10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2014
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 October 31, 2014, 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 and Comprehensive Income - unaudited	4
	Three and Nine Months Ended September 30, 2014 and 2013
	Condensed Balance Sheets - unaudited	5
	September 30, 2014 and December 31, 2013
	Condensed Statements of Cash Flows - unaudited	7
	Nine Months Ended September 30, 2014 and 2013
	Notes to Condensed Financial Statements - unaudited	8
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	14
Item 4.	Controls and Procedures	19
PART II.	OTHER INFORMATION	20
Item 1.	Legal Proceedings	20
Item 1A.	Risk Factors	20
Item 6.	Exhibits	21
	Signatures	22
	Exhibit Index	23

2

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
ASU	Accounting Standards Update
BHC	Black Hills Corporation, the Parent Company
Black Hills Energy	The name used to conduct the business of Black Hills Utility Holdings, Inc., and its subsidiaries
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of BHC
Black Hills Service Company	Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of BHC
Cheyenne Light	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of BHC
Cheyenne Prairie	Cheyenne Prairie Generating Station is a 132 MW natural gas-fired generating facility in Cheyenne, Wyoming, jointly owned by Cheyenne Light and Black Hills Power. Cheyenne Prairie was placed into commercial operations on October 1, 2014.
Cooling degree day	A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
CPCN	Certificate of Public Convenience and Necessity
CT	Combustion Turbine
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Generally Accepted Accounting Principles in the United States of America
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
kV	Kilovolt
LIBOR	London Interbank Offered Rate
Moody’s	Moody’s Investor Services, Inc.
MW	Megawatts
MWh	Megawatt-hours
SEC	U.S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
S&P	Standard & Poor’s Rating Services
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC

3

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Three Months Ended September 30,						Nine Months Ended September 30,
(unaudited)	2014			2013			2014			2013
	(in thousands)
Revenue	$	67,729		$	67,268		$	199,736		$	187,917
Operating expenses:
Fuel, purchased power and natural gas	23,919			22,454			72,242			65,676
Operations and maintenance	16,261			17,744			51,709			51,693
Depreciation and amortization	7,090			7,036			20,949			21,058
Taxes - property	1,452			1,330			4,502			3,990
Total operating expenses	48,722			48,564			149,402			142,417
Operating income	19,007			18,704			50,334			45,500
Other income (expense):
Interest expense	(4,992		)	(4,974		)	(14,923		)	(14,745		)
AFUDC - borrowed	76			25			205			124
Interest income	201			144			470			207
AFUDC - equity	165			45			427			228
Other income (expense), net	5			(52		)	100			174
Total other income (expense)	(4,545		)	(4,812		)	(13,721		)	(14,012		)
Income from continuing operations before income taxes	14,462			13,892			36,613			31,488
Income tax expense	(4,546		)	(4,594		)	(11,824		)	(9,956		)
Net income	9,916			9,298			24,789			21,532
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2014 and 2013 and $(17) and $(18) for the nine months ended September 30, 2014 and 2013, respectively)	10			10			31			30
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(4) and $(5) for the three months ended September 30, 2014 and 2013 and $(12) and $(17) for the nine months ended September 30, 2014 and 2013, respectively)	8			12			22			34
Other comprehensive income	18			22			53			64
Comprehensive income	$	9,934		$	9,320		$	24,842		$	21,596

The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.

4

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)	September 30, 2014			December 31, 2013
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	4,641		$	2,259
Receivables - customers, net	31,419			25,799
Receivables - affiliates	5,448			4,934
Other receivables, net	312			579
Money pool notes receivable, net	—			17,292
Materials, supplies and fuel	24,311			23,278
Deferred income tax assets, net, current	—			2,170
Regulatory assets, current	9,924			4,891
Other, current assets	4,549			4,933
Total current assets	80,604			86,135
Investments	4,554			4,431
Property, plant and equipment	1,163,813			1,095,884
Less accumulated depreciation and amortization	(351,298		)	(334,174		)
Total property, plant and equipment, net	812,515			761,710
Other assets:
Regulatory assets, non-current	45,630			40,373
Other, non-current assets	9,546			8,524
Total other assets	55,176			48,897
TOTAL ASSETS	$	952,849		$	901,173

The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.

5

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)	September 30, 2014			December 31, 2013
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	32,538		$	26,144
Accounts payable - affiliates	22,271			21,082
Accrued liabilities	19,064			14,966
Money pool notes payable, net	19,433			—
Deferred income tax liabilities, net, current	621			—
Regulatory liabilities, current	364			161
Total current liabilities	94,291			62,353
Long-term debt, net of current maturities	257,751			269,948
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	178,368			167,309
Regulatory liabilities, non-current	42,020			43,357
Benefit plan liabilities	10,766			12,105
Other, non-current liabilities	2,957			4,247
Total deferred credits and other liabilities	234,111			227,018
Commitments and contingencies (Notes 5, 6 and 10)
Stockholders’ equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416			23,416
Additional paid-in capital	39,575			39,575
Retained earnings	304,849			280,060
Accumulated other comprehensive loss	(1,144		)	(1,197		)
Total stockholders’ equity	366,696			341,854
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	952,849		$	901,173

The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.

6

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)	Nine Months Ended September 30,
	2014			2013
	(in thousands)
Operating activities:
Net income	$	24,789		$	21,532
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	20,949			21,058
Deferred income tax	11,803			9,630
Employee benefits	971			2,322
AFUDC - equity	(427		)	(228		)
Other adjustments, net	(55		)	1,070
Change in operating assets and liabilities -
Accounts receivable and other current assets	(11,368		)	952
Accounts payable and other current liabilities	12,787			(1,797		)
Contributions to defined benefit pension plan	(1,696		)	(2,299		)
Other operating activities, net	(6,851		)	724
Net cash provided by (used in) operating activities	50,902			52,964
Investing activities:
Property, plant and equipment additions	(72,460		)	(52,242		)
Change in money pool notes receivable, net	17,292			(733		)
Other investing activities	(123		)	(43		)
Net cash provided by (used in) investing activities	(55,291		)	(53,018		)
Financing activities:
Change in money pool notes payable, net	19,433			—
Long-term debt - repayments	(12,200		)	—
Other financing activities	(462		)	—
Net cash provided by (used in) financing activities	6,771			—
Net change in cash and cash equivalents	2,382			(54		)
Cash and cash equivalents, beginning of period	2,259			3,805
Cash and cash equivalents, end of period	$	4,641		$	3,751

See Note 9 for supplemental cash flow information.

The accompanying Notes to Condensed Financial Statements are an integral part of these Condensed Financial Statements.

7

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 2013 Annual Report on Form 10-K)

(1) MANAGEMENT’S STATEMENT

The unaudited condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the “Company,” “we,” “us,” or “our”), 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 2013 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, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2014, December 31, 2013 and September 30, 2013 financial information and are of a normal recurring nature. The results of operations for the three months and nine months ended September 30, 2014 and September 30, 2013, and our financial condition as of September 30, 2014 and December 31, 2013 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued and Adopted Accounting Standards

We have implemented all new accounting pronouncements that are in effect and may impact our financial statements and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.

(2) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Following is a summary of Receivables - customers, net included in the accompanying Condensed Balance Sheets (in thousands) as of:

	September 30, 2014			December 31, 2013
Accounts receivable trade	$	23,261		$	16,300
Unbilled revenues	8,382			9,719
Allowance for doubtful accounts	(224		)	(220		)
Receivables - customers, net	$	31,419		$	25,799

8

(3) REGULATORY ASSETS AND LIABILITIES

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC.

Our regulatory assets and liabilities were as follows (in thousands) as of:

	Recovery/Amortization Period (in years)	September 30, 2014		December 31, 2013
Regulatory assets:
Unamortized loss on reacquired debt(a)	10	$	2,447	$	2,257
AFUDC(b)	45	8,386		8,327
Employee benefit plans(c)	13	15,314		15,233
Deferred energy and fuel cost adjustments - current (a)	1	14,418		7,711
Flow through accounting(a)	35	11,031		9,723
Other(a)	2	3,958		2,013
Total regulatory assets		$	55,554	$	45,264

Regulatory liabilities:
Cost of removal for utility plant(a)	53	$	30,852	$	30,467
Employee benefit plans	13	10,328		10,177
Other	13	1,204		2,874
Total regulatory liabilities		$	42,384	$	43,518

____________________

(a) Recovery or return of costs, but we are not allowed a rate of return.

