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 June 30, 2017
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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	o		Accelerated filer	o
Non-accelerated filer	x	(Do not check if a smaller reporting company)
			Smaller reporting company	o
			Emerging growth company	o

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

Yes o No x

As of July 31, 2017, 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 Six Months Ended June 30, 2017 and 2016
	Condensed Balance Sheets - unaudited	5
	June 30, 2017 and December 31, 2016
	Condensed Statements of Cash Flows - unaudited	7
	Six Months Ended June 30, 2017 and 2016
	Notes to Condensed Financial Statements - unaudited	8
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	15
Item 4.	Controls and Procedures	19
PART II.	OTHER INFORMATION	20
Item 1.	Legal Proceedings	20
Item 1A.	Risk Factors	20
Item 6.	Exhibits	20
	Signatures	21
	Exhibit Index	22

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
ASC	Accounting Standards Codification
ASU	Accounting Standards Update issued by the FASB
BHC	Black Hills Corporation; the Parent Company
Black Hills Energy	The name used to conduct the business of BHC utility companies
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc. a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
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 Black Hills Corporation (doing business as Black Hills Energy)
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.
DSM	Demand Side Management
ECA	Energy Cost Adjustment - adjustments that allow us to pass the prudently-incurred cost of fuel and purchased energy through to customers.
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings
GAAP	Accounting principles generally accepted in the United States of America
Global Settlement	Settlement with a utilities commission where the dollar figure is agreed upon, but the specific adjustments used by each party to arrive at the figure are not specified in public rate orders.
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 Investors Service, Inc.
MW	Megawatts
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
TCA	Transmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
Winter Storm Atlas	An October 2013 blizzard that impacted South Dakota Electric. It was the second most severe blizzard in Rapid City’s history.
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 June 30,						Six Months Ended June 30,
(unaudited)	2017			2016			2017			2016
	(in thousands)
Revenue	$	66,053		$	62,019		$	139,847		$	130,661
Operating expenses:
Fuel and purchased power	18,612			16,224			41,761			36,954
Operations and maintenance	18,888			16,906			35,842			33,937
Depreciation and amortization	8,831			8,204			17,525			16,816
Taxes - property	2,010			1,749			3,631			3,238
Total operating expenses	48,341			43,083			98,759			90,945
Operating income	17,712			18,936			41,088			39,716
Other income (expense):
Interest expense	(5,635		)	(5,414		)	(11,390		)	(10,868		)
AFUDC - borrowed	392			298			584			521
Interest income	243			292			369			494
AFUDC - equity	717			566			1,188			989
Other income (expense), net	(69		)	(47		)	(122		)	27
Total other income (expense)	(4,352		)	(4,305		)	(9,371		)	(8,837		)
Income before income taxes	13,360			14,631			31,717			30,879
Income tax expense	(4,073		)	(4,825		)	(9,860		)	(9,887		)
Net income	9,287			9,806			21,857			20,992
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(5) and $(5) for the three months ended June 30, 2017 and 2016, and $(11) and $(11) for the six months ended June 30, 2017 and 2016, respectively)	11			11			21			21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(7) for the three months ended June 30, 2017 and 2016 and $(15) and $(14) for the six months ended June 30, 2017 and 2016, respectively)	14			13			28			27
Other comprehensive income	25			24			49			48
Comprehensive income	$	9,312		$	9,830		$	21,906		$	21,040

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)	June 30, 2017			December 31, 2016
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,156		$	234
Receivables - customers, net	26,702			30,614
Receivables - affiliates	6,596			9,526
Other receivables, net	334			351
Money pool notes receivable, net	12,471			28,409
Materials, supplies and fuel	22,989			22,389
Regulatory assets, current	21,453			18,119
Other, current assets	3,857			3,876
Total current assets	95,558			113,518
Investments	4,849			4,841
Property, plant and equipment	1,280,757			1,236,387
Less accumulated depreciation and amortization	(348,258		)	(338,828		)
Total property, plant and equipment, net	932,499			897,559
Other assets:
Regulatory assets, non-current	71,449			74,015
Other, non-current assets	3,586			3,816
Total other assets	75,035			77,831
TOTAL ASSETS	$	1,107,941		$	1,093,749

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)	June 30, 2017			December 31, 2016
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	15,842		$	14,158
Accounts payable - affiliates	23,745			31,799
Accrued liabilities	46,744			37,436
Regulatory liabilities, current	825			84
Total current liabilities	87,156			83,477
Long-term debt	339,825			339,756
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	214,539			211,443
Regulatory liabilities, non-current	54,818			53,866
Benefit plan liabilities	19,645			19,544
Other, non-current liabilities	1,390			1,001
Total deferred credits and other liabilities	290,392			285,854
Commitments and contingencies (Notes 4, 5 and 8)
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	328,790			322,933
Accumulated other comprehensive loss	(1,213		)	(1,262		)
Total stockholder’s equity	390,568			384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,107,941		$	1,093,749

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)	Six Months Ended June 30,
	2017			2016
	(in thousands)
Operating activities:
Net income	$	21,857		$	20,992
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	17,525			16,816
Deferred income tax	1,605			18,009
Employee benefits	408			886
AFUDC - equity	(1,188		)	(989		)
Other adjustments, net	408			(236		)
Change in operating assets and liabilities -
Accounts receivable and other current assets	7,188			3,234
Accounts payable and other current liabilities	(3,486		)	(11,538		)
Regulatory assets - current	(315		)	(7,026		)
Regulatory liabilities - current	741			—
Contributions to defined benefit pension plan	—			(820		)
Other operating activities, net	380			168
Net cash provided by (used in) operating activities	45,123			39,496
Investing activities:
Property, plant and equipment additions	(44,142		)	(35,153		)
Change in money pool notes receivable, net	(62		)	(4,286		)
Other investing activities	3			(67		)
Net cash provided by (used in) investing activities	(44,201		)	(39,506		)
Financing activities:
Net cash provided by (used in) financing activities	—			—
Net change in cash and cash equivalents	922			(10		)
Cash and cash equivalents, beginning of period	234			297
Cash and cash equivalents, end of period	$	1,156		$	287

See Note 7 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 2016 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 2016 Annual Report on Form 10-K filed with the SEC.

