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, 2011.
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 x	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 29,~~October 31, 2011, 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 - unaudited	4
	Three and ~~Six~~Nine Months Ended ~~June~~September 30, 2011 and 2010

	Condensed Balance Sheets - unaudited	5
	~~June~~September 30, 2011 and December 31, 2010

	Cash Flow Statements - unaudited	6
	~~Six~~Nine Months Ended ~~June~~September 30, 2011 and 2010

	Notes to Condensed Financial Statements - unaudited	7

Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	1614

Item 4.	Controls and Procedures	2120

PART II.	OTHER INFORMATION	2120

Item 1.	Legal Proceedings	2120

Item 1A.	Risk Factors	2120

Item 6.	Exhibits	2120

	Signatures	2322

	Exhibit Index	2423

GLOSSARY OF TERMS AND ABBREVIATIONS

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 220	ASC 220, "Comprehensive Income"
ASC 820	ASC 820, "Fair Value Measurements"
ASU	Accounting Standards Update
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, wholly-owned subsidiary of the Parent Company
Black Hills Wyoming	Black Hills Wyoming, LLC, an indirect, wholly-owned subsidiary of the Parent Company
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of the Parent Company
Enserco	Enserco Energy, Inc., an indirect, wholly-owned subsidiary of the Parent Company
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles of the United States
IFRS	International Financial Reporting Standards
IRS	Internal Revenue Service
LIBOR	London Interbank Offered Rate
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt-hours
PPA	Purchase Power Agreement
PPACA	Patient Protection and Affordability Care Act
SDPUC	South Dakota Public Utilities Commission
SEC	U.S. Securities and Exchange Commission
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned 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,
	2011			2010			2011			2010			2011			2010			2011			2010
	(in thousands)												(in thousands)

Operating revenue	$	56,098		$	56,438		$	115,292		$	110,927		$	64,940		$	59,051		$	180,232		$	169,978

Operating expenses:
Fuel and purchased power	22,764			21,616			44,324			45,852			23,062			20,944			67,386			66,796
Operations and maintenance	16,195			17,356			34,185			32,361			15,470			15,925			49,655			48,286
Gain on sale of operating assets													(768		)	(6,238		)	(768		)	(6,238		)
Depreciation and amortization	6,761			5,684			13,323			10,418			6,921			6,043			20,244			16,461
Taxes - property	1,197			1,272			2,362			2,425			1,080			1,285			3,442			3,710
Total operating expenses	46,917			45,928			94,194			91,056			45,765			37,959			139,959			129,015

Operating income	9,181			10,510			21,098			19,871			19,175			21,092			40,273			40,963

Other income (expense):
Interest expense	(4,533		)	(5,803		)	(8,753		)	(11,283		)
Interest expense incurred													(4,147		)	(4,422		)	(12,900		)	(15,705		)
AFUDC - borrowed	88			187			268			1,801			66			210			334			2,011
Interest income	360			1,029			370			1,424			98			68			468			1,492
AFUDC - equity	155			230			442			2,237			116			266			558			2,503
Other income (expense), net	(256		)	18			(152		)	138			15			22			(137		)	160
Total other income (expense)	(4,186		)	(4,339		)	(7,825		)	(5,683		)	(3,852		)	(3,856		)	(11,677		)	(9,539		)

Income before income taxes	4,995			6,171			13,273			14,188			15,323			17,236			28,596			31,424
Income tax expense	(1,254		)	(2,069		)	(3,651		)	(4,152		)	(4,813		)	(3,158		)	(8,464		)	(7,310		)
Net income	$	3,741		$	4,102		$	9,622		$	10,036		$	10,510		$	14,078		$	20,132		$	24,114

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, 2011			December 31, 2010			September 30, 2011			December 31, 2010
	(in thousands, except share amounts)						(in thousands, except share amounts)
ASSETS
Current assets:
Cash and cash equivalents	$	4,312		$	2,045		$	6,955		$	2,045
Receivables - customers, net	21,736			28,716			23,071			28,716
Receivables - affiliates	3,267			6,891			5,201			6,891
Other receivables, net	466			2,077			369			2,077
Money pool notes receivable	49,827			39,862			59,928			39,862
Materials, supplies and fuel	21,347			21,259			21,654			21,259
Regulatory assets, current	5,627			3,584			5,615			3,584
Other, current assets	3,780			3,712			3,660			3,712
Total current assets	110,362			108,146			126,453			108,146

