10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 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 October 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 Nine Months Ended September 30, 2017 and 2016
	Condensed Balance Sheets - unaudited	5
	September 30, 2017 and December 31, 2016
	Condensed Statements of Cash Flows - unaudited	7
	Nine Months Ended September 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

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
SourceGas	SourceGas Holdings LLC and its subsidiaries, a gas utility owned by funds managed by Alinda Capital Partners and GE Energy Financial Services, a unit of General Electric Co. (NYSE:GE) that was acquired by BHC on February 12, 2016, and is now named Black Hills Gas Holdings, LLC (doing business as Black Hills Energy)
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
Wyoming Electric	Includes Cheyenne Light’s electric utility operations

3

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

	Three Months Ended September 30,						Nine Months Ended September 30,
(unaudited)	2017			2016			2017			2016
	(in thousands)
Revenue	$	73,938		$	66,728		$	213,785		$	197,389
Operating expenses:
Fuel and purchased power	22,843			18,421			64,604			55,375
Operations and maintenance	16,747			15,601			52,589			49,538
Depreciation and amortization	9,053			8,547			26,578			25,363
Taxes - property	1,597			1,749			5,228			4,987
Total operating expenses	50,240			44,318			148,999			135,263
Operating income	23,698			22,410			64,786			62,126
Other income (expense):
Interest expense	(5,483		)	(5,454		)	(16,873		)	(16,322		)
AFUDC - borrowed	369			319			953			840
Interest income	335			510			704			1,004
AFUDC - equity	676			606			1,864			1,595
Other income (expense), net	3			48			(119		)	75
Total other income (expense)	(4,100		)	(3,971		)	(13,471		)	(12,808		)
Income before income taxes	19,598			18,439			51,315			49,318
Income tax expense	(5,772		)	(6,429		)	(15,632		)	(16,316		)
Net income	13,826			12,010			35,683			33,002
Other comprehensive income (loss):
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2017 and 2016, and $(17) and $(17) for the nine months ended September 30, 2017 and 2016, respectively)	10			10			31			31
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(8) for the three months ended September 30, 2017 and 2016 and $(23) and $(21) for the nine months ended September 30, 2017 and 2016, respectively)	14			14			42			41
Other comprehensive income	24			24			73			72
Comprehensive income	$	13,850		$	12,034		$	35,756		$	33,074

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

4

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)	September 30, 2017			December 31, 2016
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	1,171		$	234
Receivables - customers, net	27,579			30,614
Receivables - affiliates	5,498			9,526
Other receivables, net	335			351
Money pool notes receivable, net	8,881			28,409
Materials, supplies and fuel	23,622			22,389
Regulatory assets, current	18,819			18,119
Other, current assets	3,432			3,876
Total current assets	89,337			113,518
Investments	4,902			4,841
Property, plant and equipment	1,298,855			1,236,387
Less accumulated depreciation and amortization	(354,788		)	(338,828		)
Total property, plant and equipment, net	944,067			897,559
Other assets:
Regulatory assets, non-current	73,178			74,015
Other, non-current assets	3,545			3,816
Total other assets	76,723			77,831
TOTAL ASSETS	$	1,115,029		$	1,093,749

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

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BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)	September 30, 2017			December 31, 2016
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	14,701		$	14,158
Accounts payable - affiliates	26,828			31,799
Accrued liabilities	50,337			37,436
Regulatory liabilities, current	825			84
Total current liabilities	92,691			83,477
Long-term debt	339,860			339,756
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	220,857			211,443
Regulatory liabilities, non-current	55,822			53,866
Benefit plan liabilities	15,721			19,544
Other, non-current liabilities	1,393			1,001
Total deferred credits and other liabilities	293,793			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	326,883			322,933
Accumulated other comprehensive loss	(1,189		)	(1,262		)
Total stockholder’s equity	388,685			384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,115,029		$	1,093,749