The information furnished in the accompanying condensed financial statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2017, December 31, 2016 and June 30, 2016 financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2017 and June 30, 2016, and our financial condition as of June 30, 2017 and December 31, 2016 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Revisions

Certain revisions have been made to prior year’s financial information to conform to the current year presentation.

We revised our presentation of cash and certain cash transactions processed on behalf of affiliates as of December 31, 2016.  We have banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Cash collected or disbursed on behalf of affiliates is presented as Receivables - affiliates or Accounts payable - affiliates. Prior year amounts were corrected to conform to the current year presentation, which decreased cash and cash equivalents by $19 million as of June 30, 2016. It also decreased net cash flows provided by operations by $12 million for the six months ended June 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of June 30, 2016 and to the Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued and Adopted Accounting Standards

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures and monitor utility industry implementation discussions and guidance. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.

8

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term greater than 12 months, whereas today only financing type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted.

We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, pole attachments and other industry-related areas. We also expect to implement changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases.

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. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

9

(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:

	June 30, 2017			December 31, 2016
Accounts receivable trade	$	15,731		$	16,972
Unbilled revenues	11,137			13,799
Allowance for doubtful accounts	(166		)	(157		)
Receivables - customers, net	$	26,702		$	30,614

(3) REGULATORY ACCOUNTING

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)	June 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,674	$	1,815
Deferred taxes on AFUDC (b)	45	9,913		9,367
Employee benefit plans(c)	12	20,100		20,100
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	20,397		23,016
Deferred taxes on flow through accounting (a)	35	13,464		12,545
Decommissioning costs, net of amortization(d)	6	11,201		12,456
Other regulatory assets (a)(d)	6	16,153		12,835
Total regulatory assets		$	92,902	$	92,134

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	42,514	$	41,541
Employee benefit plan costs and related deferred taxes (c)	12	12,304		12,304
Other regulatory liabilities	13	825		105
Total regulatory liabilities		$	55,643	$	53,950

____________________

(a) We are allowed a recovery 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 or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million will be amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately$2.7 million.

10

(4) 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:

	June 30, 2017		December 31, 2016
Receivables - affiliates	$	6,596	$	9,526
Accounts payable - affiliates	$	23,745	$	31,799

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, Black Hills Service Company and the utility companies conducting business as 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 external 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 June 30, 2017, the average cost of borrowing under the Utility Money Pool was 1.61%.

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

	June 30, 2017		December 31, 2016
Money pool notes receivable, net	$	12,471	$	28,409

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Net interest income (expense)	$	90	$	290	$	216	$	568

11

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	625	$	648	$	1,505	$	1,309
Rent from electric properties	$	935	$	1,375	$	1,870	$	2,588
Fuel and purchased power:
Purchases of coal from WRDC	$	3,052	$	3,357	$	7,332	$	8,153
Purchase of excess energy from Cheyenne Light	$	76	$	53	$	116	$	108
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	369	$	353	$	975	$	1,017
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	637	$	602	$	1,656	$	1,729
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	198	$	200
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,109	$	6,177	$	13,720	$	12,898

(5) EMPLOYEE BENEFIT PLANS

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	136		$	151		$	272		$	302
Interest cost	585			625			1,170			1,250
Expected return on plan assets	(897		)	(908		)	(1,794		)	(1,816		)
Prior service cost	11			11			22			22
Net loss (gain)	307			499			614			998
Net periodic benefit cost	$	142		$	378		$	284		$	756

Defined Benefit Postretirement Healthcare Plan

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	51		$	51		$	103		$	102
Interest cost	44			47			88			94
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	11		$	14		$	23		$	28

12

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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Interest cost	$	29	$	30	$	58	$	60
Net loss (gain)	21		21		43		42
Net periodic benefit cost	$	50	$	51	$	101	$	102

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust accounts. On July 24, 2017, we made contributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands):

	Contributions Six Ended June 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	—	$	1,834	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	271	$	271	$	565
Supplemental Non-qualified Defined Benefit Plans	$	124	$	124	$	246

(6) 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 2016 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:

	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	1,156	$	1,156	$	234	$	234
Long-term debt, net of deferred financing costs (b)	$	339,825	$	434,228	$	339,756	$	410,466

_________________

(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 based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

13

(7) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Six months ended June 30,	2017			2016
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,495		$	5,355
Non-cash (decrease) to money pool notes receivable, net	$	(16,000	)	$	(24,500	)
Non-cash dividend to Parent	$	16,000		$	24,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,786	)	$	(10,547	)

(8) COMMITMENTS AND CONTINGENCIES

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 2016 Annual Report on Form 10-K.

14

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

Regulatory Matters

On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a six-year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes a suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas will be amortized over the moratorium period. These balances were previously amortized over a 10-year period ending September 30, 2024. The vegetation management regulatory asset of $14 million, previously unamortized, will also be amortized over the moratorium period. The change in amortization periods for these costs will increase annual amortization expense by approximately$2.7 million.