(b) In addition to recovery of costs, we are allowed a rate of return.

(c) In addition to recovery of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(4) PROPERTY, PLANT AND EQUIPMENT

On March 21, 2014, we retired our Osage, Ben French and Neil Simpson I electric generating plants primarily due to federal environmental regulations. The total plant to be decommissioned remaining in Property, plant and equipment at September 30, 2014 is as follows (in thousands):

Cost of Plant		Accumulated Depreciation			Net Book Value
$	54,230	$	(49,718	)	$	4,512

We reasonably expect the remaining book value to be recovered through future rates.

9

(5) 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) as of:

	September 30, 2014		December 31, 2013
Receivables - affiliates	$	5,448	$	4,934
Accounts payable - affiliates	$	22,271	$	21,082

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. We are the administrator of the Money Pool. Under the Agreement, we may borrow from BHC; however the Agreement restricts us from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings and advances under the Agreement bear interest at the weighted average daily cost of our parent company’s credit facility borrowings 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 plus 1.0%. At September 30, 2014, the average cost of borrowing under the Utility Money Pool was 1.42%.

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

	September 30, 2014		December 31, 2013
Money pool notes receivable, net	$	—	$	17,292
Money pool notes payable, net	$	19,433	$	—

Our net interest income relating to balances with the Utility Money Pool was as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014		2013
Net interest income (expense)	$	(3	)	$	132	$	81	$	420

Other related party activity was as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenue:
Energy sold to Cheyenne Light	$	391	$	238	$	1,467	$	595
Rent from electric properties	$	1,126	$	987	$	3,200	$	2,961
Fuel and purchased power:
Purchases of coal from WRDC	$	4,854	$	4,822	$	13,886	$	14,087
Purchase of excess energy from Cheyenne Light	$	1,117	$	964	$	2,330	$	2,898
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	264	$	228	$	1,393	$	1,293
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	430	$	414	$	2,274	$	2,210
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,274	$	7,583	$	20,433	$	22,637

10

(6) EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	176		$	213		$	528		$	639
Interest cost	748			742			2,244			2,226
Expected return on plan assets	(925		)	(941		)	(2,776		)	(2,823		)
Prior service cost	11			11			32			33
Net loss (gain)	235			652			705			1,956
Net periodic benefit cost	$	245		$	677		$	733		$	2,031

Non-pension Defined Benefit Postretirement Healthcare Plan

The components of net periodic benefit cost for the Non-Pension Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	56		$	54		$	168		$	162
Interest cost	60			60			180			180
Prior service cost (benefit)	(84		)	(69		)	(252		)	(207		)
Net loss (gain)	—			2			—			6
Net periodic benefit cost	$	32		$	47		$	96		$	141

11

Supplemental Non-qualified Defined Benefit Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit Plans were as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Interest cost	$	36	$	33	$	109	$	99
Net loss (gain)	11		17		33		51
Net periodic benefit cost	$	47	$	50	$	142	$	150

Contributions

We anticipate we will make contributions to the benefit plans during 2014 and 2015. Contributions to the Defined Pension Plan are cash contributions made directly to the Pension Plan Trust accounts. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):

	Contributions Nine Months Ended September 30, 2014		Remaining Anticipated Contributions for 2014		Anticipated Contributions for 2015
Defined Benefit Pension Plan	$	1,696	$	—	$	2,193
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	415	$	138	$	595
Supplemental Non-qualified Defined Benefit Plans	$	163	$	54	$	215

(7)    LONG-TERM DEBT

On September 30, 2014, we repaid in full $12 million in principal on the 5.35% Pollution Control Revenue Bonds originally due to mature on October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.

(8) FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance on fair value measurements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Note 1 included in our 2013 Annual Report on Form 10-K filed with the SEC.

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

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	4,641	$	4,641	$	2,259	$	2,259
Long-term debt, including current maturities (b)	$	257,751	$	330,397	$	269,948	$	317,531

_________________

(a) Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b) Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

12

(9) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine months ended September 30,	2014			2013
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	9,534		$	9,495
Non-cash (decrease) to money pool notes receivable, net	$	—		$	(8,000	)
Non-cash dividend to Parent	$	—		$	8,000
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(13,301	)	$	(12,784	)
Income taxes, net	$	—		$	223

(10) COMMITMENTS AND CONTINGENCIES

Other than the items discussed below, there have been no significant changes to commitments and contingencies from those previously disclosed in Note 11 of our Notes to the Financial Statements in our 2013 Annual Report on Form 10-K.

Cheyenne Prairie

Construction was completed on Cheyenne Prairie, a natural gas-fired electric generating facility jointly owned by us and Cheyenne Light. We own 55 MW and Cheyenne Light owns 40 MW of the facility’s combined-cycle unit. Our cost is approximately $91 million for our share of the combined-cycle unit. The facility was placed into commercial operation on October 1, 2014. Included in our cost of Cheyenne Prairie are contingencies of approximately $1.1 million remaining on contracts pertaining to site finishing, contractor close-outs, and construction management demobilization and cleanup. Resolution of these contingencies is expected in the fourth quarter of 2014.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A state fire investigator concluded that the fire was caused by the failure of a transmission structure which we owned, operated and maintained. On April 16, 2013, a lawsuit was filed in the United States District Court for the District of Wyoming, which forty-seven plaintiffs and the State of Wyoming have now joined, asserting claims for damages against us. The claims include allegations of negligence, negligence per se, common law nuisance, and trespass. In addition to claims for these compensatory damages, the lawsuit seeks recovery of punitive damages. Our investigation of the cause and origin of the fire is ongoing. We have denied and will vigorously defend all claims arising out of the fire, pending the completion of our investigation. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation.

Civil litigation of this kind, however, is likely to lead to settlement negotiations, including negotiations prompted by pre-trial civil court procedures. We believe such negotiations would effect a settlement of all claims. Regardless of whether the litigation is determined at trial or through settlement, we expect to incur significant investigation, legal and expert services expenses associated with the litigation. We maintain insurance coverage to limit our exposure to losses due to civil liability claims, and related litigation expense. The deductible applicable to some types of claims arising out of this fire is $1.0 million. We expect this coverage to limit our exposure, and we will pursue recoveries to the maximum extent available under the policies. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, as of September 30, 2014, we recorded a loss contingency liability related to these claims, and we recorded a receivable for costs we believe are reimbursable and probable of recovery under our insurance coverage. Both of these entries reflect our reasonable estimate of probable future litigation expense and settlement costs; we did not base these contingencies on any determination that it is probable we would be found liable for these claims were they to be litigated.

13

Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims in excess of the loss we have determined to be probable is reasonably possible. However, we cannot reasonably estimate the amount of such possible loss because our investigation and review of damage claims documentation is ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these and other parties. While we have received claims seeking recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate, currently totaling $50 million, we are not yet able, for the reasons described above, to reasonably estimate the amount of any reasonable possible losses in excess of the amount we have accrued. Based upon information currently available, however, management does not expect the outcome of the claims to have a material adverse effect upon our consolidated financial condition, results of operations or cash flows.

(11)    SUBSEQUENT EVENT

Long-Term Debt

On October 1, 2014, in a private placement to provide permanent financing for Cheyenne Prairie, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044.

Related-Party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Cheyenne Light in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

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

RESULTS OF OPERATIONS

Amounts are presented on a pre-tax basis unless otherwise indicated.

Minor differences in amounts may result due to rounding.

