with matching investment funds from us,~~2009. The grants will enable us to install ~~69,000~~ smart meters and related communications infrastructure and information technology software and equipment. We expect to complete installation of these meters in ~~2011 and have spent $0.3 million of the DOE grant funds during 2010.~~2011.

Wygen III Power Plant Project

Construction of our 110 MW coal-fired base load electric generation facility, Wygen III, was completed and it commenced commercial operations on April 1, 2010. The ~~expected~~ cost of construction is approximately $255 million, which includes estimates of AFUDC. In April 2009, we sold a 25% ownership interest to MDU. At closing, MDU made a payment to us for its 25% share of the costs to date for the on-going construction of the facility. As described above, in July 2010, we sold an additional 23% ownership in Wygen III to the City of Gillette.

Rate Case Filed with the SDPUC

In 2009, we filed a rate case with the SDPUC requesting an electric revenue increase to recover costs associated with Wygen III and other ~~generation,~~generatio n, transmission and distribution assets and increased operating expenses incurred during the past four years. We were seeking a $32.0 million, or 26.6%, increase in annual utility revenues. In March 2010, the SDPUC approved interim rates for a 20% increase in rates effective April 1, 2010 for South Dakota customers. On July 8,7, 2010, the SDPUC approved a final revenue increase of ~~$ 15.2~~$15.2 million or 12.7%. effective April 1, 2010. The final settlement represented a rate base increase of $22.0 million, or 19.4%. ~~A refund to customers will be provided and has been accrued for the difference in rates.~~

As part of the rate case settlement, we have agreed that (a) 65% of our off-system sales income will be credited to ratepayers with a minimum credit of $2.0 million per year; (b) our rates will reflect ~~an SD~~a South Dakota Surplus Energy Credit of $2.5 million in year ~~one~~on e (fiscal year ending March 2011), $2.25 million in year two, $2.0 million in year three and zero thereafter; and (c) a three year moratorium on any rate case filings excluding any extraordinary events as defined in the stipulation agreement.

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 were seeking a $3.8 million ~~or 38.95%,~~ increase in annual utility revenues. On May 13, 2010, the WPSC approved an annual rate increase of $3.1 million effective June 1, 2010.

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Financing ~~Transactions~~Tra nsactions and Short-Term Liquidity

Financing

In February 2010, our Series AC bonds matured. These ~~w ere~~were paid in full for $30.0 million plus accrued interest of $1.2 million.

In ~~February~~March 2010, we ~~provided notice to the bondholders~~completed a call of our ~~intent to call our~~ Series Y 9.49% bonds in full. These bonds were originally due in 2018. ~~The balance~~A total of $2.7 million was paid on March 31, 2010, which includes the balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.

In ~~April~~June 2010, we ~~provided notice to the bondholders~~completed a call of our ~~intent to call the~~ Series Z 9.35% bonds in full. These bonds, originally due in 2021, were paid in full on June 1, 2010 with a payment of $21.8 million which included principal of $20.0 million, accrued interest and an early redemption premium of 4.675%. The early redemption premium was recorded in unamortized loss on reacquired debt which is included in Regulatory assets on the accompanying Condensed Balance Sheets and will be amortized over the remaining term of the original bonds.

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 ~~June~~September 30, 2010, our first mortgage bonds credit ratings, as assessed by the three major credit rating agencies, were as follows:


Rating Agency	Rating	Outlook
Fitch	A-	Stable
Moody's	A3	Stable
S&P *	~~BB B~~	~~Stable~~
~~Fitch~~	A-BBB+	Stable

* In July 2010, S&P upgraded our senior secured debt rating to BBB+.

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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 ~~actua l~~actual results to differ materially from those anticipated. In some cases, forward-looking statements can be identified by ~~terminology~~t erminology 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 2009 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 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;

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;


•	The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;


•	Changes in business and financial reporting practices arising from the enactment of the Energy Policy Act of 2005 and subsequent rules and regulations promulgated thereunder;

•

Our ability to 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 and subsequent rules and regulations promulgated thereunder;~~

•

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

•

Our ability to successfully complete labor negotiations with our union;

•

Our ability to recover our borrowing costs, including debt service costs, in our customer rates;

•

~~Liabilities of environmental conditions, including remediation and reclamation obligations under environmental laws;~~


•	Liabilities of environmental conditions, including remediation and reclamation obligations under environmental laws;

•

~~Our ability to complete the permitting, construction, start-up and operations of power generating facilities in a cost-effective and timely manner;~~


•	Our ability to complete the permitting, construction, start-up and operations of power generating facilities in a cost-effective and timely manner;

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~~• &nb sp;~~

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;


•	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;~~

ris ks;

•

Our ability to minimize defaults on amounts due from ~~counterpa rty~~counterparty transactions;


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

•

~~Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment and to recover those expenditures in customer rates, whereapplicable;~~


•	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;

•

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, market, political and economic changes, including the impact of consolidations and changes in competition;~~


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

•

The effect of ~~ac counting~~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 cost and effects on our business, including insurance, resulting from terrorist actions or responses to such actions or events;~~


•	The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements on our financial condition or results of operations;

•

~~The outcome of any ongoing or future litigation or similar disputes and the impact on any such outcome or related settlements on our financial condition or results of operations;~~

•

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~~descr ibed 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 ~~June~~September 30, 2010. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over ~~financ ial~~financial reporting during the quarter ended ~~June~~September 30, 2010 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

Effective August 1, 2010, the Company implemented a new financial and human resource system. Although many financial processes were changed, the underlying intern al controls did not materially change. The new financial and human resource system was implemented as part of a corporate unification project of Black Hills Corp. and was not undertaken in response to any actual or perceived significant deficiencies in the Company's internal control over financial reporting. The new system streamlines processes by consolidating two financial systems into one, standardizes accounting systems, is intended to improve management reporting and will consolidate accounting functions for the Parent Company and its subsidiaries.