The June 16, 2017 settlement had no impact to base rates. The following table illustrates information about certain enacted regulatory provisions with respect to South Dakota Electric:

Jurisdiction	Authorized Rate of Return on Equity	Authorized Return on Rate Base	Authorized Capital Structure Debt/Equity	Effective Date	Tariffs and Rate Matters	Percentage of Power Marketing Profit Shared with Customers
SD	Global Settlement	7.76%	Global Settlement	10/2014	ECA,TCA, Energy Efficiency Cost Recovery/ DSM	70%

Transmission

Construction was completed on the 144 mile-long transmission line connecting the Teckla Substation in northeast Wyoming to the Lange Substation near Rapid City, South Dakota. The first segment of this project connecting Teckla to Osage, WY was placed in service on August 31, 2016. The second segment connecting Osage to Lange was placed in service on May 30, 2017.

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 and purchased power. 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.

15

The following tables provide certain financial information and operating statistics:

	Three Months Ended June 30,									Six Months Ended June 30,
	2017			2016			Variance			2017			2016			Variance
	(in thousands)
Revenue	$	66,053		$	62,019		$	4,034		$	139,847		$	130,661		$	9,186
Fuel and purchased power	18,612			16,224			2,388			41,761			36,954			4,807
Gross margin	47,441			45,795			1,646			98,086			93,707			4,379
Operating expenses	29,729			26,859			2,870			56,998			53,991			3,007
Operating income	17,712			18,936			(1,224		)	41,088			39,716			1,372
Interest income (expense), net	(5,000		)	(4,824		)	(176		)	(10,437		)	(9,853		)	(584		)
Other income (expense), net	648			519			129			1,066			1,016			50
Income tax expense	(4,073		)	(4,825		)	752			(9,860		)	(9,887		)	27
Net income	$	9,287		$	9,806		$	(519	)	$	21,857		$	20,992		$	865

Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016. Net income was $9.3 million compared to $9.8 million for the same period in the prior year primarily due to the following:

Gross marginincreased over the prior year reflecting a $2.5 million increase in rider revenues primarily related to transmission investment recovery. Partially offsetting these increases was $0.4 million in lower residential margins driven primarily by lower cooling degree days. Compared to normal, cooling degree days were 15% higher than normal in the current year compared to 74% higher than normal for the same period in the prior year.

Operating expensesincreased primarily due to higher employee costs as a result of prior year integration activities and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, higher property taxes with increased asset base, and increased maintenance costs from higher outages.

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

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

Income tax expense: The effective tax rate was lower than the prior year, primarily due to higher flow-through benefits in the current year.

Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016. Net income was $22 million compared to $21 million for the same period in the prior year primarily due to the following:

Gross marginincreased over the prior year reflecting a $3.0 million increase in rider revenues primarily related to transmission investment recovery.

Operating expensesincreased primarily due to higher employee costs as a result of prior year integration activities and transition expenses charged to our Parent Company related to its prior year acquisition of SourceGas, higher property taxes with increased asset base, and increased maintenance costs from higher outages.

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

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

Income tax expense: The effective tax rate was comparable to the same period in the prior year.

16

	Electric Revenue by Customer Type
	Three Months Ended June 30,					Six Months Ended June 30,
	(in thousands)
	2017		Percentage Change	2016		2017		Percentage Change	2016
Residential	$	15,633	(4)%	$	16,241	$	35,704	—%	$	35,556
Commercial	22,858		(4)%	23,723		47,149		—%	47,312
Industrial	8,171		5%	7,764		16,625		2%	16,265
Municipal	942		(2)%	960		1,778		(1)%	1,791
Total retail revenue	47,604		(2)%	48,688		101,256		—%	100,924
Contract wholesale (a)	6,702		70%	3,947		14,545		79%	8,121
Wholesale off-system (b)	2,424		(11)%	2,734		6,257		(15)%	7,320
Other revenue (c)	9,323		40%	6,650		17,789		24%	14,296
Total revenue	$	66,053	7%	$	62,019	$	139,847	7%	$	130,661

____________________

(a) Increase for the three and six months ended June 30, 2017 was primarily due to a new 50 MW power sales agreement with Cargill effective January 1, 2017.

(b) Decrease in 2017 revenue was primarily driven by commodity prices that impacted power marketing sales.

(c) Increase from the prior year is primarily due to higher transmission revenues.

	Megawatt Hours Sold by Customer Type
	Three Months Ended June 30,			Six Months Ended June 30,
	2017	Percentage Change	2016	2017	Percentage Change	2016
Residential	107,521	(6)%	114,851	257,093	—%	257,604
Commercial	173,720	(9)%	190,207	370,126	(2)%	379,095
Industrial	103,497	1%	102,620	213,293	1%	210,641
Municipal	8,104	(5)%	8,487	15,709	(1)%	15,928
Total retail quantity sold	392,842	(6)%	416,165	856,221	(1)%	863,268
Contract wholesale (a)	165,881	196%	56,087	351,997	194%	119,540
Wholesale off-system (b)	102,966	(12)%	117,064	257,462	(17)%	310,437
Total quantity sold	661,689	12%	589,316	1,465,680	13%	1,293,245
Losses and company use (c)	57,189	87%	30,528	99,030	42%	69,852
Total energy	718,878	16%	619,844	1,564,710	15%	1,363,097

____________________

(a) Increase for the three and six months ended June 30, 2017 was primarily due to a new 50 MW power sales agreement with Cargill effective January 1, 2017.

(b) Decrease in 2017 sales was primarily driven by commodity prices that impacted power marketing sales.

(c) Includes company uses, line losses, and excess exchange production.

17

	Megawatt Hours Generated and Purchased
	Three Months Ended June 30,			Six Months Ended June 30,
Generated -	2017	Percentage Change	2016	2017	Percentage Change	2016
Coal-fired	289,540	9%	265,032	677,525	4%	653,033
Gas-fired (a)	11,024	(72)%	39,433	21,374	(61)%	54,995
Total generated	300,564	(1)%	304,465	698,899	(1)%	708,028
Total purchased (b)	418,314	33%	315,379	865,811	32%	655,069
Total generated and purchased (b)	718,878	16%	619,844	1,564,710	15%	1,363,097

____________________

(a) Decrease is primarily due to the ability to purchase excess generation in the open market at a lower cost than to generate for the three and six months ended June 30, 2017.