Significant Events

Cheyenne Prairie

On October 1, 2014, Black Hills Power and Cheyenne Light placed into commercial service their jointly-owned Cheyenne Prairie generating station. Cheyenne Prairie is a natural gas-fired generating facility built to serve Black Hills Power and Cheyenne Light customers. We own 55 MW and Cheyenne Light owns 40 MW of the facility’s combined-cycle unit. Our cost is approximately $91 million for our share of the combined-cycle unit. Cheyenne Prairie was constructed on time and on budget. Construction financing costs were recovered through construction financing riders. New rates were implemented on October 1, 2014 for Black Hills Power customers in Wyoming, as previously approved by the WPSC, and interim rates were implemented on October 1, 2014 for customers in South Dakota.

Bond Issuance

On October 1, 2014, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044 to provide permanent financing for Cheyenne Prairie. Proceeds from the bond sale also funded the September 30, 2014 early redemption of our 5.35%$12 million pollution control revenue bonds, originally due October 1, 2024.

Regulatory Matters

We received approval from the WPSC on the rate case associated with Cheyenne Prairie, previously filed on January 17, 2014. On August 21, 2014, the WPSC approved rate case settlement agreements authorizing an increase for Black Hills Power of approximately $2.2 million for annual electric revenue, effective October 1, 2014. The settlement also included a return on equity of 9.9% and a capital structure of 53.3% equity and 46.7% debt.

On July 22, 2014, we filed a CPCN with the WPSC to construct a $54 million, 230-kV, 144 mile-long transmission line that would connect the Teckla Substation in northeast Wyoming, to the Lange Substation near Rapid City, South Dakota, for the Wyoming portion of this line. On June 30, 2014, we filed an application with the SDPUC, for a permit to construct the South Dakota portion of this line. Approval by the WPSC and SDPUC is anticipated in the fourth quarter of 2014.

14

On March 31, 2014, we filed a rate request with the SDPUC for an annual revenue increase of $14.6 million to recover operating expenses and infrastructure investments, primarily for Cheyenne Prairie. The filing seeks a return on equity of 10.25%, and a capital structure of approximately 53.3% equity and 46.7% debt. Interim rates were implemented on October 1, 2014 when Cheyenne Prairie commenced commercial operations. A final ruling from the SDPUC is expected in the first quarter of 2015.

On March 21, 2014, we retired the Ben French, Neil Simpson I, and Osage coal-fired power plants. These three plants totaling 81 MW were closed because of federal environmental regulations. These plants are primarily replaced by our share of Cheyenne Prairie. On October 1, 2014, we transferred the remaining net book value of these plants to a regulatory asset in accordance with an order granted by the SDPUC.

Results of Operations

The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, gross margin, that is considered a “non-GAAP financial measure.” Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Gross margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of depreciation from the measure. The presentation of gross margin is intended to supplement investors’ understanding of our operating performance.

Gross margin is calculated as operating revenue less cost of fuel, purchased power and natural gas. Our gross margin is impacted by the fluctuations in power purchases, natural gas and other fuel supply costs. However, while these fluctuating costs impact gross margin as a percentage of revenue, they only impact total gross margin if the costs cannot be passed through to our customers.

Our gross margin measure may not be comparable to other companies’ gross margin measure. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

The following tables provide certain financial information and operating statistics:

	Three Months Ended September 30,									Nine Months Ended September 30,
	2014			2013			Variance			2014			2013			Variance
	(in thousands)
Revenue	$	67,729		$	67,268		$	461		$	199,736		$	187,917		$	11,819
Fuel and purchased power	23,919			22,454			1,465			72,242			65,676			6,566
Gross margin	43,810			44,814			(1,004		)	127,494			122,241			5,253
Operating expenses	24,803			26,110			(1,307		)	77,160			76,741			419
Operating income	19,007			18,704			303			50,334			45,500			4,834
Interest income (expense), net	(4,715		)	(4,805		)	90			(14,248		)	(14,414		)	166
Other income (expense), net	170			(7		)	177			527			402			125
Income tax expense	(4,546		)	(4,594		)	48			(11,824		)	(9,956		)	(1,868		)
Net income	$	9,916		$	9,298		$	618		$	24,789		$	21,532		$	3,257

15

	Electric Revenue by Customer Type
	Three Months Ended September 30,					Nine Months Ended September 30,
	(in thousands)
	2014		Percentage Change	2013		2014		Percentage Change	2013
Residential	$	15,941	(6)%	$	16,951	$	50,333	7%	$	46,928
Commercial	24,747		6%	23,319		67,475		13%	59,716
Industrial	6,816		—%	6,850		21,685		8%	20,070
Municipal	964		(11)%	1,078		2,602		(1)%	2,639
Total retail revenue	48,468		1%	48,198		142,095		10%	129,353
Contract wholesale	5,551		(5)%	5,847		15,622		(6)%	16,540
Wholesale off-system	6,278		(23)%	8,123		20,764		(7)%	22,222
Other revenue	7,432		46%	5,100		21,255		7%	19,802
Total revenue	$	67,729	1%	$	67,268	$	199,736	6%	$	187,917

	Megawatt Hours Sold by Customer Type
	Three Months Ended September 30,			Nine Months Ended September 30,
	2014	Percentage Change	2013	2014	Percentage Change	2013
Residential	120,117	(9)%	131,664	398,821	(2)%	406,159
Commercial	214,590	7%	201,332	575,579	4%	551,712
Industrial	96,443	(2)%	98,174	302,208	2%	295,662
Municipal	9,387	(12)%	10,691	24,781	(7)%	26,621
Total retail quantity sold	440,537	—%	441,861	1,301,389	2%	1,280,154
Contract wholesale	83,714	(4)%	87,092	250,941	(7)%	268,529
Wholesale off-system	171,189	(35)%	261,567	595,483	(23)%	777,854
Total quantity sold	695,440	(12)%	790,520	2,147,813	(8)%	2,326,537
Losses and company use	67,325	45%	46,474	170,279	28%	132,629
Total energy	762,765	(9)%	836,994	2,318,092	(6)%	2,459,166

	Megawatt Hours Generated and Purchased
	Three Months Ended September 30,				Nine Months Ended September 30,
Generated -	2014		Percentage Change	2013	2014		Percentage Change	2013
Coal-fired	414,551	(a)(b)	(9)%	457,329	1,168,641	(a)(b)	(12)%	1,334,441
Gas-fired	12,054	(c)	(34)%	18,275	17,026	(c)	(34)%	25,953
Total generated	426,605		(10)%	475,604	1,185,667		(13)%	1,360,394
Total purchased	336,160		(7)%	361,390	1,132,425		3%	1,098,772
Total generated and purchased	762,765		(9)%	836,994	2,318,092		(6)%	2,459,166

__________________

(a) Decrease reflects the retirement of Neil Simpson I on March 21, 2014.

(b) The nine months ended September 30, 2014 reflects a planned annual outage at Neil Simpson II and an unplanned outage for a catalyst repair at Wygen III.

(c) The nine months ended September 30, 2014 include a planned outage at Ben French CT's #1 and #2 for a controls upgrade.

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	Power Plant Availability
	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Coal-fired plants (a)	96.5	%	96.6	%	89.8	%	96.8	%
Other plants (b)	91.4	%	92.6	%	91.0	%	96.1	%
Total availability	94.2	%	95.0	%	90.3	%	96.5	%

____________________

(a) The nine months ended September 30, 2014 reflects a planned annual outage at Neil Simpson II and an unplanned outage for a catalyst repair at Wygen III.

(b) The nine months ended September 30, 2014 include a planned outage at Ben French CT's #1 and #2 for a controls upgrade.

	Degree Days						Degree Days
	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
	Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average		Actual	Variance from 30-year Average
Heating and cooling degree days:
Heating degree days	241	15	%	107	(49	)%	4,676	6	%	4,544	6	%
Cooling degree days	382	(32	)%	646	15	%	481	(28	)%	724	8	%

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2013. Net income was $9.9 million compared to $9.3 million for the same period in the prior year primarily due to the following:

Gross margindecreased primarily due to a 41% decrease in cooling degree days compared to the same period in the prior year resulting in a $1.3 million decrease on lower demand and residential MWh sold. Wholesale margins were also impacted from plant outages related to unit contingent contracts, resulting in $0.7 million decrease in wholesale margins. These decreases were partially offset by increased rider margins of $0.5 million due to a return on additional investment in our generating facilities and higher common use system revenues of $0.3 million.