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

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BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)	Nine Months Ended September 30,
	2017			2016
	(in thousands)
Operating activities:
Net income	$	35,683		$	33,002
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	26,578			25,363
Deferred income tax	6,188			22,267
Employee benefits	613			1,327
AFUDC	(2,817		)	(1,595		)
Other adjustments, net	2,298			118
Change in operating assets and liabilities -
Accounts receivable and other current assets	6,567			5,499
Accounts payable and other current liabilities	3,077			(501		)
Regulatory assets - current	1,543			(4,029		)
Contributions to defined benefit pension plan	(4,000		)	(820		)
Other operating activities, net	(1,097		)	(3,994		)
Net cash provided by (used in) operating activities	74,633			76,637
Investing activities:
Property, plant and equipment additions	(61,537		)	(65,062		)
Change in money pool notes receivable, net	(12,472		)	(10,966		)
Other investing activities	313			(81		)
Net cash provided by (used in) investing activities	(73,696		)	(76,109		)
Financing activities:
Net cash provided by (used in) financing activities	—			—
Net change in cash and cash equivalents	937			528
Cash and cash equivalents, beginning of period	234			297
Cash and cash equivalents, end of period	$	1,171		$	825

See Note 7 for supplemental cash flow information.

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

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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 September 30, 2017, December 31, 2016 and September 30, 2016 financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, 2017 and September 30, 2016, and our financial condition as of September 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 $9.4 million as of September 30, 2016. It also decreased net cash flows provided by operations by $2.2 million for the nine months ended September 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 September 30, 2016 and to the Statements of Cash Flows for the nine months ended September 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued Accounting Standards

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 have substantially completed our assessment of all sources of revenue and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity delivered during 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. We

8

also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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 period 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 we monitor regulated utility industry implementation discussions and guidance. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. 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, and other industry-related areas. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.

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:

	September 30, 2017			December 31, 2016
Accounts receivable trade	$	17,356		$	16,972
Unbilled revenues	10,348			13,799
Allowance for doubtful accounts	(125		)	(157		)
Receivables - customers, net	$	27,579		$	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:

	Maximum Amortization (in years)	September 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,604	$	1,815
Deferred taxes on AFUDC (b)	45	10,192		9,367
Employee benefit plans(c)	12	20,180		20,100
Deferred energy and fuel cost adjustments - current (a)	1	13,754		18,119
Deferred gas cost adjustments (a) (e)	1	5,324		4,897
Deferred taxes on flow through accounting (a)	35	14,906		12,545
Decommissioning costs, net of amortization(d)	6	10,766		12,456
Other regulatory assets (a)(d)	6	15,271		12,835
Total regulatory assets		$	91,997	$	92,134

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	43,518	$	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		$	56,647	$	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.

(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 are being 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.

(e) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. We file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

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(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:

	September 30, 2017		December 31, 2016
Receivables - affiliates	$	5,498	$	9,526
Accounts payable - affiliates	$	26,828	$	31,799

Money Pool Notes Receivable and Notes Payable

On September 1, 2017, the Utility Money Pool was transferred from Black Hills Power to our affiliate Black Hills Utility Holdings. This transfer reduced our cash by $0.7 million, reduced our Money pool notes receivable, net by $1.0 million and increased our Retained earnings by $0.3 million.

We will continue to participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool 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 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 September 30, 2017, the average cost of borrowing under the Utility Money Pool was 1.66%.