(b) Increase in 2017 is primarily driven by resource needs from a new 50 MW power sales agreement with Cargill, effective January 1, 2017.

	Power Plant Availability
	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Coal-fired plants (a)	67.6	%	64.5	%	78.4	%	78.4	%
Other plants	98.0	%	99.2	%	98.7	%	98.7	%
Total availability	83.7	%	84.2	%	89.2	%	90.0	%

____________________

(a) Both years included outages. 2017 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2016 included a planned outage at Wygen III and an extended planned outage at Wyodak.

	Degree Days						Degree Days
	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	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 degree days	910	(11	)%	877	(13	)%	4,040	(5	)%	3,683	(13	)%
Cooling degree days	114	15	%	186	74	%	114	15	%	186	74	%

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. The following table represents our secured credit rating from each agency’s review which was in effect at June 30, 2017:

Rating Agency	Secured Rating
S&P	A-
Moody’s	A1
Fitch	A

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 of Financial Condition and Results of Operations.

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 2016 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 10-Q.

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, 2016.

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 June 30, 2017. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of June 30, 2017.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2017, there have been no changes in our internal control over financial reporting that have 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 2016 Annual Report on Form 10-K and Note 8 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 8 is incorporated by reference into this item.

Item 1A. Risk Factors

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, 2016.

Item 6. Exhibits

Exhibit 3.1* Restated Articles of Incorporation of the Registrant dated March 30, 2015 (filed as Exhibit 3.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

Exhibit 3.2* Amended and Restated Bylaws of the Registrant dated March 30, 2015 (filed as Exhibit 3.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

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)). 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.

20

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/ RICHARD W. KINZLEY

Richard W. Kinzley, Senior Vice President

and Chief Financial Officer

Dated: August 8, 2017

21

EXHIBIT INDEX

Exhibit Number Description

Exhibit 3.1* Restated Articles of Incorporation of the Registrant dated March 30, 2015 (filed as Exhibit 3.1 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

Exhibit 3.2* Amended and Restated Bylaws of the Registrant dated March 30, 2015 (filed as Exhibit 3.2 to Registrant’s Form 10-Q for the quarterly period ended March 31, 2015).

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)). 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.

22

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:	August 8, 2017
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Richard W. Kinzley, 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:	August 8, 2017
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior 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 June 30, 2017 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:	August 8, 2017
		/S/ DAVID R. EMERY
		David R. Emery
		Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Power, Inc. (the “Company”) on Form 10-Q for the period ended June 30, 2017 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Richard W. Kinzley, Senior 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:	August 8, 2017
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - shares	6 Months Ended
	Jun. 30, 2017	Jul. 31, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS POWER INC
Entity Central Index Key	0000012400
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Document Fiscal Year End Focus	2017
Document Fiscal Period Focus	Q2
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

XML

Condensed Statements of Income and Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Statement [Abstract]
Revenue	$ 66,053	$ 62,019	$ 139,847	$ 130,661
Operating expenses:
Fuel and purchased power	18,612	16,224	41,761	36,954
Operations and maintenance	18,888	16,906	35,842	33,937
Depreciation and amortization	8,831	8,204	17,525	16,816
Taxes - property	2,010	1,749	3,631	3,238
Total operating expenses	48,341	43,083	98,759	90,945
Operating income	17,712	18,936	41,088	39,716
Other income (expense):
Interest expense	(5,635)	(5,414)	(11,390)	(10,868)
AFUDC - borrowed	392	298	584	521
Interest income	243	292	369	494
AFUDC - equity	717	566	1,188	989
Other income (expense), net	(69)	(47)	(122)	27
Total other income (expense)	(4,352)	(4,305)	(9,371)	(8,837)
Income before income taxes	13,360	14,631	31,717	30,879
Income tax expense	(4,073)	(4,825)	(9,860)	(9,887)
Net income	9,287	9,806	21,857	20,992
Other comprehensive income (loss):
Reclassification adjustments of cash flow hedges settled and included in net income (net of tax (expense) benefit of $(5) and $(5) for the three months ended June 30, 2017 and 2016, and $(11) and $(11) for the six months ended June 30, 2017 and 2016, respectively)	11	11	21	21
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(7) for the three months ended June 30, 2017 and 2016 and $(15) and $(14) for the six months ended June 30, 2017 and 2016, respectively)	14	13	28	27
Other comprehensive income	25	24	49	48
Comprehensive income	$ 9,312	$ 9,830	$ 21,906	$ 21,040

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Condensed Statements of Income and Comprehensive Income OCI Parenthetical - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Income Statement [Abstract]
Reclassification adjustment of cash flow hedges settled, (tax) benefit	$ (5)	$ (5)	$ (11)	$ (11)
Reclassification adjustment of benefit and other postretirement plans included in net income, (tax) benefit	$ (8)	$ (7)	$ (15)	$ (14)