Investments	4,534			4,396			4,552			4,396

Property, plant and equipment	1,000,649			962,640			1,003,458			962,640
Less accumulated depreciation and amortization	(321,903		)	(304,800		)	(324,054		)	(304,800		)
Total property, plant and equipment, net	678,746			657,840			679,404			657,840

Other assets:
Regulatory assets, non-current	35,765			37,740			36,848			37,740
Other, non-current assets	3,774			3,610			4,287			3,610
Total other assets	39,539			41,350			41,135			41,350
TOTAL ASSETS	$	833,181		$	811,732		$	851,544		$	811,732

LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current maturities of long-term debt	$	78		$	81		$	58		$	81
Accounts payable	13,873			14,828			15,789			14,828
Accounts payable - affiliates	15,299			12,562			13,887			12,562
Accrued liabilities	16,406			15,541			32,390			15,541
Regulatory liabilities, current	1,193			1,932			852			1,932
Deferred income tax liabilities, current	573			859			618			859
Total current liabilities	47,422			45,803			63,594			45,803

Long-term debt, net of current maturities	276,388			276,422			276,389			276,422

Deferred credits and other liabilities:
Deferred income tax liability, non-current	125,507			122,319			115,524			122,319
Regulatory liabilities, non-current	34,633			28,276			35,311			28,276
Benefit plan liabilities	20,695			19,581			21,282			19,581
Other, deferred credits and other liabilities	9,476			9,914			9,863			9,914
Total deferred credits and other liabilities	190,311			180,090			181,980			180,090

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	257,310			247,688			267,820			247,688
Accumulated other comprehensive loss	(1,241		)	(1,262		)	(1,230		)	(1,262		)
Total stockholder's equity	319,060			309,417			329,581			309,417
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY	$	833,181		$	811,732		$	851,544		$	811,732

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

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)


	Six Months Ended June 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)
Operating activities:
Net income	$	9,622		$	10,036		$	20,132		$	24,114
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	13,323			10,418			20,244			16,461
Deferred income tax	4,026			11,029			(6,816		)	20,467
Employee benefits	1,202			2,043			1,803			3,060
Gain on sale of operating assets							(768		)	(6,238		)
AFUDC - equity	(442		)	(2,237		)	(558		)	(2,503		)
Other, net	514			159			213			5,615
Change in operating assets and liabilities -
Accounts receivable and other current assets	11,224			(1,953		)	8,378			(14,663		)
Accounts payable and other current liabilities	866			(10,495		)	17,359			20,143
Regulatory assets	166			(441		)	(96		)	2,665
Regulatory liabilities	(2,358		)	—			(2,158		)	1,245
Contributions to employee benefit plans							—			(8,800		)
Other operating activities	(1,552		)	2,027			(1,399		)	(8,818		)
Net cash provided by operating activities	36,591			20,586			56,334			52,748

Investing activities:
Property, plant and equipment additions	(24,183		)	(40,241		)	(32,277		)	(62,935		)
Proceeds from sale of operating assets							1,135			62,000
Change in money pool notes receivable, net	(9,965		)	57,737			(20,067		)	594
Other investing activities	(139		)	3,392			(156		)	2,244
Net cash provided by (used in) investing activities	(34,287		)	20,888			(51,365		)	1,903

Financing activities:
Long-term debt - repayments	(37		)	(52,532		)	(59		)	(52,543		)
Change in money pool notes payable, net	—			13,028
Other financing activities	—			(1,176		)	—			(1,176		)
Net cash provided by (used in) financing activities	(37		)	(40,680		)	(59		)	(53,719		)

Net change in cash and cash equivalents	2,267			794			4,910			932

Cash and cash equivalents, beginning of period	2,045			1,709			2,045			1,709
Cash and cash equivalents, end of period	$	4,312		$	2,503		$	6,955		$	2,641

See Note 10 for supplemental cash flow information

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

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 2010 Annual Report on Form 10-K)


(1) ~~MANAGEMENT'S STATEMENT~~	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 condensed financial statements should be read in conjunction with the financial statements and the notes thereto, included in our 2010 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 condensed financial statements reflects all adjustments which are, in the opinion of management, necessary for a fair presentation of the ~~June~~September 30, 2011, December 31, 2010 and ~~June~~September 30, 2010 financial information and are of a normal recurring nature. The results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2011 and ~~June~~September 30, 2010, and our financial condition as of ~~June~~September 30, 2011 and December 31, 2010 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 condensed financial statements has been reclassified to conform to the current year presentation. These reclassifications had no effect on our financial position, results of operations, or cash flows.