2431

& nbsp;

BLACK HILLS POWER, ~~INC .~~INC.

Part II - Other Information

Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 1112 of Notes to Financial Statements in ~~Ite m~~Item 8 of our 2009 Annual Report on Form 10-K and Note 812 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 812 is incorporated by reference into this item.

2532

Item 1A. Risk Factors

Except to the extent updated or described below, our Risk Factors are documented in Item 1A. of Part I in our Annual Report on Form 10-K for the year ended December 31, 2009.

Municipal governments may seek to limit or deny franchise privileges.

Municipal governments within our utility service territories possess the power of condemnation, and could seek a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations, and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. ~~Althoug h~~Although condemnation is a process that is subject to constitutional protections requiring just compensation, as with any judicial procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of our investment in assets subject to condemnation.

Federal and state laws concerning climate change and air emissions may materially increase our generation and production costs and could render some of our generating units uneconomical to operate and maintain.

We own and operate regulated and non-regulated fossil-fuel generating plants in South Dakota and Wyoming. We recently completed another fossil-fuel generating plant in Wyoming. 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, which could have a material impact on our costs or operations.

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 carbon dioxide 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 United States Environmental Protection Agency (the "EPA") for further rule-making to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or alternatively, to explain why GHG emissions should not be regulated. On April 17, 2009, the EPA signed its proposed Endangerment and Cause or Contribute Finding for Greenhouse Gases under Section 202 of the Clean Air Act. Although this proposal does not specifically address stationary sources, such as power generation plants, the general endangerment finding relative to GHG's could support such a proposal by the EPA for stationary sources. On October 30, 2009, the EPA published final rules regarding a mandatory GHG reporting regimen, the purpose of which would be to collect data to inform future policy and regulatory decisions.

On June 23, 2010, the EPA published in the Federal Register the Greenhouse Gas Tailoring Rule, implementing regulation of greenhouse gases for permitting purposes. This rule will impact Black Hills in the event of a major modification at an existing facility or in the event of construction of a new major source. Existing permitted facilities will see monitoring and reporting requirements incorporated into their operating permits upon renewal. New projects or major modifi cations to existing projects will result in a Best Available Control Technology review that could result in more stringent emissions control practices and technologies.

On April 29, 2010, the EPA published in the Federal Register the proposed Industrial and Commercial Boiler Hazardous Air Pollutant (IB MACT) regulations, proposing hazardous air pollutant related emission limits and monitoring requirements. The final rule has a court ordered deadline of January 16, 2011 and as proposed, will have a significant impact on our Neil Simpson 1, Osage, and Ben French facilities. The regulation currently has a three year compliance window and will require engineering evaluations to determine economic viability of continued operations of these units. In our current opi nion, the proposed regulations will lead to retirement of these units within three years of the effective date of the final rule.

On June 21, 2010, the EPA published in the Federal Register the proposed coal combustion residuals regulations. The regulations are complex and contain various options and at this time we cannot determine an accurate impact on our operations. EPA is expected to propose the Electric Utility MACT regulation for control of hazardous air pollutants, in the first quarter of 2011. Certain requirements of that regulation could have significant impacts on Neil Simpson 2 and Wygen III. Also late in 2011 EPA is scheduled to issue updated regulations for wastewater discharges from electric generating units, which could have a significant impa ct on all of our generating fleet.

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

New or more stringent regulations, including GHG emissions limitations or other energy efficiency requirements, such as the EPA's recently published Greenhouse Gas Tailoring Rule, which will require additional monitoring and reporting requirements for existing and new facilities, would require, 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-fu el 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.

We own regulated electric utilities that serve customers in South Dakota, Wyoming, and Montana. To a varying degree Montana has adopt ed mandatory renewable portfolio standards that require electric utilities to supply a minimum percentage of the power delivered to customers from renewable resources (e.g., wind, solar, biomass) by a certain date in the future. These renewable energy portfolio standards have increased the power supply costs of our electric operations. If these states increase their renewable energy portfolio standards, 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.

Increased risks of regulatory penalties could negatively impact our business.

The Energy Policy Act of 2005 increased the Federal Energy Regulatory Commission's (“FERC”) civil penalty authority for violation of FERC statutes, rules and orders. FERC can now impose penalties of $1.0 million per violation, per day, and other regulatory agencies that impose compliance requirements relative to our business also have civil penalty authority. In addition, FERC has delegated certain aspects of authority for enforcement of electric system reliability standards to the North American Electric Reliability Corporation, with similar penalty authority for violations. Many rules that were historically subject to voluntary compliance are now mandatory and subject to potential civil penalties for violations. If a serious v iolation did occur, and penalties were imposed by FERC or another federal agency, this action could have a material adverse effect on our operations or our financial results.

2633

Item 6. Exhibits

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

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

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

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

2734

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~~t he 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: ~~August~~November 10, 2010

2835

EXHIBIT INDEX

Exhibit Number Description

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

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

Exhibit 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as ~~a dopted~~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~~Sect ion 906 of the Sarbanes - Oxley Act of 2002.

2936