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Condensed Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 1,156	$ 234
Receivables - customers, net	26,702	30,614
Receivables - affiliates	6,596	9,526
Other receivables, net	334	351
Money pool notes receivable, net	12,471	28,409
Materials, supplies and fuel	22,989	22,389
Regulatory assets, current	21,453	18,119
Other, current assets	3,857	3,876
Total current assets	95,558	113,518
Investments	4,849	4,841
Property, plant and equipment	1,280,757	1,236,387
Less accumulated depreciation and amortization	(348,258)	(338,828)
Total property, plant and equipment, net	932,499	897,559
Other assets:
Regulatory assets, non-current	71,449	74,015
Other, non-current assets	3,586	3,816
Total other assets	75,035	77,831
TOTAL ASSETS	1,107,941	1,093,749
Current liabilities:
Accounts payable	15,842	14,158
Accounts payable - affiliates	23,745	31,799
Accrued liabilities	46,744	37,436
Regulatory liabilities, current	825	84
Total current liabilities	87,156	83,477
Long-term debt	339,825	339,756
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	214,539	211,443
Regulatory liabilities, non-current	54,818	53,866
Benefit plan liabilities	19,645	19,544
Other, non-current liabilities	1,390	1,001
Total deferred credits and other liabilities	290,392	285,854
Commitments and contingencies (Notes 4, 5 and 8)
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	328,790	322,933
Accumulated other comprehensive loss	(1,213)	(1,262)
Total stockholder’s equity	390,568	384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 1,107,941	$ 1,093,749

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Balance Sheet Parentheticals - $ / shares	Jun. 30, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1
Common Stock, Shares authorized	50,000,000	50,000,000
Common Stock, Shares Issued	23,416,396	23,416,396

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Condensed Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating activities:
Net income	$ 21,857	$ 20,992
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	17,525	16,816
Deferred income tax	1,605	18,009
Employee benefits	408	886
AFUDC - equity	(1,188)	(989)
Other adjustments, net	408	(236)
Change in operating assets and liabilities -
Accounts receivable and other current assets	7,188	3,234
Accounts payable and other current liabilities	(3,486)	(11,538)
Regulatory assets - current	(315)	(7,026)
Regulatory liabilities - current	741	0
Contributions to defined benefit pension plan	0	(820)
Other operating activities, net	380	168
Net cash provided by (used in) operating activities	45,123	39,496
Investing activities:
Property, plant and equipment additions	(44,142)	(35,153)
Change in money pool notes receivable, net	(62)	(4,286)
Other investing activities	3	(67)
Net cash provided by (used in) investing activities	(44,201)	(39,506)
Financing activities:
Net cash provided by (used in) financing activities	0	0
Net change in cash and cash equivalents	922	(10)
Cash and cash equivalents, beginning of period	234	297
Cash and cash equivalents, end of period	$ 1,156	$ 287

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Management's Statement:

6 Months Ended

Jun. 30, 2017

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 2016 Annual Report on Form 10-K filed with the SEC.

The information furnished in the accompanying condensed financial statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2017, December 31, 2016 and June 30, 2016 financial information and are of a normal recurring nature. The results of operations for the three and six months ended June 30, 2017 and June 30, 2016, and our financial condition as of June 30, 2017 and December 31, 2016 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Revisions

Certain revisions have been made to prior year’s financial information to conform to the current year presentation.

We revised our presentation of cash and certain cash transactions processed on behalf of affiliates as of December 31, 2016.  We have banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Cash collected or disbursed on behalf of affiliates is presented as Receivables - affiliates or Accounts payable - affiliates. Prior year amounts were corrected to conform to the current year presentation, which decreased cash and cash equivalents by $19 million as of June 30, 2016. It also decreased net cash flows provided by operations by $12 million for the six months ended June 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of June 30, 2016 and to the Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued and Adopted Accounting Standards

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures and monitor utility industry implementation discussions and guidance. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term greater than 12 months, whereas today only financing type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted.

We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, pole attachments and other industry-related areas. We also expect to implement changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases.

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. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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Accounts Receivable and Allowance for Doubtful Accounts:

6 Months Ended

Jun. 30, 2017

Accounts Receivable, Net [Abstract]

Accounts Receivable and Allowance for Doubtful Accounts

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:

	June 30, 2017			December 31, 2016
Accounts receivable trade	$	15,731		$	16,972
Unbilled revenues	11,137			13,799
Allowance for doubtful accounts	(166		)	(157		)
Receivables - customers, net	$	26,702		$	30,614

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Regulatory Accounting:

6 Months Ended

Jun. 30, 2017

Regulated Operations [Abstract]

Regulatory Accounting

REGULATORY ACCOUNTING

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)	June 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,674	$	1,815
Deferred taxes on AFUDC (b)	45	9,913		9,367
Employee benefit plans(c)	12	20,100		20,100
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	20,397		23,016
Deferred taxes on flow through accounting (a)	35	13,464		12,545
Decommissioning costs, net of amortization(d)	6	11,201		12,456
Other regulatory assets (a)(d)	6	16,153		12,835
Total regulatory assets		$	92,902	$	92,134

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	42,514	$	41,541
Employee benefit plan costs and related deferred taxes (c)	12	12,304		12,304
Other regulatory liabilities	13	825		105
Total regulatory liabilities		$	55,643	$	53,950

____________________

(a) We are allowed a recovery 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 or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million will be amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately$2.7 million.

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Related Party Transactions:

6 Months Ended

Jun. 30, 2017

Related Party Transactions [Abstract]

Related-Party Transactions

RELATED-PARTY TRANSACTIONS

Receivables and Payables

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

	June 30, 2017		December 31, 2016
Receivables - affiliates	$	6,596	$	9,526
Accounts payable - affiliates	$	23,745	$	31,799

Money Pool Notes Receivable and Notes Payable

We have entered into a Utility Money Pool Agreement (the “Agreement”) with BHC, Black Hills Service Company and the utility companies conducting business as 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 external 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 June 30, 2017, the average cost of borrowing under the Utility Money Pool was 1.61%.