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

Other Comprehensive Income, ASU No. 2011-05

FASB issued an accounting standards update amending ASC 220 to improve the comparability, consistency and transparency of reporting of comprehensive income. It amends existing guidance by allowing only two options for presenting the components of net income and other comprehensive income: (1) in a single continuous financial statement, statement of comprehensive income or (2) in two separate but consecutive financial statements, consisting of an income statement followed by a separate statement of other comprehensive income. Also, items that are reclassified from other comprehensive income to net income must be presented on the face of the financial statements. ASU No. 2011-05 requires retrospective application, and it is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. We believe the adoption of this update ~~will~~may change the order in which certain financial statements are presented and provide additional detail on those financial statements when applicable, but will not have any other impact on our financial statements.

Fair Value Measurement, ASU No. 2011-04

FASB issued an accounting standards update amending ASC 820 to achieve common fair value measurement and disclosure requirements between ~~U.S.~~ GAAP and IFRS. This amendment changes the wording used to describe fair value and requires additional disclosures. We do not expect this amendment, which is effective for interim and annual periods beginning after December 31, 2011, to have an impact on our financial position, results of operations, or cash flows.

Patient Protection and Affordable Care Act (HR 3590)

In March 2010, the President of the United States signed into law comprehensive healthcare reform legislation under the 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 PPACA is a change in the tax treatment of the Medicare Part D subsidy (the "subsidy") which 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 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.


(3)3~~) ACCOUNTS RECEIVABLE~~ We maintain an allowance for doubtful accounts which reflects our best estimate of probable uncollectible trade receivables. We regularly review our trade 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.	ACCOUNTS RECEIVABLE

Accounts receivable consist of sales to residential, commercial, industrial, municipal and other customers all of which do not bear interest. These accounts receivable balances are stated at billed and unbilled amounts net of write-offs. Approximately 31% of the accounts receivable balance consists of unbilled revenue as of ~~June~~September 30, 2011.

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

The allowance for doubtful accounts represents our best estimate of existing accounts receivable that will ultimately be uncollected. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management's best estimate of future collection success given the existing collections environment.

In specific cases where we are aware of a customer's inability or reluctance to pay, we record an allowance for doubtful accounts against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired.

Following is a summary of accounts receivable balances (in thousands):


	June 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
Accounts receivable trade	$	15,239		$	21,365		$	15,965		$	21,365
Unbilled revenues	6,655			7,581			7,231			7,581
Total accounts receivable - customers	21,894			28,946
Total receivables - customers							23,196			28,946
Allowance for doubtful accounts	(158		)	(230		)	(125		)	(230		)
Receivable - customers, net	$	21,736		$	28,716
Receivables - customers, net							$	23,071		$	28,716


(4) ~~REGULATORY ASSETS AND LIABILITIES~~	REGULATORY ASSETS AND LIABILITIES

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


	Recovery Period	June 30, 2011		December 31, 2010		Recovery Period	September 30, 2011		December 31, 2010
Regulatory assets:
Unamortized loss on reacquired debt	14 years	$	2,891	$	3,016	14 years	$	2,828	$	3,016
AFUDC	Up to 45 years	9,489		9,489		Up to 45 years	9,489		9,489
Defined benefit postretirement plans	Up to 13 years	18,615		18,049		Up to 13 years	18,719		18,049
Deferred energy costs	Less than one year	5,346		3,584		Less than one year	5,511		3,584
Flow through accounting	Up to 35 years	4,284		4,772		Up to 35 years	5,509		4,772
Other		767		2,414			407		2,414
Total regulatory assets		$	41,392	$	41,324		$	42,463	$	41,324

Regulatory liabilities:
Cost of removal for utility plant	Up to 53 years	$	22,851	$	15,429	Up to 53 years	$	23,755	$	15,429
Defined benefit postretirement plans	Up to 13 years	10,874		10,204		Up to 13 years	10,889		10,204
Other		2,101		4,575			1,519		4,575
Total regulatory liabilities		$	35,826	$	30,208		$	36,163	$	30,208

Regulatory assets are primarily recorded for the probable future revenue to recover costs while regulatory liabilities include the ~~costs associated with defined benefit postretirement plans,~~probable future ~~income taxes related to the deferred tax liability for the equity component of AFUDC of utility assets and unamortized losses on reacquired debt.~~decrease in rate revenues. 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 Sheets. Regulatory liabilities are included in Regulatory liabilities, current and Regulatory liabilities, non-current on the accompanying Condensed Balance Sheets.