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

	September 30, 2017		December 31, 2016
Money pool notes receivable, net	$	8,881	$	28,409

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Net interest income (expense)	$	53	$	277	$	269	$	845

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	361	$	599	$	1,866	$	1,908
Rent from electric properties	$	935	$	1,229	$	2,805	$	3,817
Fuel and purchased power:
Purchases of coal from WRDC	$	4,054	$	4,122	$	11,386	$	12,275
Purchase of excess energy from Cheyenne Light	$	208	$	64	$	324	$	172
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	199	$	312	$	1,174	$	1,329
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	351	$	547	$	2,007	$	2,276
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	297	$	300
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,626	$	6,257	$	20,346	$	19,155

(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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Service cost	$	137		$	151		$	409		$	453
Interest cost	585			625			1,755			1,875
Expected return on plan assets	(898		)	(908		)	(2,692		)	(2,724		)
Prior service cost	10			11			32			33
Net loss (gain)	308			498			922			1,496
Net periodic benefit cost	$	142		$	377		$	426		$	1,133

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Service cost	$	52		$	51		$	155		$	153
Interest cost	44			47			132			141
Prior service cost (benefit)	(84		)	(84		)	(252		)	(252		)
Net periodic benefit cost	$	12		$	14		$	35		$	42

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Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Interest cost	$	29	$	30	$	87	$	90
Net loss (gain)	22		20		65		62
Net periodic benefit cost	$	51	$	50	$	152	$	152

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 24, 2017, we made contributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. On September 15, 2017, we made an additional contribution of approximately $2.2 million to reduce Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. 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 Nine Months Ended September 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	4,000	$	—	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	406	$	135	$	565
Supplemental Non-qualified Defined Benefit Plans	$	185	$	62	$	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:

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	1,171	$	1,171	$	234	$	234
Long-term debt, including current maturities (b) (c)	$	339,860	$	439,973	$	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.

(c) Carrying amount of long-term debt is net of deferred financing costs.

13

(7) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine months ended September 30,	2017			2016
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,242		$	5,565
Non-cash (decrease) to money pool notes receivable, net	$	(32,000	)	$	(36,500	)
Non-cash dividend to Parent	$	32,000		$	36,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(12,838	)	$	(13,486	)

(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.

Tax Matters - Potential Corporate Tax Reform

President Trump and Congressional Republicans have stated that one of their top priorities is enactment of comprehensive tax reform.  On November 2, 2017, the House Ways and Means Committee released its tax reform bill. Significant uncertainty exists as to the ultimate legislation that will be enacted into law.  We are evaluating the proposed legislation; any impact on our future results of operations, financial position and cash flows as a result of the potential changes cannot yet be determined and such changes could be material.

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 September 30,									Nine Months Ended September 30,
	2017			2016			Variance			2017			2016			Variance
	(in thousands)
Revenue	$	73,938		$	66,728		$	7,210		$	213,785		$	197,389		$	16,396
Fuel and purchased power	22,843			18,421			4,422			64,604			55,375			9,229
Gross margin	51,095			48,307			2,788			149,181			142,014			7,167
Operating expenses	27,397			25,897			1,500			84,395			79,888			4,507
Operating income	23,698			22,410			1,288			64,786			62,126			2,660
Interest income (expense), net	(4,779		)	(4,625		)	(154		)	(15,216		)	(14,478		)	(738		)
Other income (expense), net	679			654			25			1,745			1,670			75
Income tax expense	(5,772		)	(6,429		)	657			(15,632		)	(16,316		)	684
Net income	$	13,826		$	12,010		$	1,816		$	35,683		$	33,002		$	2,681

Three Months Ended September 30, 2017 Compared to Three Months Ended September 30, 2016. Net income was $14 million compared to $12 million for the same period in the prior year primarily due to the following:

Gross marginincreased over the prior year reflecting a $2.8 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling degree days were offset by lower usage per customer and lower commercial and industrial demand. Cooling degree days were 11% higher than normal in the current year compared to 18% lower 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, increased amortization expenses as a result of the SDPUC settlement, and increased maintenance costs from outages.

Interest expense, net and other income, net were 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.

Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016. Net income was $36 million compared to $33 million for the same period in the prior year primarily due to the following:

Gross marginincreased over the prior year reflecting a $4.0 million increase in rider revenues primarily related to transmission investment recovery. Higher cooling degree days were slightly offset by lower usage per customer and lower commercial and industrial demand. Cooling degree days were 12% higher than normal in the current year compared to 3% lower 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, increased amortization expenses as a result of the SDPUC settlement, and increased maintenance costs from higher outages.

Interest expense, net and other income, net were 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.

16

	Electric Revenue by Customer Type
	Three Months Ended September 30,					Nine Months Ended September 30,
	(in thousands)
	2017		Percentage Change	2016		2017		Percentage Change	2016
Residential	$	18,020	3%	$	17,501	$	53,724	1%	$	53,057
Commercial	25,459		(1)%	25,714		72,608		(1)%	73,026
Industrial	8,149		(2)%	8,275		24,774		1%	24,540
Municipal	1,071		2%	1,053		2,849		—%	2,844
Total retail revenue	52,699		—%	52,543		153,955		—%	153,467
Contract wholesale (a)	8,048		75%	4,596		22,593		78%	12,717
Wholesale off-system (b)	4,787		20%	3,984		11,044		(2)%	11,304
Other revenue (c)	8,404		50%	5,605		26,193		32%	19,901
Total revenue	$	73,938	11%	$	66,728	$	213,785	8%	$	197,389

____________________

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

(b) Increase for three months ended September 30, 2017 was driven by higher commodity prices on similar MWh quantities sold. For the nine months ended September 30, 2017 higher commodity prices primarily offset lower MWh quantities sold.

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

	Megawatt Hours Sold by Customer Type
	Three Months Ended September 30,			Nine Months Ended September 30,
	2017	Percentage Change	2016	2017	Percentage Change	2016
Residential	129,616	5%	124,012	386,709	1%	381,616
Commercial	212,773	—%	213,276	582,899	(2)%	592,371
Industrial	109,745	—%	110,220	323,038	1%	320,861
Municipal	10,156	2%	9,927	25,865	—%	25,855
Total retail quantity sold	462,290	1%	457,435	1,318,511	—%	1,320,703
Contract wholesale (a)	185,723	197%	62,547	537,720	195%	182,087
Wholesale off-system (b)	130,825	2%	128,415	388,287	(12)%	438,852
Total quantity sold	778,838	20%	648,397	2,244,518	16%	1,941,642
Losses and company use (c)	56,447	36%	41,585	155,477	40%	111,437
Total energy	835,285	21%	689,982	2,399,995	17%	2,053,079

____________________

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

(b) Decrease in 2017 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 September 30,			Nine Months Ended September 30,
Generated -	2017	Percentage Change	2016	2017	Percentage Change	2016
Coal-fired	423,766	6%	401,231	1,101,291	4%	1,054,264
Natural Gas and Oil (a)	54,466	31%	41,654	75,840	(22)%	96,649
Total generated	478,232	8%	442,885	1,177,131	2%	1,150,913
Total purchased (b)	357,053	44%	247,097	1,222,864	36%	902,166
Total generated and purchased (b)	835,285	21%	689,982	2,399,995	17%	2,053,079

____________________

(a) Variances for the three and nine months ended September 30, 2017 compared to the same periods in the prior year are driven primarily by the ability to purchase excess generation in the open market at a lower or higher cost than to generate.

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

	Power Plant Availability
	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Coal-fired plants (a)	97.5	%	92.8	%	84.8	%	83.2	%
Other plants	93.7	%	97.7	%	97.0	%	98.4	%
Total availability	95.5	%	95.6	%	91.3	%	91.8	%

____________________

(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 September 30,						Nine Months Ended September 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	202	(10	)%	161	(23	)%	4,242	(5	)%	3,844	(13	)%
Cooling degree days	595	11	%	460	(18	)%	709	12	%	646	(3	)%

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 September 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 September 30, 2017. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of September 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 September 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: November 3, 2017