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

	June 30, 2017		December 31, 2016
Money pool notes receivable, net	$	12,471	$	28,409

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Net interest income (expense)	$	90	$	290	$	216	$	568

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	625	$	648	$	1,505	$	1,309
Rent from electric properties	$	935	$	1,375	$	1,870	$	2,588
Fuel and purchased power:
Purchases of coal from WRDC	$	3,052	$	3,357	$	7,332	$	8,153
Purchase of excess energy from Cheyenne Light	$	76	$	53	$	116	$	108
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	369	$	353	$	975	$	1,017
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	637	$	602	$	1,656	$	1,729
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	198	$	200
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,109	$	6,177	$	13,720	$	12,898

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Employee Benefit Plans:

6 Months Ended

Jun. 30, 2017

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

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	136		$	151		$	272		$	302
Interest cost	585			625			1,170			1,250
Expected return on plan assets	(897		)	(908		)	(1,794		)	(1,816		)
Prior service cost	11			11			22			22
Net loss (gain)	307			499			614			998
Net periodic benefit cost	$	142		$	378		$	284		$	756

Defined Benefit Postretirement Healthcare Plan

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	51		$	51		$	103		$	102
Interest cost	44			47			88			94
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	11		$	14		$	23		$	28

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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Interest cost	$	29	$	30	$	58	$	60
Net loss (gain)	21		21		43		42
Net periodic benefit cost	$	50	$	51	$	101	$	102

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust accounts. On July 24, 2017, we made contributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. Contributions to the Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands):

	Contributions Six Ended June 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	—	$	1,834	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	271	$	271	$	565
Supplemental Non-qualified Defined Benefit Plans	$	124	$	124	$	246

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Fair Value of Financial Instruments:

6 Months Ended

Jun. 30, 2017

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 2016 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:

	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	1,156	$	1,156	$	234	$	234
Long-term debt, net of deferred financing costs (b)	$	339,825	$	434,228	$	339,756	$	410,466

_________________

(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 based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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Supplemental Disclosure of Cash Flow Information:

6 Months Ended

Jun. 30, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Six months ended June 30,	2017			2016
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,495		$	5,355
Non-cash (decrease) to money pool notes receivable, net	$	(16,000	)	$	(24,500	)
Non-cash dividend to Parent	$	16,000		$	24,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,786	)	$	(10,547	)

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Commitment and Contingencies:

6 Months Ended

Jun. 30, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

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 2016 Annual Report on Form 10-K.

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Management's Statement: (Policies)

6 Months Ended

Jun. 30, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Revisions

Revisions

Certain revisions have been made to prior year’s financial information to conform to the current year presentation.

We revised our presentation of cash and certain cash transactions processed on behalf of affiliates as of December 31, 2016.  We have banking arrangements at certain financial institutions whereby if required, payments of one account are cleared with cash from other accounts at the same financial institution; therefore, book overdrafts are presented on a combined basis by bank as cash and cash equivalents. Cash collected or disbursed on behalf of affiliates is presented as Receivables - affiliates or Accounts payable - affiliates. Prior year amounts were corrected to conform to the current year presentation, which decreased cash and cash equivalents by $19 million as of June 30, 2016. It also decreased net cash flows provided by operations by $12 million for the six months ended June 30, 2016. We assessed the materiality of these changes, taking into account quantitative and qualitative factors, and determined them to be immaterial to the balance sheet as of June 30, 2016 and to the Statements of Cash Flows for the six months ended June 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued and Adopted Accounting Standards

Recently Issued and Adopted Accounting Standards

Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We continue to assess the impact of this new standard on our financial statements and disclosures and monitor utility industry implementation discussions and guidance. The presentation changes required for net periodic pension and post-retirement costs will result in offsetting changes to Operating income and Other income and are not expected to be material. We will implement this standard effective January 1, 2018.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items including but not limited to debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017.We will use the retrospective transition method to adopt this standard with fiscal years beginning after December 15, 2017. This standard will not have a material impact on our financial position, results of operations or cash flows.

Leases, ASU 2016-02

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases. This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for all leases with a term greater than 12 months, whereas today only financing type lease liabilities (capital leases) are recognized on the balance sheet. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The ASU does not significantly change the lessees’ recognition, measurement and presentation of expenses and cash flows from the previous accounting standard. Lessors’ accounting under the ASU is largely unchanged from the previous accounting standard. The ASU expands the disclosure requirements of lease arrangements. Lessees and lessors will use a modified retrospective transition approach, which requires application of the new guidance at the beginning of the earliest comparative period presented in the year of adoption. The guidance is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted.

We currently expect to adopt this standard on January 1, 2019. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and right of ways, pipeline laterals, purchase power agreements, pole attachments and other industry-related areas. We also expect to implement changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases.

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. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017 with early adoption on January 1, 2017 permitted. Entities will have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption.

We currently expect to implement the standard on a modified retrospective basis effective January 1, 2018. We continue to actively assess all of our sources of revenue to determine the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. Our evaluation includes identifying revenue streams by like contracts to allow for ease of implementation. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity or gas delivered in that period. Therefore, we do not expect there will be a significant shift in the timing or pattern of revenue recognition for regulated tariff based sales. The evaluation of other revenue streams is ongoing, including our non-regulated revenues and those tied to longer term contractual commitments. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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Accounts Receivable and Allowance for Doubtful Accounts: (Tables)

6 Months Ended

Jun. 30, 2017

Accounts Receivable, Net [Abstract]

Schedule of Accounts Receivable

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

	June 30, 2017			December 31, 2016
Accounts receivable trade	$	15,731		$	16,972
Unbilled revenues	11,137			13,799
Allowance for doubtful accounts	(166		)	(157		)
Receivables - customers, net	$	26,702		$	30,614

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Regulatory Accounting: (Tables)

6 Months Ended

Jun. 30, 2017

Regulated Operations [Abstract]

Schedule of Regulatory Assets

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

	Recovery/Amortization Period (in years)	June 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,674	$	1,815
Deferred taxes on AFUDC (b)	45	9,913		9,367
Employee benefit plans(c)	12	20,100		20,100
Deferred energy and fuel cost adjustments - current (a)	Less than 1 year	20,397		23,016
Deferred taxes on flow through accounting (a)	35	13,464		12,545
Decommissioning costs, net of amortization(d)	6	11,201		12,456
Other regulatory assets (a)(d)	6	16,153		12,835
Total regulatory assets		$	92,902	$	92,134

Schedule of Regulatory Liabilities

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	42,514	$	41,541
Employee benefit plan costs and related deferred taxes (c)	12	12,304		12,304
Other regulatory liabilities	13	825		105
Total regulatory liabilities		$	55,643	$	53,950

____________________

(a) We are allowed a recovery 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 or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base, respectively.