(5) ~~COMPREHENSIVE INCOME~~	COMPREHENSIVE INCOME

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


	Three Months Ended June 30, 2011					Six Months Ended June 30, 2011					Three Months Ended September 30, 2011					Nine Months Ended September 30, 2011
Net income				$	3,741				$	9,622				$	10,510				$	20,132
Other comprehensive income, net of tax:
Fair value adjustment on derivatives designated as cash flow hedges	$	—				$	—				$	—				$	—
Taxes	—					—					—					—
Fair value adjustment on derivatives designated as cash flow hedges, net of tax				—					—					—					—

Reclassification adjustments included in net income	$	16				$	32				$	16				$	48
Taxes	(6		)			(11		)			(5		)			(16		)
Reclassification adjustments included in net income, net of tax				10					21					11					32

Comprehensive income				$	3,751				$	9,643				$	10,521				$	20,164


	Three Months Ended June 30, 2010						Six Months Ended June 30, 2010					Three Months Ended September 30, 2010					Nine Months Ended September 30, 2010
Net income				$	4,102					$	10,036				$	14,078				$	24,114
Other comprehensive income, net of tax:
Fair value adjustment on derivatives designated as cash flow hedges	$	(10	)				$	317				$	43				$	360
Taxes	4						(111		)			(15		)			(125		)
Fair value adjustment on derivatives designated as cash flow hedges, net of tax				(6		)				206					28					235

Reclassification adjustments included in net income	$	16					$	33				$	16				$	49
Taxes	(6		)				(12		)			(6		)			(18		)
Reclassification adjustments included in net income, net of tax				10						21					10					31

Comprehensive income				$	4,106					$	10,263				$	14,116				$	24,380

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


	June 30, 2011			December 31, 2010			September 30, 2011			December 31, 2010
Derivatives designated as cash flow hedges	$	(827	)	$	(848	)	$	(816	)	$	(848	)
Employee benefit plans	(414		)	(414		)	(414		)	(414		)
Total accumulated other comprehensive loss	$	(1,241	)	$	(1,262	)	$	(1,230	)	$	(1,262	)

109


(6) ~~RELATED-PARTY TRANSACTIONS~~	RELATED-PARTY TRANSACTIONS

Receivables and Payables

We have accounts receivable and accounts payable balances related to transactions with other BHC subsidiaries. The balances were as follows (in thousands):


	June 30, 2011		December 31, 2010		September 30, 2011		December 31, 2010
Receivable - affiliates	$	3,267	$	6,891	$	5,201	$	6,891
Accounts payable - affiliates	$	15,299	$	12,562	$	13,887	$	12,562

Money 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.

We had the following balances with the Utility Money Pool (in thousands):

June 30,
2011 December 31,
2010
Money pool notes receivable $ 49,827
$ 39,862



	September 30, 2011		December 31, 2010
Money pool notes receivable	$	59,928	$	39,862

Advances under the Utility Money Pool notes bear interest at 2.75% above the daily average LIBOR rate (which equates to ~~2.94%~~2.98% at ~~June~~September 30, 2011). Net interest (income) expense relating to balances for the Utility Money Pool was as follows (in thousands):

Three Months Ended June 30, Six Months Ended June 30,
2011 2010 2011 2010
Net interest (income) expense $ (343 ) $ 4
$ (660 ) $ (50 )



	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Net interest (income) expense	$	(384	)	$	(121	)	$	(1,044	)	$	(171	)

1110

Other Balances and Transactions

~~The sales~~Sales and purchases with related parties were as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
Revenues:
Transmission of electricity sold to Black Hills Wyoming	$	58	$	769	$	220	$	942	$	—	$	216	$	220	$	1,158
Electricity and dispatch services sold to Cheyenne Light	$	63	$	326	$	248	$	874	$	354	$	171	$	602	$	1,045

Expenses:
Coal purchases from WRDC	$	5,758	$	3,900	$	10,645	$	7,984	$	5,487	$	4,033	$	16,132	$	13,569
Purchase of excess power generated at Cheyenne Light	$	3,660	$	2,119	$	5,467	$	4,710	$	1,532	$	2,545	$	6,999	$	7,255
Natural gas from Enserco	$	62	$	200	$	223	$	722	$	—	$	611	$	223	$	1,333
Purchase of excess transmission capacity from Black Hills Wyoming									$	8	$	—	$	8	$	—
Corporate support services from Parent and Black Hills Energy	$	4,509	$	4,212	$	9,683	$	8,216	$	4,091	$	3,101	$	13,774	$	11,317

Other Transactions:
Gain on sale of operating asset to BHC									$	768	$	—	$	768	$	—

We have funds on deposit from Black Hills Wyoming for transmission system reserve which are included in Other, deferred credits and other liabilities on the accompanying Condensed Balance Sheets. ~~We have transmission~~Transmission system reserve balances were as follows (in thousands):

June 30,
2011 December 31,
2010
Funds on deposit from affiliate $ 2,076
$ 2,044



	September 30, 2011		December 31, 2010
Funds on deposit from affiliate	$	2,094	$	2,044

Interest on the funds on deposit from Black Hills Wyoming accrues quarterly at an average quarterly prime rate (3.25% at ~~June~~September 30, 2011) (in thousands).