21

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, David R. Emery, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	November 3, 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:	November 3, 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 September 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:	November 3, 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 September 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:	November 3, 2017
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - shares	9 Months Ended
	Sep. 30, 2017	Oct. 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	Sep. 30, 2017
Amendment Flag	false
Document Fiscal Year End Focus	2017
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		23,416,396

XML

Condensed Statements of Income and Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement [Abstract]
Revenue	$ 73,938	$ 66,728	$ 213,785	$ 197,389
Operating expenses:
Fuel and purchased power	22,843	18,421	64,604	55,375
Operations and maintenance	16,747	15,601	52,589	49,538
Depreciation and amortization	9,053	8,547	26,578	25,363
Taxes - property	1,597	1,749	5,228	4,987
Total operating expenses	50,240	44,318	148,999	135,263
Operating income	23,698	22,410	64,786	62,126
Other income (expense):
Interest expense	(5,483)	(5,454)	(16,873)	(16,322)
AFUDC - borrowed	369	319	953	840
Interest income	335	510	704	1,004
AFUDC - equity	676	606	1,864	1,595
Other income (expense), net	3	48	(119)	75
Total other income (expense)	(4,100)	(3,971)	(13,471)	(12,808)
Income before income taxes	19,598	18,439	51,315	49,318
Income tax expense	(5,772)	(6,429)	(15,632)	(16,316)
Net income	13,826	12,010	35,683	33,002
Other comprehensive income (loss):
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax (expense) benefit of $(6) and $(6) for the three months ended September 30, 2017 and 2016, and $(17) and $(17) for the nine months ended September 30, 2017 and 2016, respectively)	10	10	31	31
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(8) and $(8) for the three months ended September 30, 2017 and 2016 and $(23) and $(21) for the nine months ended September 30, 2017 and 2016, respectively)	14	14	42	41
Other comprehensive income	24	24	73	72
Comprehensive income	$ 13,850	$ 12,034	$ 35,756	$ 33,074

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Condensed Statements of Income and Comprehensive Income OCI Parenthetical - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Income Statement [Abstract]
Reclassification adjustment of cash flow hedges settled, (tax) benefit	$ (6)	$ (6)	$ (17)	$ (17)
Reclassification adjustment of benefit and other postretirement plans included in net income, (tax) benefit	$ (8)	$ (8)	$ (23)	$ (21)

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Condensed Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 1,171	$ 234
Receivables - customers, net	27,579	30,614
Receivables - affiliates	5,498	9,526
Other receivables, net	335	351
Money pool notes receivable, net	8,881	28,409
Materials, supplies and fuel	23,622	22,389
Regulatory assets, current	18,819	18,119
Other, current assets	3,432	3,876
Total current assets	89,337	113,518
Investments	4,902	4,841
Property, plant and equipment	1,298,855	1,236,387
Less accumulated depreciation and amortization	(354,788)	(338,828)
Total property, plant and equipment, net	944,067	897,559
Other assets:
Regulatory assets, non-current	73,178	74,015
Other, non-current assets	3,545	3,816
Total other assets	76,723	77,831
TOTAL ASSETS	1,115,029	1,093,749
Current liabilities:
Accounts payable	14,701	14,158
Accounts payable - affiliates	26,828	31,799
Accrued liabilities	50,337	37,436
Regulatory liabilities, current	825	84
Total current liabilities	92,691	83,477
Long-term debt	339,860	339,756
Deferred credits and other liabilities:
Deferred income tax liability, net, non-current	220,857	211,443
Regulatory liabilities, non-current	55,822	53,866
Benefit plan liabilities	15,721	19,544
Other, non-current liabilities	1,393	1,001
Total deferred credits and other liabilities	293,793	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	326,883	322,933
Accumulated other comprehensive loss	(1,189)	(1,262)
Total stockholder’s equity	388,685	384,662
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 1,115,029	$ 1,093,749