Operations and maintenancedecreased primarily due to lower generation plant maintenance and employee costs.

Interest expense, net was comparable to the same period in the prior year, reflecting lower interest expense in the current year, partially offset by lower current year interest income driven by a decrease in lending to the Utility money pool.

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

Income tax expense: The effective tax rate was lower in 2014 when compared to 2013 due primarily to an increase in an estimated flow through tax adjustment, partially offset by a prior period research and development tax credit not being extended to 2014.

17

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013. Net income was $25 million compared to $22 million for the same period in the prior year primarily due to the following:

Gross marginincreased primarily due a return on additional investments which increased base electric margins by $3.6 million, increased rider margins by $2.7 million, and a $0.8 million increase resulting from higher retail megawatt hours sold, primarily due to increased commercial and industrial loads. These increases were partially offset by a $1.7 million decrease in contract wholesale margins primarily due to plant outages related to unit contingent contracts.

Operations and maintenanceincreased primarily due to increased generation maintenance and property taxes, partially offset by lower vegetation management and employee costs.

Interest expense, net was comparable to the same period in the prior year, reflecting lower interest expense in the current year, partially offset by lower current year interest income driven by a decrease in lending to the Utility money pool.

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

Income tax expense: The effective tax rate was higher in 2014 when compared to 2013 due primarily to the research and development tax credit not being extended to 2014. The prior year reflected the entire year of the 2012 research and development tax credit due to retroactive reinstatement of the credit in January 2013 by the U.S. Congress.

Financing Plans and Activity

On September 30, 2014 we repaid in full $12 million in principal on the 5.35% Pollution Control Revenue Bonds originally due to mature on October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.

On October 1, 2014, in a private placement to provide permanent financing for Cheyenne Prairie, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044.

Credit Ratings

Credit ratings impact our ability to obtain short and long-term financing, the cost of such financing, and vendor payment terms, including collateral requirements. As of September 30, 2014, our credit ratings for our Senior Secured Debt, as assessed by the three major credit rating agencies, were as follows:

Rating Agency	Rating
S&P	A-
Moody’s(*)	A1
Fitch (**)	A

______________________

* On January 30, 2014, Moody’s upgraded the BHP credit rating to A1 with a stable outlook.

** On June 13, 2014, Fitch upgraded the BHP credit rating to A with a Stable outlook.

18

FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates”, “estimates”, “expects”, “intends”, “plans”, “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature, including statements contained within Item 2 - Management’s Discussion & Analysis.

Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished.

Any forward-looking statement contained in this document speaks only as of the date on which the statement is made, and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements described in Item 1A of our 2013 Annual Report on Form 10-K, including statements contained within Item 1A - Risk Factors and Part II, Item 1A of this Quarterly Report on Form 10Q.

ITEM 4. CONTROLS AND PROCEDURES

This section should be read in conjunction with Item 9A, “Controls and Procedures” included in our Annual Report on Form 10-K for the year ended December 31, 2013.

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) as of September 30, 2014. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2014, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

19

BLACK HILLS POWER, INC.

Part II - Other Information

Item 1. Legal Proceedings

For information regarding legal proceedings, see Note 11 of Notes to Financial Statements in Item 8 of our 2013 Annual Report on Form 10-K and Note 10 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 10 is incorporated by reference into this item.

Item 1A. Risk Factors

Except as noted below, there are no material changes to the Risk Factors previously disclosed in Item 1A of Part I in our Annual Report on Form 10-K for the year ended December 31, 2013.

Federal and state laws concerning greenhouse gas regulations 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 fossil-fuel generating plants in South Dakota and Wyoming. Recent developments under federal and state laws and regulations 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 of operations. In addition to the environmental matters identified in Item 1A of our Annual Report on Form 10-K, the following recently proposed regulations could negatively impact our operations.

On June 2, 2014, the EPA proposed the Clean Power Plan to cut carbon emissions from existing electric generating units. The design of the Clean Power Plan is to decrease existing coal-fired generation, and increase the utilization of existing gas generation, increase renewable energy, and demand side management. This rule could have a significant impact on our coal, natural gas and oil generating fleet. The rule calls for states to develop plans to meet their assigned emission rate targets by 2030. The rule also allows states to formulate a regional approach whereby they would join with other states and be assigned a new single target for the group. We are currently evaluating this proposal, but cannot predict the impact on operations as this rule is expected to be final in June 2015, and state plans are expected to be due at the earliest in June 2016, with extensions possible to 2017 and 2018. We expect any impact to us to be mitigated through the recent Osage, Ben French and Neil Simpson I plant closures.

New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, and the closure of certain generating facilities. To the extent our regulated fossil-fuel generating plants are included in rate base we will attempt to recover costs associated with complying with emission standards or other requirements. We will also attempt to recover the emission compliance costs of our non-regulated fossil-fuel generating plants from utility and other purchasers of the power generated by those 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.

20

Item 6. Exhibits

Exhibit 3.1* Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).

Exhibit 3.2* Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).

Exhibit 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).

Exhibit 4.1* Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

Exhibit 10* Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

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.

Exhibit 101 Financial Statements for XBRL Format

_________________________

* Previously filed as part of the filing indicated and incorporated by reference herein.

21

BLACK HILLS POWER, INC.

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS POWER, INC.

/S/ DAVID R. EMERY

David R. Emery, Chairman

and Chief Executive Officer

/S/ ANTHONY S. CLEBERG

Anthony S. Cleberg, Executive Vice President

and Chief Financial Officer

Dated: November 6, 2014

22

EXHIBIT INDEX

Exhibit Number Description

Exhibit 3.1* Restated Articles of Incorporation of the Registrant (filed as an exhibit to the Registrant’s Form 8-K dated June 7, 1994 (No. 1-7978)).

Exhibit 3.2* Articles of Amendment to the Articles of Incorporation of the Registrant, as filed with the Secretary of State of the State of South Dakota on December 22, 2000 (filed as an exhibit to the Registrant’s Form 10-K for 2000).

Exhibit 3.3* Bylaws of the Registrant (filed as an exhibit to the Registrant’s Registration Statement on Form S-8 dated July 13, 1999).

Exhibit 4.1* Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

Exhibit 10* Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).

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.

Exhibit 101 Financial Statements for XBRL Format

_________________________

* Previously filed as part of the filing indicated and incorporated by reference herein.

23

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, David R. Emery, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Black Hills Power, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; and

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; and

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting.

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 6, 2014
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Anthony S. Cleberg, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Black Hills Power, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting.

5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 6, 2014
		/S/ ANTHONY S. CLEBERG
		Anthony S. Cleberg
		Executive Vice President and
		Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Power, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, David R. Emery, Chairman and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.

Date:	November 6, 2014
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Power, Inc. (the “Company”) on Form 10-Q for the period ended September 30, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Anthony S. Cleberg, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.

Date:	November 6, 2014
		/S/ ANTHONY S. CLEBERG
		Anthony S. Cleberg
		Executive Vice President and
		Chief Financial Officer

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Commitment and Contingencies Cheyenne Prairie (Details) (Cheyenne Prairie [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Unrecorded Unconditional Purchase Obligation [Line Items]
Amount to Construct Generation Plant	$ 91
Unrecorded Unconditional Purchase Obligation, Due in Remainder of Fiscal Year	$ 1.1
Capital Addition Purchase Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Plant Capacity, Megawatts	55
Capital Addition Purchase Commitments [Member] | Cheyenne Light [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Plant Capacity, Megawatts	40

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Accounts Receivable (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Accounts Receivable [Line Items]
Allowance for doubtful accounts	$ (224)	$ (220)
Receivables - customers, net	31,419	25,799
Billed Revenues [Member]
Accounts Receivable [Line Items]
Accounts receivable, trade	23,261	16,300
Unbilled Revenues [Member]
Accounts Receivable [Line Items]
Accounts receivable, trade	$ 8,382	$ 9,719

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Regulatory Accounting

9 Months Ended

Sep. 30, 2014

Regulated Operations [Abstract]

Regulatory Assets and Liabilities [Text Block]

REGULATORY ASSETS AND LIABILITIES

Our regulated electric operations are subject to regulation by various state and federal agencies. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC.