Three Months Ended June 30, Six Months Ended June 30,
2011 2010 2011 2010
Interest expense paid to affiliate $ 16
$ 16
$ 33
$ 32



	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Interest expense paid to affiliate	$	16	$	16	$	49	$	48


(7) ~~EMPLOYEE BENEFIT PLANS~~	EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost	$	199		$	304		$	398		$	608		$	199		$	304		$	597		$	912
Interest cost	773			820			1,546			1,641			773			820			2,319			2,462
Expected return on plan assets	(905		)	(752		)	(1,810		)	(1,504		)	(905		)	(752		)	(2,715		)	(2,256		)
Prior service cost	16			15			32			30			16			15			48			45
Net loss	372			344			744			687			372			344			1,116			1,030

Net periodic benefit cost	$	455		$	731		$	910		$	1,462		$	455		$	731		$	1,365		$	2,193

Non-pension Defined Benefit Postretirement Healthcare 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 were as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
Service cost	$	52		$	94		$	104		$	188		$	52		$	94		$	156		$	282
Interest cost	91			149			182			298			91			149			273			447
Amortization of prior service cost	(78		)	(42		)	(156		)	(84		)	(78		)	(42		)	(234		)	(126		)
Net loss	41			56			82			112			41			56			123			168

Net periodic benefit cost	$	106		$	257		$	212		$	514		$	106		$	257		$	318		$	771

It has been determined that the post-65 retiree prescription drug plans are actuarially equivalent and qualify for the Medicare Part D subsidy.

Supplemental 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 were as follows (in thousands):


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
Interest cost	$	28	$	25	$	56	$	50	$	28	$	25	$	84	$	75
Net loss	12		7		24		14		12		7		36		21
Net periodic benefit cost	$	40	$	32	$	80	$	64	$	40	$	32	$	120	$	96

Contributions

We anticipate that we will make contributions to each of the benefit plans during 2011 and 2012. Contributions to the Healthcare Plans and the Supplemental Plans are expected to be made in the form of benefit payments. Contributions are as follows (in thousands):


	Six Months Ended June 30, 2011		Remaining Anticipated Contributions for 2011		Anticipated Contributions for 2012		Nine Months Ended September 30, 2011		Remaining Anticipated Contributions for 2011		Anticipated Contributions for 2012
Defined Benefit Pension Plan	$	—	$	—	$	904	$	—	$	—	$	—
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	214	$	214	$	518	$	321	$	107	$	518
Supplemental Non-qualified Defined Benefit Plans	$	71	$	71	$	122	$	106	$	35	$	122


(8) ~~FAIR VALUE OF FINANCIAL INSTRUMENTS~~	FAIR VALUE OF FINANCIAL INSTRUMENTS

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


	June 30, 2011				December 31, 2010				September 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents	$	4,312	$	4,312	$	2,045	$	2,045	$	6,955	$	6,955	$	2,045	$	2,045
Long-term debt, including current maturities	$	276,466	$	319,220	$	276,503	$	301,964	$	276,447	$	327,092	$	276,503	$	301,964

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.

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. The first mortgage bonds are either currently not callable or are subject to make-whole provisions which would eliminate any economic benefits if we were to call these bonds.


(9) ~~LONG TERM DEBT~~	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 March 2010, we completed redemption of our 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 is being amortized over the remaining term of the original bonds.

In June 2010, we completed redemption of our 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 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 is being amortized over the remaining term of the original bonds.


(10) ~~SUPPLEMENTAL CASH FLOWS INFORMATION~~	SUPPLEMENTAL CASH FLOWS INFORMATION


	Six Months Ended June 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)						(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment financed with accrued liabilities	$	2,974		$	5,897		$	1,993		$	2,920

Supplemental disclosure of cash flow information:
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(8,183	)	$	(10,959	)	$	(10,595	)	$	(14,247	)
Income taxes	$	15		$	6,517		$	15		$	8,392


(11) ~~COMMITMENTS AND CONTINGENCIES~~	COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We are subject to various legal proceedings, claims and litigation as described in Note 13 of the Notes to our Financial Statements in our 2010 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 ~~six~~nine months of 2011.