(d) In accordance with a settlement agreement approved by the SDPUC on June 16, 2017, the amortization of South Dakota Electric’s decommissioning costs of approximately $11 million, vegetation management costs of approximately $14 million, and Winter Storm Atlas costs of approximately $2.0 million will be amortized over 6 years, effective July 1, 2017. Decommissioning costs and Winter Storm Atlas costs were previously amortized over a 10 year period ending September 30, 2024. The vegetation management costs were previously unamortized. The change in amortization periods for these costs will increase annual amortization expense by approximately$2.7 million.

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Related Party Transactions: (Tables)

6 Months Ended

Jun. 30, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Accounts Receivable and Payable

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

	June 30, 2017		December 31, 2016
Receivables - affiliates	$	6,596	$	9,526
Accounts payable - affiliates	$	23,745	$	31,799

Schedule of Related Party Notes

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

	June 30, 2017		December 31, 2016
Money pool notes receivable, net	$	12,471	$	28,409

Schedule of Related Party Interest Income Expense

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Net interest income (expense)	$	90	$	290	$	216	$	568

Schedule of Revenues and Purchases from Related Parties

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	625	$	648	$	1,505	$	1,309
Rent from electric properties	$	935	$	1,375	$	1,870	$	2,588
Fuel and purchased power:
Purchases of coal from WRDC	$	3,052	$	3,357	$	7,332	$	8,153
Purchase of excess energy from Cheyenne Light	$	76	$	53	$	116	$	108
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	369	$	353	$	975	$	1,017
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	637	$	602	$	1,656	$	1,729
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	198	$	200
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,109	$	6,177	$	13,720	$	12,898

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Employee Benefit Plans: (Tables)

6 Months Ended

Jun. 30, 2017

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

Schedule of Net Benefit Costs

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	136		$	151		$	272		$	302
Interest cost	585			625			1,170			1,250
Expected return on plan assets	(897		)	(908		)	(1,794		)	(1,816		)
Prior service cost	11			11			22			22
Net loss (gain)	307			499			614			998
Net periodic benefit cost	$	142		$	378		$	284		$	756

Defined Benefit Postretirement Healthcare Plan

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Service cost	$	51		$	51		$	103		$	102
Interest cost	44			47			88			94
Prior service cost (benefit)	(84		)	(84		)	(168		)	(168		)
Net periodic benefit cost	$	11		$	14		$	23		$	28

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 June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Interest cost	$	29	$	30	$	58	$	60
Net loss (gain)	21		21		43		42
Net periodic benefit cost	$	50	$	51	$	101	$	102

Schedule of Defined Benefit Plans Contributions

Contributions made for 2017 and anticipated contributions for 2017 and 2018 are as follows (in thousands):

	Contributions Six Ended June 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	—	$	1,834	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	271	$	271	$	565
Supplemental Non-qualified Defined Benefit Plans	$	124	$	124	$	246

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Fair Value of Financial Instruments: (Tables)

6 Months Ended

Jun. 30, 2017

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:

	June 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	1,156	$	1,156	$	234	$	234
Long-term debt, net of deferred financing costs (b)	$	339,825	$	434,228	$	339,756	$	410,466

_________________

(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 based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy.

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Supplemental Disclosure of Cash Flow Information: (Tables)

6 Months Ended

Jun. 30, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Six months ended June 30,	2017			2016
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,495		$	5,355
Non-cash (decrease) to money pool notes receivable, net	$	(16,000	)	$	(24,500	)
Non-cash dividend to Parent	$	16,000		$	24,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(10,786	)	$	(10,547	)

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Management's Statement: Revision (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Prior Period Adjustments Restatement [Line Items]
Decreased net cash flows provided by operations	$ 45,123	$ 39,496
Restatement Adjustment
Prior Period Adjustments Restatement [Line Items]
Decreased net cash flows provided by operations		(12,000)
Cash and Cash Equivalents
Prior Period Adjustments Restatement [Line Items]
Prior Period Reclassification Adjustment		$ (19,000)

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Accounts Receivable and Allowance for Doubtful Accounts: (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Accounts Receivable, Net [Abstract]
Accounts receivable trade	$ 15,731	$ 16,972
Unbilled revenues	11,137	13,799
Allowance for doubtful accounts	(166)	(157)
Receivables - customers, net	$ 26,702	$ 30,614

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Regulatory Accounting: Regulatory Assets (Details) - USD ($) $ in Thousands		6 Months Ended
	Jul. 01, 2017	Jun. 30, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Regulatory Assets		$ 92,902	$ 92,134
Subsequent Event
Regulatory Assets [Line Items]
Amortization of Regulatory Asset	$ 2,700
Loss on Reacquired Debt
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)		8 years
Regulatory Assets		$ 1,674	1,815
Allowance For Funds Used During Construction
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)		45 years
Regulatory Assets		$ 9,913	9,367
Pension and Other Postretirement Plans Costs
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)		12 years
Regulatory Assets		$ 20,100	20,100
Deferred Fuel Costs
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)		1 year
Regulatory Assets		$ 20,397	23,016
Flow Through Accounting
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)		35 years
Regulatory Assets		$ 13,464	12,545
Environmental Restoration Costs
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)		6 years
Regulatory Assets		$ 11,201	12,456
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC)
Regulatory Assets [Line Items]
Regulatory Assets		$ 11,000
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC) | Subsequent Event
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)	6 years
Other Regulatory Assets
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)		6 years
Regulatory Assets		$ 16,153	$ 12,835
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC)
Regulatory Assets [Line Items]
Regulatory Assets		14,000
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Subsequent Event
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)	6 years
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Winter Storm Atlas
Regulatory Assets [Line Items]
Regulatory Assets		$ 2,000
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Winter Storm Atlas | Subsequent Event
Regulatory Assets [Line Items]
Recovery/Amortization Period (in years)	6 years