Our regulatory assets and liabilities were as follows (in thousands) as of:

	Recovery/Amortization Period (in years)	September 30, 2014		December 31, 2013
Regulatory assets:
Unamortized loss on reacquired debt(a)	10	$	2,447	$	2,257
AFUDC(b)	45	8,386		8,327
Employee benefit plans(c)	13	15,314		15,233
Deferred energy and fuel cost adjustments - current (a)	1	14,418		7,711
Flow through accounting(a)	35	11,031		9,723
Other(a)	2	3,958		2,013
Total regulatory assets		$	55,554	$	45,264

Regulatory liabilities:
Cost of removal for utility plant(a)	53	$	30,852	$	30,467
Employee benefit plans	13	10,328		10,177
Other	13	1,204		2,874
Total regulatory liabilities		$	42,384	$	43,518

____________________

(a) Recovery or return of costs, but we are not allowed a rate of return.

(b) In addition to recovery of costs, we are allowed a rate of return.

(c) In addition to recovery of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

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Employee Benefit Plans (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Defined Benefit Pension Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	$ 176	$ 213	$ 528	$ 639
Interest cost	748	742	2,244	2,226
Expected return on plan assets	(925)	(941)	(2,776)	(2,823)
Prior service cost (benefit)	11	11	32	33
Net loss (gain)	235	652	705	1,956
Net periodic benefit cost	245	677	733	2,031
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer			1,696
Remaining Anticipated Contributions for Current Year			0
Anticipated Contributions for Next Year			2,193
Non-Pension Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost	56	54	168	162
Interest cost	60	60	180	180
Prior service cost (benefit)	(84)	(69)	(252)	(207)
Net loss (gain)	0	2	0	6
Net periodic benefit cost	32	47	96	141
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer			415
Remaining Anticipated Contributions for Current Year			138
Anticipated Contributions for Next Year			595
Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Interest cost	36	33	109	99
Net loss (gain)	11	17	33	51
Net periodic benefit cost	47	50	142	150
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer			163
Remaining Anticipated Contributions for Current Year			54
Anticipated Contributions for Next Year			$ 215

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Related Party Transactions (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Utility Money Pool [Member]	Sep. 30, 2013 Utility Money Pool [Member]	Sep. 30, 2014 Utility Money Pool [Member]	Sep. 30, 2013 Utility Money Pool [Member]	Sep. 30, 2014 Energy sold to Cheyenne Light [Member]	Sep. 30, 2013 Energy sold to Cheyenne Light [Member]	Sep. 30, 2014 Energy sold to Cheyenne Light [Member]	Sep. 30, 2013 Energy sold to Cheyenne Light [Member]	Sep. 30, 2014 Rent from electric properties [Member]	Sep. 30, 2013 Rent from electric properties [Member]	Sep. 30, 2014 Rent from electric properties [Member]	Sep. 30, 2013 Rent from electric properties [Member]	Sep. 30, 2014 Coal, Purchased [Member]	Sep. 30, 2013 Coal, Purchased [Member]	Sep. 30, 2014 Coal, Purchased [Member]	Sep. 30, 2013 Coal, Purchased [Member]	Sep. 30, 2014 Allocated Costs From Related Parties [Member]	Sep. 30, 2013 Allocated Costs From Related Parties [Member]	Sep. 30, 2014 Allocated Costs From Related Parties [Member]	Sep. 30, 2013 Allocated Costs From Related Parties [Member]	Sep. 30, 2014 Purchase of Excess Energy, Cheyenne Light [Member]	Sep. 30, 2013 Purchase of Excess Energy, Cheyenne Light [Member]	Sep. 30, 2014 Purchase of Excess Energy, Cheyenne Light [Member]	Sep. 30, 2013 Purchase of Excess Energy, Cheyenne Light [Member]	Sep. 30, 2014 Happy Jack Wind Purchase Power Agreeement [Member] Renewable Wind Energy, Cheyenne Light [Member]	Sep. 30, 2013 Happy Jack Wind Purchase Power Agreeement [Member] Renewable Wind Energy, Cheyenne Light [Member]	Sep. 30, 2014 Happy Jack Wind Purchase Power Agreeement [Member] Renewable Wind Energy, Cheyenne Light [Member]	Sep. 30, 2013 Happy Jack Wind Purchase Power Agreeement [Member] Renewable Wind Energy, Cheyenne Light [Member]	Sep. 30, 2014 Silver Sage Wind Power Purchase Agreement [Member] Renewable Wind Energy, Cheyenne Light [Member]	Sep. 30, 2013 Silver Sage Wind Power Purchase Agreement [Member] Renewable Wind Energy, Cheyenne Light [Member]	Sep. 30, 2014 Silver Sage Wind Power Purchase Agreement [Member] Renewable Wind Energy, Cheyenne Light [Member]	Sep. 30, 2013 Silver Sage Wind Power Purchase Agreement [Member] Renewable Wind Energy, Cheyenne Light [Member]
Related Party Transaction [Line Items]
Receivables - affiliates	$ 5,448	$ 4,934
Accounts payable - affiliates	22,271	21,082
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	1.00%
Related Party Transaction, Utility Money Pool Interest Rate	1.42%
Money pool notes receivable, net	0	17,292
Money pool notes payable, net	19,433	0
Interest Income (Expense), Net			(3)	132	81	420
Revenue from Related Parties							391	238	1,467	595	1,126	987	3,200	2,961
Costs and Expenses, Related Party															$ 4,854	$ 4,822	$ 13,886	$ 14,087	$ 6,274	$ 7,583	$ 20,433	$ 22,637	$ 1,117	$ 964	$ 2,330	$ 2,898	$ 264	$ 228	$ 1,393	$ 1,293	$ 430	$ 414	$ 2,274	$ 2,210

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Long-term Debt (Details) (Polution Control Revenue Bonds Due 2024 [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Polution Control Revenue Bonds Due 2024 [Member]
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 12
Debt Instrument, Interest Rate, Stated Percentage	5.35%
Accrued Interest Paid	$ 0.3

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Fair Value of Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013		Sep. 30, 2013	Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, Carrying Amount	$ 4,641		$ 2,259		$ 3,751	$ 3,805
Carrying Amount [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, Carrying Amount	4,641	[1]	2,259	[1]
Long-term Debt, Including Current Maturities, Carrying Amount	257,751	[2]	269,948	[2]
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, Fair Value	4,641	[1]	2,259	[1]
Long-term debt, Including Current Maturities, Fair Value	$ 330,397	[2]	$ 317,531	[2]

[1] Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

[2] Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

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Accounts Receivable

9 Months Ended

Sep. 30, 2014

Accounts Receivable, Net [Abstract]

Accounts Receivables [Text Block]

ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Following is a summary of Receivables - customers, net included in the accompanying Condensed Balance Sheets (in thousands) as of:

	September 30, 2014			December 31, 2013
Accounts receivable trade	$	23,261		$	16,300
Unbilled revenues	8,382			9,719
Allowance for doubtful accounts	(224		)	(220		)
Receivables - customers, net	$	31,419		$	25,799

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Supplemental Disclosures of Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Noncash Investing and Financing Items [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 9,534	$ 9,495
Non-cash Payment of Notes Receivable, Related Parties	0	(8,000)
Interest and Income Taxes Paid Net [Abstract]
Interest paid, (net of amounts capitalized)	(13,301)	(12,784)
Income taxes, net	0	223
Parent [Member]
Noncash Investing and Financing Items [Abstract]
Non-cash Dividends Distributed to Parent by Subsidiaries	$ 0	$ 8,000