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 condensed 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 and to comply with applicable laws and regulations, will not exceed the amounts reflected in our condensed financial statements. As such, costs, if any, that may be incurred in excess of those amounts provided as of ~~June~~September 30, 2011, cannot be reasonably determined and could have a material ~~adverse~~ effect on our results of operations, financial position or cash flows.

1514

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

RESULTS OF OPERATIONS

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


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010			2011			2010			2011			2010
	(in thousands)
Revenue	$	56,098		$	56,438		$	115,292		$	110,927
Operating revenue													$	64,940		$	59,051		$	180,232		$	169,978
Fuel and purchased power	22,764			21,616			44,324			45,852			23,062			20,944			67,386			66,796
Gross margin	33,334			34,822			70,968			65,075			41,878			38,107			112,846			103,182

Operations and maintenance, depreciation and amortization	24,153			24,312			49,870			45,204			23,471			23,253			73,341			68,457
Gain on sale of operating assets													(768		)	(6,238		)	(768		)	(6,238		)
Operating income	9,181			10,510			21,098			19,871			19,175			21,092			40,273			40,963

Interest expense, net	(4,085		)	(4,587		)	(8,115		)	(8,058		)	(3,983		)	(4,144		)	(12,098		)	(12,202		)
Other income, net	(101		)	248			290			2,375			131			288			421			2,663
Income tax expense	(1,254		)	(2,069		)	(3,651		)	(4,152		)	(4,813		)	(3,158		)	(8,464		)	(7,310		)
Net income	$	3,741		$	4,102		$	9,622		$	10,036		$	10,510		$	14,078		$	20,132		$	24,114


	Electric Revenue by Customer Type												Electric Revenue by Customer Type
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2011		Percentage Change		2010		2011		Percentage Change		2010		2011		Percentage Change		2010		2011		Percentage Change		2010
Commercial	$	17,759	10	%	$	16,104	$	35,073	14	%	$	30,643	$	19,889	7	%	$	18,529	$	54,962	12	%	$	49,172
Residential	12,773		11	%	11,546		29,943		15	%	26,025		15,034		11	%	13,492		44,977		14	%	39,517
Industrial	6,464		4	%	6,204		12,228		13	%	10,841		6,716		24	%	5,402		18,944		17	%	16,243
Municipal	783		5	%	748		1,517		8	%	1,401		908		7	%	850		2,425		8	%	2,251
Total retail sales	37,779		9	%	34,602		78,761		14	%	68,910		42,547		11	%	38,273		121,308		13	%	107,183
Contract wholesale	4,370		(38	)%	7,078		8,990		(35	)%	13,796		4,519		(5	)%	4,758		13,509		(27	)%	18,554
Wholesale off-system	7,442		(13	)%	8,539		14,395		(17	)%	17,255		9,158		(6	)%	9,695		23,553		(13	)%	26,950
Total wholesale sales	49,591		(1	)%	50,219		102,146		2	%	99,961		56,224		7	%	52,726		158,370		4	%	152,687
Other revenue	6,507		5	%	6,219		13,146		20	%	10,966		8,716		38	%	6,325		21,862		26	%	17,291
Total revenue	$	56,098	(1	)%	$	56,438	$	115,292	4	%	$	110,927	$	64,940	10	%	$	59,051	$	180,232	6	%	$	169,978

1615


	Megawatt Hours Sold by Customer Type								Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2011	Percentage Change		2010	2011	Percentage Change		2010	2011	Percentage Change		2010	2011	Percentage Change		2010
Commercial	167,649	2	%	164,863	345,886	(1	)%	349,301	198,774	2	%	195,634	544,660	—	%	544,935
Residential	107,683	(5	)%	113,903	282,083	(2	)%	288,438	132,571	9	%	122,123	414,654	1	%	410,561
Industrial	105,861	4	%	101,425	194,610	3	%	188,088	106,658	18	%	90,426	301,268	8	%	278,514
Municipal	7,739	2	%	7,577	16,041	2	%	15,803	9,917	10	%	9,008	25,958	5	%	24,811
Total retail sales	388,932	—	%	387,768	838,620	—	%	841,630	447,920	7	%	417,191	1,286,540	2	%	1,258,821
Contract wholesale *	82,253	(32	)%	120,258	172,212	(40	)%	288,723	84,346	2	%	83,013	256,558	(31	)%	371,736
Wholesale off-system	278,086	(7	)%	299,064	520,242	(2	)%	530,111	299,511	(3	)%	309,297	819,753	(2	)%	839,408
Total wholesale sales	749,271	(7	)%	807,090	1,531,074	(8	)%	1,660,464
Total sales									831,777	3	%	809,501	2,362,851	(4	)%	2,469,965
Losses and company use	39,100	(11	)%	43,792	71,771	34	%	53,511	51,853	23	%	42,203	123,624	29	%	95,714
Total energy	788,371	(7	)%	850,882	1,602,845	(6	)%	1,713,975	883,630	4	%	851,704	2,486,475	(3	)%	2,565,679