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Condensed Balance Sheets Parenthetical - $ / shares	Sep. 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	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Operating activities:
Net income	$ 35,683	$ 33,002
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	26,578	25,363
Deferred income tax	6,188	22,267
Employee benefits	613	1,327
AFUDC	(2,817)	(1,595)
Other adjustments, net	2,298	118
Change in operating assets and liabilities -
Accounts receivable and other current assets	6,567	5,499
Accounts payable and other current liabilities	3,077	(501)
Regulatory assets - current	1,543	(4,029)
Contributions to defined benefit pension plan	(4,000)	(820)
Other operating activities, net	(1,097)	(3,994)
Net cash provided by (used in) operating activities	74,633	76,637
Investing activities:
Property, plant and equipment additions	(61,537)	(65,062)
Change in money pool notes receivable, net	(12,472)	(10,966)
Other investing activities	313	(81)
Net cash provided by (used in) investing activities	(73,696)	(76,109)
Financing activities:
Net cash provided by (used in) financing activities	0	0
Net change in cash and cash equivalents	937	528
Cash and cash equivalents, beginning of period	234	297
Cash and cash equivalents, end of period	$ 1,171	$ 825

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Management's Statement:

9 Months Ended

Sep. 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 September 30, 2017, December 31, 2016 and September 30, 2016 financial information and are of a normal recurring nature. The results of operations for the three and nine months ended September 30, 2017 and September 30, 2016, and our financial condition as of September 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 $9.4 million as of September 30, 2016. It also decreased net cash flows provided by operations by $2.2 million for the nine months ended September 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 September 30, 2016 and to the Statements of Cash Flows for the nine months ended September 30, 2016. There is no impact to the Statements of Income or Statements of Comprehensive Income (Loss) for any period reported.

Recently Issued Accounting Standards

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 have substantially completed our assessment of all sources of revenue and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity delivered during 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. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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 period 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 we monitor regulated utility industry implementation discussions and guidance. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. 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, and other industry-related areas. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.

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Accounts Receivable and Allowance for Doubtful Accounts:

9 Months Ended

Sep. 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:

	September 30, 2017			December 31, 2016
Accounts receivable trade	$	17,356		$	16,972
Unbilled revenues	10,348			13,799
Allowance for doubtful accounts	(125		)	(157		)
Receivables - customers, net	$	27,579		$	30,614

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Regulatory Accounting:

9 Months Ended

Sep. 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:

	Maximum Amortization (in years)	September 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,604	$	1,815
Deferred taxes on AFUDC (b)	45	10,192		9,367
Employee benefit plans(c)	12	20,180		20,100
Deferred energy and fuel cost adjustments - current (a)	1	13,754		18,119
Deferred gas cost adjustments (a) (e)	1	5,324		4,897
Deferred taxes on flow through accounting (a)	35	14,906		12,545
Decommissioning costs, net of amortization(d)	6	10,766		12,456
Other regulatory assets (a)(d)	6	15,271		12,835
Total regulatory assets		$	91,997	$	92,134

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	43,518	$	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		$	56,647	$	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.

(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 are being 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.

(e) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. We file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

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Related-Party Transactions:

9 Months Ended

Sep. 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:

	September 30, 2017		December 31, 2016
Receivables - affiliates	$	5,498	$	9,526
Accounts payable - affiliates	$	26,828	$	31,799

Money Pool Notes Receivable and Notes Payable

On September 1, 2017, the Utility Money Pool was transferred from Black Hills Power to our affiliate Black Hills Utility Holdings. This transfer reduced our cash by $0.7 million, reduced our Money pool notes receivable, net by $1.0 million and increased our Retained earnings by $0.3 million.

We will continue to participate in the Utility Money Pool Agreement (the Agreement). Under the Agreement, we may borrow from the pool; however the Agreement restricts the pool 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 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 September 30, 2017, the average cost of borrowing under the Utility Money Pool was 1.66%.