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Condensed Income Statements (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenue	$ 67,729	$ 67,268	$ 199,736	$ 187,917
Operating expenses:
Fuel, purchased power and natural gas	23,919	22,454	72,242	65,676
Operations and maintenance	16,261	17,744	51,709	51,693
Depreciation and amortization	7,090	7,036	20,949	21,058
Taxes - property	1,452	1,330	4,502	3,990
Total operating expenses	48,722	48,564	149,402	142,417
Operating income	19,007	18,704	50,334	45,500
Other income (expense):
Interest expense	(4,992)	(4,974)	(14,923)	(14,745)
AFUDC - borrowed	76	25	205	124
Interest income	201	144	470	207
AFUDC - equity	165	45	427	228
Other income (expense), net	5	(52)	100	174
Total other income (expense)	(4,545)	(4,812)	(13,721)	(14,012)
Income from continuing operations before income taxes	14,462	13,892	36,613	31,488
Income tax expense	(4,546)	(4,594)	(11,824)	(9,956)
Net Income	9,916	9,298	24,789	21,532
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2014 and 2013 and $(17) and $(18) for the nine months ended September 30, 2014 and 2013, respectively)	10	10	31	30
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(4) and $(5) for the three months ended September 30, 2014 and 2013 and $(12) and $(17) for the nine months ended September 30, 2014 and 2013, respectively)	8	12	22	34
Other comprehensive income	18	22	53	64
Comprehensive income	$ 9,934	$ 9,320	$ 24,842	$ 21,596

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Condensed Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Operating activities:
Net income	$ 24,789	$ 21,532
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	20,949	21,058
Deferred income tax	11,803	9,630
Employee benefits	971	2,322
AFUDC - equity	(427)	(228)
Other adjustments, net	(55)	1,070
Change in operating assets and liabilities -
Accounts receivable and other current assets	(11,368)	952
Accounts payable and other current liabilities	12,787	(1,797)
Contributions to defined benefit pension plan	(1,696)	(2,299)
Other operating activities, net	(6,851)	724
Net cash provided by (used in) operating activities	50,902	52,964
Investing activities:
Property, plant and equipment additions	(72,460)	(52,242)
Change in money pool notes receivable, net	17,292	(733)
Other investing activities	(123)	(43)
Net cash provided by (used in) investing activities	(55,291)	(53,018)
Financing activities:
Change in money pool notes payable, net	19,433	0
Long-term debt - repayments	(12,200)	0
Other financing activities	(462)	0
Net cash provided by (used in) financing activities	6,771	0
Net change in cash and cash equivalents	2,382	(54)
Cash and Cash Equivalents:
Cash and cash equivalents, beginning of period	2,259	3,805
Cash and cash equivalents, end of period	$ 4,641	$ 3,751

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Subsequent Event (Details) (Subsequent Event [Member], First Mortgage Bonds Due 2044 [Member], USD $) In Millions, unless otherwise specified	0 Months Ended
	Oct. 01, 2014	Oct. 01, 2014
Subsequent Event [Member] | First Mortgage Bonds Due 2044 [Member]
Long-term Debt, Gross		$ 85
Debt Instrument, Interest Rate, Stated Percentage		4.43%
Debt Instrument, Maturity Date	Oct. 20, 2044

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 2014

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	176		$	213		$	528		$	639
Interest cost	748			742			2,244			2,226
Expected return on plan assets	(925		)	(941		)	(2,776		)	(2,823		)
Prior service cost	11			11			32			33
Net loss (gain)	235			652			705			1,956
Net periodic benefit cost	$	245		$	677		$	733		$	2,031

Non-pension Defined Benefit Postretirement Healthcare Plan

The components of net periodic benefit cost for the Non-Pension Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	56		$	54		$	168		$	162
Interest cost	60			60			180			180
Prior service cost (benefit)	(84		)	(69		)	(252		)	(207		)
Net loss (gain)	—			2			—			6
Net periodic benefit cost	$	32		$	47		$	96		$	141

Supplemental Non-qualified Defined Benefit Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit Plans were as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Interest cost	$	36	$	33	$	109	$	99
Net loss (gain)	11		17		33		51
Net periodic benefit cost	$	47	$	50	$	142	$	150

Schedule of Defined Benefit Plans Contributions [Table Text Block]

Contributions and anticipated contributions are as follows (in thousands):

	Contributions Nine Months Ended September 30, 2014		Remaining Anticipated Contributions for 2014		Anticipated Contributions for 2015
Defined Benefit Pension Plan	$	1,696	$	—	$	2,193
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	415	$	138	$	595
Supplemental Non-qualified Defined Benefit Plans	$	163	$	54	$	215

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Supplemental Disclosures of Cash Flow Information (Tables)

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

Nine months ended September 30,	2014			2013
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	9,534		$	9,495
Non-cash (decrease) to money pool notes receivable, net	$	—		$	(8,000	)
Non-cash dividend to Parent	$	—		$	8,000
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(13,301	)	$	(12,784	)
Income taxes, net	$	—		$	223

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Management's Statement

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Management's Statement

MANAGEMENT’S STATEMENT

The unaudited condensed financial statements included herein have been prepared by Black Hills Power, Inc. (the “Company,” “we,” “us,” or “our”), 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 2013 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, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2014, December 31, 2013 and September 30, 2013 financial information and are of a normal recurring nature. The results of operations for the three months and nine months ended September 30, 2014 and September 30, 2013, and our financial condition as of September 30, 2014 and December 31, 2013 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued and Adopted Accounting Standards

We have implemented all new accounting pronouncements that are in effect and may impact our financial statements and do not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on our financial position, results of operations, or cash flows.

Revenue from Contracts with Customers, ASU 2014-09

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer, as opposed to recognizing revenue when the risks and rewards transfer to the customer under the existing revenue guidance. ASU 2014-09 is effective for annual and interim reporting periods beginning after December 15, 2016 and early adoption is not permitted. We are currently assessing the impact, if any, that ASU 2014-09 will have on our financial position, results of operations or cash flows.

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Condensed Income Statements OCI Parenthetical (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Reclassification adjustment of cash flow hedges settled, (tax) benefit	$ (6)	$ (6)	$ (17)	$ (18)
Reclassification adjustment of benefit and other postretirement plans included in net income, (tax) benefit	$ (4)	$ (5)	$ (12)	$ (17)

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Subsequent Event

9 Months Ended

Sep. 30, 2014

Subsequent Events [Abstract]

Subsequent Events [Text Block]

SUBSEQUENT EVENT

Long-Term Debt

On October 1, 2014, in a private placement to provide permanent financing for Cheyenne Prairie, we issued $85 million of 4.43% coupon first mortgage bonds due October 20, 2044.

Related-Party Gas Transportation Service Agreement

On October 1, 2014, we entered into a gas transportation service agreement with Cheyenne Light in connection with gas supply for Cheyenne Prairie. The agreement is for a term of 40 years, in which we pay a monthly service and facility fee for firm and interruptible gas transportation.

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Document and Entity Information Document	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document Information [Line Items]
Entity Registrant Name	BLACK HILLS POWER INC
Entity Central Index Key	0000012400
Document Type	10-Q
Document Period End Date	Sep. 30, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		23,416,396

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Accounts Receivable (Tables)

9 Months Ended

Sep. 30, 2014

Accounts Receivable, Net [Abstract]

Schedule of Accounts Receivable [Table Text Block]

Following is a summary of Receivables - customers, net included in the accompanying Condensed Balance Sheets (in thousands) as of:

	September 30, 2014			December 31, 2013
Accounts receivable trade	$	23,261		$	16,300
Unbilled revenues	8,382			9,719
Allowance for doubtful accounts	(224		)	(220		)
Receivables - customers, net	$	31,419		$	25,799