* Decrease in 2011 MWh due to the termination of a wholesale contract with a previous wholesale customer who acquired ownership interest in the Wygen III facility.


*	Decrease in 2011 MWh due to the termination of a wholesale contract with a previous wholesale customer who acquired ownership interest in the Wygen III facility.


	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,
	2011			2010			2011			2010			2011		2010			2011			2010
Coal-fired plants	83.6	%	^(a)	90.9	%	^(b)	86.9	%	^(a)	91.4	%	^(b)	93.4	%	94.8	%	^(b)	89.1	%	^(a)	93.1	%	^(b)
Other plants	86.9	%	(c)	98.8	%		92.8	%		99.3	%		98.9	%	98.2	%		94.9	%	(c)	98.9	%
Total availability	84.8	%		93.8	%		89.2	%		94.4	%		95.5	%	96.1	%		91.3	%		95.4	%

___________________________

(a) 2011 reflects a planned major outage at the PacifiCorp-operated Wyodak plant.

(b) 2010 reflects an unplanned 12 day outage at the PacifiCorp-operated Wyodak plant due to a collapsed scrubber vessel.


	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 -	2011	Percentage Change		2010	2011	Percentage Change		2010	2011	Percentage Change		2010	2011	Percentage Change		2010
Coal-fired	386,006	(31	)%	559,258	823,844	(17	)%	989,831	463,032	(12	)%	525,000	1,286,876	(15	)%	1,514,831
Gas-fired	1,147	4	%	1,106	2,171	(45	)%	3,944	11,424	(3	)%	11,780	13,595	(14	)%	15,724
	387,153	(31	)%	560,364	826,015	(17	)%	993,775	474,456	(12	)%	536,780	1,300,471	(15	)%	1,530,555

Purchased	401,218	38	%	290,518	776,830	8	%	720,200	409,174	30	%	314,924	1,186,004	15	%	1,035,124
Total Generated and Purchased	788,371	(7	)%	850,882	1,602,845	(6	)%	1,713,975
Total generated and purchased									883,630	4	%	851,704	2,486,475	(3	)%	2,565,679

1716


	Degree Days								Degree Days
	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010		2011		2010		2011		2010
Heating and cooling degree days:
Actual -
Heating degree days	1,190		904		4,897		4,296		153		188		5,050		4,484
Cooling degree days	56		65		56		65		620		456		676		521

Variance from normal -
Heating degree days	19	%	9	%	14	%	4	%	(33	)%	(17	)%	(30	)%	(3	)%
Cooling degree days	(45	)%	(37	)%	(45	)%	(37	)%	26	%	(8	)%	13	%	(12	)%

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

Three Months Ended ~~June~~September 30, 2011 Compared to Three Months Ended ~~June~~September 30, 2010. Net income was $~~3.7~~10.5 million compared to $~~4.1~~14.1 million for the same period in the prior year primarily due to the following:

Gross margin ~~decreased~~increased $~~1.5~~3.8 million primarily due to ~~lower margins resulting from the termination of power sales contracts upon a customer's purchase of an ownership interest in Wygen III, partially offset by~~higher volumes due to warmer weather and increased transmission ~~gross margin.~~margins.

Operations and maintenance ~~depreciation and amortization~~ ~~expenses are~~was comparable ~~overall. However, there were offsetting variances with~~to the same period in the prior year.

Gain on sale of operating assets in 2011 represents the gain on sale of assets to a ~~decrease due to unplanned maintenance expenditures at the PacifiCorp-operated Wyodak plant~~related party and in 2010 ~~offset by an increase~~represents the gain on sale of a 23% ownership interest in ~~allocation of corporation costs.~~the Wygen III generating facility.

Interest expense, net iswas comparable to the same period in the prior year.

Other income, net iswas comparable to the same period in the prior year.