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

	September 30, 2017		December 31, 2016
Money pool notes receivable, net	$	8,881	$	28,409

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Net interest income (expense)	$	53	$	277	$	269	$	845

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	361	$	599	$	1,866	$	1,908
Rent from electric properties	$	935	$	1,229	$	2,805	$	3,817
Fuel and purchased power:
Purchases of coal from WRDC	$	4,054	$	4,122	$	11,386	$	12,275
Purchase of excess energy from Cheyenne Light	$	208	$	64	$	324	$	172
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	199	$	312	$	1,174	$	1,329
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	351	$	547	$	2,007	$	2,276
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	297	$	300
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,626	$	6,257	$	20,346	$	19,155

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Employee Benefit Plans:

9 Months Ended

Sep. 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Service cost	$	137		$	151		$	409		$	453
Interest cost	585			625			1,755			1,875
Expected return on plan assets	(898		)	(908		)	(2,692		)	(2,724		)
Prior service cost	10			11			32			33
Net loss (gain)	308			498			922			1,496
Net periodic benefit cost	$	142		$	377		$	426		$	1,133

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Service cost	$	52		$	51		$	155		$	153
Interest cost	44			47			132			141
Prior service cost (benefit)	(84		)	(84		)	(252		)	(252		)
Net periodic benefit cost	$	12		$	14		$	35		$	42

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Interest cost	$	29	$	30	$	87	$	90
Net loss (gain)	22		20		65		62
Net periodic benefit cost	$	51	$	50	$	152	$	152

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. On July 24, 2017, we made contributions to the Defined Benefit Pension Plan in the amount of approximately $1.8 million. On September 15, 2017, we made an additional contribution of approximately $2.2 million to reduce Pension Benefit Guaranty Corporation premiums and offset the forecasted increase in pension expense due to low bond yields which impact the pension discount rate. 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 Nine Months Ended September 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	4,000	$	—	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	406	$	135	$	565
Supplemental Non-qualified Defined Benefit Plans	$	185	$	62	$	246

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Fair Value of Financial Instruments:

9 Months Ended

Sep. 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:

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	1,171	$	1,171	$	234	$	234
Long-term debt, including current maturities (b) (c)	$	339,860	$	439,973	$	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.

(c) Carrying amount of long-term debt is net of deferred financing costs.

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Supplemental Disclosure of Cash Flow Information:

9 Months Ended

Sep. 30, 2017

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Nine months ended September 30,	2017			2016
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,242		$	5,565
Non-cash (decrease) to money pool notes receivable, net	$	(32,000	)	$	(36,500	)
Non-cash dividend to Parent	$	32,000		$	36,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(12,838	)	$	(13,486	)

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Commitment and Contingencies:

9 Months Ended

Sep. 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)

9 Months Ended

Sep. 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 $9.4 million as of September 30, 2016. It also decreased net cash flows provided by operations by $2.2 million for the nine months ended September 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 September 30, 2016 and to the Statements of Cash Flows for the nine months ended September 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 Accounting Standards

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 have substantially completed our assessment of all sources of revenue and are currently determining the impact that adoption of the new standard will have on our financial position, results of operations and cash flows. A majority of our revenues are from regulated tariff offerings that provide electricity with a defined contractual term. For such arrangements, we expect that revenue from contracts with the customer will be equivalent to the electricity delivered during 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. We also continue to monitor outstanding industry implementation issues and assess the impacts to our current accounting policies and/or patterns of revenue recognition.

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 period 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 we monitor regulated utility industry implementation discussions and guidance. For our rate-regulated entities, we currently expect to capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities. 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, and other industry-related areas. We have begun the process of identifying and categorizing our lease contracts and evaluating our current business processes.