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Regulatory Accounting: Regulatory Liabilities (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 55,643	$ 53,950
Cost Of Removal
Regulatory Liabilities [Line Items]
Recovery/Amortization Period (in years)	61 years
Regulatory Liabilities	$ 42,514	41,541
Pension and Other Postretirement Plans Costs
Regulatory Liabilities [Line Items]
Recovery/Amortization Period (in years)	12 years
Regulatory Liabilities	$ 12,304	12,304
Other Regulatory Liabilities
Regulatory Liabilities [Line Items]
Recovery/Amortization Period (in years)	13 years
Regulatory Liabilities	$ 825	$ 105

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Regulatory Accounting: Recovery Period (Details)		6 Months Ended
	Jul. 01, 2017	Jun. 30, 2017
Deferred Fuel Costs
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)		1 year
Environmental Restoration Costs
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)		6 years
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC) | Subsequent Event
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)	6 years
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC) | Scenario, Previously Reported
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)		10 years
Other Regulatory Assets
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)		6 years
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Subsequent Event
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)	6 years
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Subsequent Event | Winter Storm Atlas
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)	6 years
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | Scenario, Previously Reported | Winter Storm Atlas
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)		10 years

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Related Party Transactions: (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Related Party Transaction [Line Items]
Receivables - affiliates	$ 6,596		$ 6,596		$ 9,526
Accounts payable - affiliates	23,745		$ 23,745		31,799
Related Party Transaction, Utility Money Pool Interest Rate			1.61%
Money pool notes receivable, net	12,471		$ 12,471		$ 28,409
Parent
Related Party Transaction [Line Items]
Commitment fee percentage			1.00%
Utility Money Pool
Related Party Transaction [Line Items]
Net interest income (expense)	90	$ 290	$ 216	$ 568
Subsidiary of Common Parent | Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings
Related Party Transaction [Line Items]
Fuel and purchased power	7,109	6,177	13,720	12,898
Subsidiary of Common Parent | Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation
Related Party Transaction [Line Items]
Fuel and purchased power	99	100	198	200
Subsidiary of Common Parent | Purchases of coal from WRDC
Related Party Transaction [Line Items]
Fuel and purchased power	3,052	3,357	7,332	8,153
Subsidiary of Common Parent | Purchase of excess energy from Cheyenne Light
Related Party Transaction [Line Items]
Fuel and purchased power	76	53	116	108
Subsidiary of Common Parent | Purchase of renewable wind energy from Cheyenne Light - Happy Jack
Related Party Transaction [Line Items]
Fuel and purchased power	369	353	975	1,017
Subsidiary of Common Parent | Purchase of renewable wind energy from Cheyenne Light - Silver Sage
Related Party Transaction [Line Items]
Fuel and purchased power	637	602	1,656	1,729
Subsidiary of Common Parent | Energy sold to Cheyenne Light
Related Party Transaction [Line Items]
Revenue	625	648	1,505	1,309
Subsidiary of Common Parent | Rent from electric properties
Related Party Transaction [Line Items]
Revenue	$ 935	$ 1,375	$ 1,870	$ 2,588

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Employee Benefit Plans: (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
	Jul. 24, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Defined Benefit Pension Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		$ 136	$ 151	$ 272	$ 302
Interest cost		585	625	1,170	1,250
Expected return on plan assets		(897)	(908)	(1,794)	(1,816)
Prior service cost (benefit)		11	11	22	22
Net loss (gain)		307	499	614	998
Net periodic benefit cost		142	378	284	756
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer				0
Remaining Anticipated Contributions for Current Year				1,834
Anticipated Contributions for Next Year				1,834
Defined Benefit Pension Plan | Subsequent Event
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer	$ 1,800
Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost		51	51	103	102
Interest cost		44	47	88	94
Prior service cost (benefit)		(84)	(84)	(168)	(168)
Net periodic benefit cost		11	14	23	28
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer				271
Remaining Anticipated Contributions for Current Year				271
Anticipated Contributions for Next Year				565
Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Interest cost		29	30	58	60
Net loss (gain)		21	21	43	42
Net periodic benefit cost		$ 50	$ 51	101	$ 102
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer				124
Remaining Anticipated Contributions for Current Year				124
Anticipated Contributions for Next Year				$ 246

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Fair Value of Financial Instruments: (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	$ 1,156	$ 234	$ 287	$ 297
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	1,156	234
Long-term debt, including current maturities, carrying amount	339,825	339,756
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, fair value	1,156	234
Long-term debt, including current maturities, fair value	$ 434,228	$ 410,466

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Supplemental Disclosure of Cash Flow Information: (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Noncash Investing and Financing Items [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 10,495	$ 5,355
Interest and Income Taxes Paid Net [Abstract]
Interest (net of amounts capitalized)	(10,786)	(10,547)
Subsidiary of Common Parent
Noncash Investing and Financing Items [Abstract]
Non-cash (decrease) to money pool notes receivable, net	(16,000)	(24,500)
Parent
Noncash Investing and Financing Items [Abstract]
Non-cash dividend to Parent	$ 16,000	$ 24,500