Income tax, expense: The effective tax rate ~~decreased~~increased from the same period in the prior year due to a ~~true up~~prior year tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of ~~unit of property depreciation flow through accounting.~~such tax benefit resulting from a rate case settlement in 2010.

~~Six~~Nine Months Ended ~~June~~September 30, 2011 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2010. Net income was $~~9.6~~20.1 million compared to $~~10.0~~24.1 million for the same period in prior year primarily due to the following:

Gross margin increased $~~5.9~~9.7 million primarily due to ~~recently~~ approved rate adjustments that include a return on capital investments and ~~increase in~~increased transmission margins partially offset by lower margins resulting from the termination of power sales contracts upon a customer's purchase of an ownership interest in Wygen III.

Operating and maintenance ~~depreciation and amortization~~ expenses increased $~~4.7~~4.9 million primarily due to additional operating costs and depreciation expense of $2.4 million associated with the Wygen III plant which commenced commercial operation on April 1, 2010, and an increase in allocation of corporate costs, partially offset by ~~a decrease in~~ unplanned maintenance expenditures ~~which were incurred~~ at the PacifiCorp-operated Wyodak plant in 2010.

Gain on sale of operating assets in 2011 represents the gain on sale of assets to a related party and in 2010 represents the gain on sale of a 23% ownership interest in the Wygen III generating facility.

Interest expense, net ~~is comparable;~~was comparable to the same period in the prior year; however, notable variances include a ~~$1.5~~$1.7 million decrease in AFUDC associated with borrowed funds due to the completed construction at Wygen III partially offset by lower interest expense of ~~$1.5~~$1.9 million primarily due to repayment of higher rate debt during 2010.

Other income, net decreased $~~2.1~~2.2 million primarily due to a decrease in AFUDC-equity of ~~$1.8~~$1.9 million due to the placement of Wygen III into commercial operation.

Income tax, expense: The effective tax rate ~~was comparable to~~increased from the same period in the prior ~~year.~~year due to a prior year tax benefit for a repairs deduction taken for tax purposes and the flow-through treatment of such tax benefit resulting from a rate case settlement in 2010.

Significant Events

On ~~June 13,~~November 1, 2011, ~~the SDPUC dismissed~~ Black Hills ~~Power's~~Power and Cheyenne Light, a related party, filed a joint request for ~~declaratory ruling~~a certificate of public convenience and necessity with the WPSC to ~~confirm~~construct and operate a new natural gas-fired electric generation facility. The proposed facility will include a combined cycle unit with a gross capacity of 98 MW that ~~a proposed 20 MW wind farm site near Belle Fourche, SD is reasonable and cost effective. The dismissal resulted in a decision~~will be jointly owned by Black Hills Power ~~not to proceed with this project.~~and Cheyenne Light at 55 MW and 43 MW, respectively. If approved by the WPSC, construction will begin in 2012 and the facility would begin serving customers in 2014.

Financing Transactions and Short-Term Liquidity

Financing

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 March 2010, we completed ~~a call~~redemption of our 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 includes the balance of $2.5 million plus accrued interest and an early redemption premium of 2.618%.

In June 2010, we completed ~~a call~~redemption of our 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%.

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, 2011, 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	BBB+	Stable

1918

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 2010 Annual Report on Form 10-K, in Item 1A. of Part II of this Quarterly Report on Form 10-Q, ~~filed~~and other reports that we file with the SEC from time to time, and the following:

Our ability to obtain adequate cost recovery for our retail utility operations through regulatory proceedings; our ability 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;

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 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;

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

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 and to recover those expenditures in customer rates, where applicable;

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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;

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 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 in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events, or otherwise.

~~ITEM 4.~~ ~~CONTROLS AND PROCEDURES~~


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, 2011. 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 ~~June~~September 30, 2011 that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

BLACK HILLS POWER, INC.

Part II - Other Information

~~Item 1.~~ ~~Legal Proceedings~~


Item 1.	Legal Proceedings

For information regarding legal proceedings, see Note 13 of Notes to Financial Statements in Item 8 of our 2010 Annual Report on Form 10-K and Note 11 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 13 is incorporated by reference into this item.

~~Item 1A.~~ ~~Risk Factors~~


Item 1A.	Risk Factors

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, 2010.

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~~Item 6.~~ ~~Exhibits~~


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 31.1	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 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 32.1	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.

~~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.~~


Exhibit 101	Financials for XBRL Format

2221

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: ~~August 11,~~November 8, 2011

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EXHIBIT INDEX

~~Exhibit NumberDescription~~


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 31.1	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 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 32.1	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.

~~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.~~


Exhibit 101	Financials for XBRL Format

2423