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Condensed Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 4,641	$ 2,259
Receivables - customers, net	31,419	25,799
Receivables - affiliates	5,448	4,934
Other receivables, net	312	579
Money pool notes receivable, net	0	17,292
Materials, supplies and fuel	24,311	23,278
Deferred income tax assets, net, current	0	2,170
Regulatory assets, current	9,924	4,891
Other, current assets	4,549	4,933
Total current assets	80,604	86,135
Investments	4,554	4,431
Property, plant and equipment	1,163,813	1,095,884
Less accumulated depreciation and amortization	(351,298)	(334,174)
Total property, plant and equipment, net	812,515	761,710
Other assets:
Regulatory assets, non-current	45,630	40,373
Other, non-current assets	9,546	8,524
Total other assets	55,176	48,897
TOTAL ASSETS	952,849	901,173
Current liabilities:
Accounts payable	32,538	26,144
Accounts payable - affiliates	22,271	21,082
Accrued liabilities	19,064	14,966
Money pool notes payable, net	19,433	0
Deferred income tax liabilities, net, current	621	0
Regulatory liabilities, current	364	161
Total current liabilities	94,291	62,353
Long-term debt, net of current maturities	257,751	269,948
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	178,368	167,309
Regulatory liabilities, non-current	42,020	43,357
Benefit plan liabilities	10,766	12,105
Other, non-current liabilities	2,957	4,247
Total deferred credits and other liabilities	234,111	227,018
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416	23,416
Additional paid-in capital	39,575	39,575
Retained earnings	304,849	280,060
Accumulated other comprehensive loss	(1,144)	(1,197)
Total stockholder’s equity	366,696	341,854
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 952,849	$ 901,173

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Employee Benefit Plans

9 Months Ended

Sep. 30, 2014

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Employee Benefit Plans Disclosure [Text Block]

EMPLOYEE BENEFIT PLANS

Defined Benefit Pension Plan

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	176		$	213		$	528		$	639
Interest cost	748			742			2,244			2,226
Expected return on plan assets	(925		)	(941		)	(2,776		)	(2,823		)
Prior service cost	11			11			32			33
Net loss (gain)	235			652			705			1,956
Net periodic benefit cost	$	245		$	677		$	733		$	2,031

Non-pension Defined Benefit Postretirement Healthcare Plan

The components of net periodic benefit cost for the Non-Pension Defined Benefit Postretirement Healthcare Plan were as follows (in thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2014			2013			2014			2013
Service cost	$	56		$	54		$	168		$	162
Interest cost	60			60			180			180
Prior service cost (benefit)	(84		)	(69		)	(252		)	(207		)
Net loss (gain)	—			2			—			6
Net periodic benefit cost	$	32		$	47		$	96		$	141

Supplemental Non-qualified Defined Benefit Plans

The components of net periodic benefit cost for the Supplemental Non-qualified Defined Benefit Plans were as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Interest cost	$	36	$	33	$	109	$	99
Net loss (gain)	11		17		33		51
Net periodic benefit cost	$	47	$	50	$	142	$	150

Contributions

We anticipate we will make contributions to the benefit plans during 2014 and 2015. Contributions to the Defined Pension Plan are cash contributions made directly to the Pension Plan Trust accounts. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions and anticipated contributions are as follows (in thousands):

	Contributions Nine Months Ended September 30, 2014		Remaining Anticipated Contributions for 2014		Anticipated Contributions for 2015
Defined Benefit Pension Plan	$	1,696	$	—	$	2,193
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	415	$	138	$	595
Supplemental Non-qualified Defined Benefit Plans	$	163	$	54	$	215

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Related Party Transactions

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

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) as of:

	September 30, 2014		December 31, 2013
Receivables - affiliates	$	5,448	$	4,934
Accounts payable - affiliates	$	22,271	$	21,082

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. We are the administrator of the Money Pool. Under the Agreement, we may borrow from BHC; however the Agreement restricts us from loaning funds to BHC or to any of BHC’s non-utility subsidiaries. The Agreement does not restrict us from paying dividends to BHC. Borrowings and advances under the Agreement bear interest at the weighted average daily cost of our parent company’s credit facility borrowings 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 plus 1.0%. At September 30, 2014, the average cost of borrowing under the Utility Money Pool was 1.42%.

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

	September 30, 2014		December 31, 2013
Money pool notes receivable, net	$	—	$	17,292
Money pool notes payable, net	$	19,433	$	—

Our net interest income relating to balances with the Utility Money Pool was as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014		2013
Net interest income (expense)	$	(3	)	$	132	$	81	$	420

Other related party activity was as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenue:
Energy sold to Cheyenne Light	$	391	$	238	$	1,467	$	595
Rent from electric properties	$	1,126	$	987	$	3,200	$	2,961
Fuel and purchased power:
Purchases of coal from WRDC	$	4,854	$	4,822	$	13,886	$	14,087
Purchase of excess energy from Cheyenne Light	$	1,117	$	964	$	2,330	$	2,898
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	264	$	228	$	1,393	$	1,293
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	430	$	414	$	2,274	$	2,210
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,274	$	7,583	$	20,433	$	22,637

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Fair Value of Financial Instruments(Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Financial Instruments

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

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	4,641	$	4,641	$	2,259	$	2,259
Long-term debt, including current maturities (b)	$	257,751	$	330,397	$	269,948	$	317,531

_________________

(a) Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b) Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

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Regulatory Accounting (Tables)

9 Months Ended

Sep. 30, 2014

Regulated Operations [Abstract]

Schedule of Regulatory Assets [Table Text Block]

Our regulatory assets and liabilities were as follows (in thousands) as of:

	Recovery/Amortization Period (in years)	September 30, 2014		December 31, 2013
Regulatory assets:
Unamortized loss on reacquired debt(a)	10	$	2,447	$	2,257
AFUDC(b)	45	8,386		8,327
Employee benefit plans(c)	13	15,314		15,233
Deferred energy and fuel cost adjustments - current (a)	1	14,418		7,711
Flow through accounting(a)	35	11,031		9,723
Other(a)	2	3,958		2,013
Total regulatory assets		$	55,554	$	45,264

Schedule of Regulatory Liabilities [Table Text Block]

Regulatory liabilities:
Cost of removal for utility plant(a)	53	$	30,852	$	30,467
Employee benefit plans	13	10,328		10,177
Other	13	1,204		2,874
Total regulatory liabilities		$	42,384	$	43,518

____________________

(a) Recovery or return of costs, but we are not allowed a rate of return.

(b) In addition to recovery of costs, we are allowed a rate of return.

(c) In addition to recovery of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

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Supplemental Disclosure of Cash Flow Information

9 Months Ended

Sep. 30, 2014

Supplemental Cash Flow Information [Abstract]

Cash Flow, Supplemental Disclosures [Text Block]

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine months ended September 30,	2014			2013
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	9,534		$	9,495
Non-cash (decrease) to money pool notes receivable, net	$	—		$	(8,000	)
Non-cash dividend to Parent	$	—		$	8,000
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(13,301	)	$	(12,784	)
Income taxes, net	$	—		$	223

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Long-term Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

LONG-TERM DEBT

On September 30, 2014, we repaid in full $12 million in principal on the 5.35% Pollution Control Revenue Bonds originally due to mature on October 1, 2024. In addition, we paid the accrued interest on these bonds of $0.3 million.

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance on fair value measurements establishes a hierarchy for grouping assets and liabilities, based on significance of inputs. For additional information see Note 1 included in our 2013 Annual Report on Form 10-K filed with the SEC.

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

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	4,641	$	4,641	$	2,259	$	2,259
Long-term debt, including current maturities (b)	$	257,751	$	330,397	$	269,948	$	317,531

_________________

(a) Carrying value approximates fair value due to either short-term length of maturity or variable interest rates that approximate prevailing market rates and therefore is classified in Level 1 in the fair value hierarchy.

(b) Long-term debt is valued using the market approach based on observable inputs of quoted market prices and yields available for debt instruments either directly or indirectly for similar maturities and debt ratings in active markets and therefore is classified in Level 2 in the fair value hierarchy. The carrying amount of our variable rate debt approximates fair value due to the variable interest rates with short reset periods.

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Commitment and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

COMMITMENTS AND CONTINGENCIES

Other than the items discussed below, there have been no significant changes to commitments and contingencies from those previously disclosed in Note 11 of our Notes to the Financial Statements in our 2013 Annual Report on Form 10-K.

Cheyenne Prairie

Construction was completed on Cheyenne Prairie, a natural gas-fired electric generating facility jointly owned by us and Cheyenne Light. We own 55 MW and Cheyenne Light owns 40 MW of the facility’s combined-cycle unit. Our cost is approximately $91 million for our share of the combined-cycle unit. The facility was placed into commercial operation on October 1, 2014. Included in our cost of Cheyenne Prairie are contingencies of approximately $1.1 million remaining on contracts pertaining to site finishing, contractor close-outs, and construction management demobilization and cleanup. Resolution of these contingencies is expected in the fourth quarter of 2014.

Oil Creek Fire

On June 29, 2012, a forest and grassland fire occurred in the western Black Hills of Wyoming. A state fire investigator concluded that the fire was caused by the failure of a transmission structure which we owned, operated and maintained. On April 16, 2013, a lawsuit was filed in the United States District Court for the District of Wyoming, which forty-seven plaintiffs and the State of Wyoming have now joined, asserting claims for damages against us. The claims include allegations of negligence, negligence per se, common law nuisance, and trespass. In addition to claims for these compensatory damages, the lawsuit seeks recovery of punitive damages. Our investigation of the cause and origin of the fire is ongoing. We have denied and will vigorously defend all claims arising out of the fire, pending the completion of our investigation. We cannot predict the outcome of our investigation, the viability of alleged claims or the outcome of the litigation.

Civil litigation of this kind, however, is likely to lead to settlement negotiations, including negotiations prompted by pre-trial civil court procedures. We believe such negotiations would effect a settlement of all claims. Regardless of whether the litigation is determined at trial or through settlement, we expect to incur significant investigation, legal and expert services expenses associated with the litigation. We maintain insurance coverage to limit our exposure to losses due to civil liability claims, and related litigation expense. The deductible applicable to some types of claims arising out of this fire is $1.0 million. We expect this coverage to limit our exposure, and we will pursue recoveries to the maximum extent available under the policies. Based upon information currently available, we believe that a loss associated with settlement of pending claims is probable. Accordingly, as of September 30, 2014, we recorded a loss contingency liability related to these claims, and we recorded a receivable for costs we believe are reimbursable and probable of recovery under our insurance coverage. Both of these entries reflect our reasonable estimate of probable future litigation expense and settlement costs; we did not base these contingencies on any determination that it is probable we would be found liable for these claims were they to be litigated.

Given the uncertainty of litigation, however, a loss related to the fire, the litigation and related claims in excess of the loss we have determined to be probable is reasonably possible. However, we cannot reasonably estimate the amount of such possible loss because our investigation and review of damage claims documentation is ongoing, and there are significant factual and legal issues to be resolved. Further claims may be presented by these and other parties. While we have received claims seeking recovery for fire suppression, reclamation and rehabilitation costs, damage to fencing and other personal property, alleged injury to timber, grass or hay, livestock and related operations, and diminished value of real estate, currently totaling $50 million, we are not yet able, for the reasons described above, to reasonably estimate the amount of any reasonable possible losses in excess of the amount we have accrued. Based upon information currently available, however, management does not expect the outcome of the claims to have a material adverse effect upon our consolidated financial condition, results of operations or cash flows.

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Commitment and Contingencies Oil Creek Fire (Details) (Oil Creek Fire [Member], Loss from Catastrophes [Member], USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014
Minimum [Member]
Loss Contingencies [Line Items]
Insurance Coverage Deductible Per Occurrence	$ 1.0
Maximum [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 50

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Related Party Transactions (Tables)

9 Months Ended

Sep. 30, 2014

Related Party Transactions [Abstract]

Schedule of Related Party Accounts Receivable and Payable [Table Text Block]

The balances were as follows (in thousands) as of:

	September 30, 2014		December 31, 2013
Receivables - affiliates	$	5,448	$	4,934
Accounts payable - affiliates	$	22,271	$	21,082

Schedule of Related Party Notes [Table Text Block]

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

	September 30, 2014		December 31, 2013
Money pool notes receivable, net	$	—	$	17,292
Money pool notes payable, net	$	19,433	$	—

Schedule of Related Party Interest Income Expense [Table Text Block]

Our net interest income relating to balances with the Utility Money Pool was as follows (in thousands):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014			2013		2014		2013
Net interest income (expense)	$	(3	)	$	132	$	81	$	420

Schedule of Revenues and Purchases from Related Parties [Table Text Block]

Other related party activity was as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2014		2013		2014		2013
Revenue:
Energy sold to Cheyenne Light	$	391	$	238	$	1,467	$	595
Rent from electric properties	$	1,126	$	987	$	3,200	$	2,961
Fuel and purchased power:
Purchases of coal from WRDC	$	4,854	$	4,822	$	13,886	$	14,087
Purchase of excess energy from Cheyenne Light	$	1,117	$	964	$	2,330	$	2,898
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	264	$	228	$	1,393	$	1,293
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	430	$	414	$	2,274	$	2,210
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,274	$	7,583	$	20,433	$	22,637

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Regulatory Accounting (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014		Dec. 31, 2013
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets	$ 55,554		$ 45,264
Regulatory Liabilities	42,384		43,518
Cost of removal for utility plant [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period	P53Y
Regulatory Liabilities	30,852	[1]	30,467	[1]
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period	P13Y
Regulatory Liabilities	10,328		10,177
Other regulatory liabilities [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Liabilities Amortization Period	P13Y
Regulatory Liabilities	1,204		2,874
Unamortized Loss on reacquired debt [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Recovery Period	P10Y
Regulatory Assets	2,447	[1]	2,257	[1]
Allowance For Funds Used During Construction [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Recovery Period	P45Y
Regulatory Assets	8,386	[2]	8,327	[2]
Employee benefit plans [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Recovery Period	P13Y
Regulatory Assets	15,314	[3]	15,233	[3]
Deferred energy and fuel cost adjustments - current [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Recovery Period	P1Y
Regulatory Assets	14,418	[1]	7,711	[1]
Flow through accounting [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Recovery Period	P35Y
Regulatory Assets	11,031	[1]	9,723	[1]
Other regulatory assets [Member]
Schedule of Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Recovery Period	P2Y
Regulatory Assets	$ 3,958	[1]	$ 2,013	[1]

[1] Recovery or return of costs, but we are not allowed a rate of return.

[2] In addition to recovery of costs, we are allowed a rate of return.

[3] In addition to recovery of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

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Balance Sheet Parantheticals (USD $)	Sep. 30, 2014	Dec. 31, 2013
Common Stock, Par Value	$ 1.00	$ 1.00
Common Stock, Shares Authorized	50,000,000	50,000,000
Common Stock, Shares, Issued	23,416,396	23,416,396
Common Stock, Shares, Outstanding	23,416,396	23,416,396

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Property, plant and equipment

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment Disclosure [Text Block]

PROPERTY, PLANT AND EQUIPMENT

On March 21, 2014, we retired our Osage, Ben French and Neil Simpson I electric generating plants primarily due to federal environmental regulations. The total plant to be decommissioned remaining in Property, plant and equipment at September 30, 2014 is as follows (in thousands):

Cost of Plant		Accumulated Depreciation			Net Book Value
$	54,230	$	(49,718	)	$	4,512

We reasonably expect the remaining book value to be recovered through future rates.

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Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Gross Cost of Plant to be Decommissioned included in PP&E	$ 1,163,813	$ 1,095,884
Accumulated Depreciation on Decommissioned Plant	(351,298)	(334,174)
Total property, plant and equipment, net	812,515	761,710
Generation Facilities Retired [Member]
Property, Plant and Equipment [Line Items]
Gross Cost of Plant to be Decommissioned included in PP&E	54,230
Accumulated Depreciation on Decommissioned Plant	(49,718)
Total property, plant and equipment, net	$ 4,512

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Property, Plant and Equipment (Tables)

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment [Table Text Block]

The total plant to be decommissioned remaining in Property, plant and equipment at September 30, 2014 is as follows (in thousands):

Cost of Plant		Accumulated Depreciation			Net Book Value
$	54,230	$	(49,718	)	$	4,512