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Accounts Receivable and Allowance for Doubtful Accounts: (Tables)

9 Months Ended

Sep. 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:

	September 30, 2017			December 31, 2016
Accounts receivable trade	$	17,356		$	16,972
Unbilled revenues	10,348			13,799
Allowance for doubtful accounts	(125		)	(157		)
Receivables - customers, net	$	27,579		$	30,614

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Regulatory Accounting: (Tables)

9 Months Ended

Sep. 30, 2017

Regulated Operations [Abstract]

Schedule of Regulatory Assets

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

	Maximum Amortization (in years)	September 30, 2017		December 31, 2016
Regulatory assets:
Unamortized loss on reacquired debt (a)	8	$	1,604	$	1,815
Deferred taxes on AFUDC (b)	45	10,192		9,367
Employee benefit plans(c)	12	20,180		20,100
Deferred energy and fuel cost adjustments - current (a)	1	13,754		18,119
Deferred gas cost adjustments (a) (e)	1	5,324		4,897
Deferred taxes on flow through accounting (a)	35	14,906		12,545
Decommissioning costs, net of amortization(d)	6	10,766		12,456
Other regulatory assets (a)(d)	6	15,271		12,835
Total regulatory assets		$	91,997	$	92,134

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	43,518	$	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		$	56,647	$	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.

(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 are being 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.

(e) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. We file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

Schedule of Regulatory Liabilities

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	43,518	$	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		$	56,647	$	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.

(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 are being 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.

(e) Our deferred energy, fuel cost, and gas cost adjustments represent the cost of electricity and gas delivered to our electric utility customers that is either higher or lower than current rates and will be recovered or refunded in future rates. We file periodic quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions.

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Related-Party Transactions: (Tables)

9 Months Ended

Sep. 30, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Accounts Receivable and Payable

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

	September 30, 2017		December 31, 2016
Receivables - affiliates	$	5,498	$	9,526
Accounts payable - affiliates	$	26,828	$	31,799

Schedule of Related Party Notes

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

	September 30, 2017		December 31, 2016
Money pool notes receivable, net	$	8,881	$	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 September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Net interest income (expense)	$	53	$	277	$	269	$	845

Schedule of Revenues and Purchases from Related Parties

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Revenue:
Energy sold to Cheyenne Light	$	361	$	599	$	1,866	$	1,908
Rent from electric properties	$	935	$	1,229	$	2,805	$	3,817
Fuel and purchased power:
Purchases of coal from WRDC	$	4,054	$	4,122	$	11,386	$	12,275
Purchase of excess energy from Cheyenne Light	$	208	$	64	$	324	$	172
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	199	$	312	$	1,174	$	1,329
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	351	$	547	$	2,007	$	2,276
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	99	$	100	$	297	$	300
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	6,626	$	6,257	$	20,346	$	19,155

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Employee Benefit Plans: (Tables)

9 Months Ended

Sep. 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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Service cost	$	137		$	151		$	409		$	453
Interest cost	585			625			1,755			1,875
Expected return on plan assets	(898		)	(908		)	(2,692		)	(2,724		)
Prior service cost	10			11			32			33
Net loss (gain)	308			498			922			1,496
Net periodic benefit cost	$	142		$	377		$	426		$	1,133

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 September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016
Service cost	$	52		$	51		$	155		$	153
Interest cost	44			47			132			141
Prior service cost (benefit)	(84		)	(84		)	(252		)	(252		)
Net periodic benefit cost	$	12		$	14		$	35		$	42

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2017		2016		2017		2016
Interest cost	$	29	$	30	$	87	$	90
Net loss (gain)	22		20		65		62
Net periodic benefit cost	$	51	$	50	$	152	$	152

Schedule of Defined Benefit Plans Contributions

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

	Contributions Nine Months Ended September 30, 2017		Remaining Anticipated Contributions for 2017		Anticipated Contributions for 2018
Defined Benefit Pension Plan	$	4,000	$	—	$	1,834
Defined Benefit Postretirement Healthcare Plan	$	406	$	135	$	565
Supplemental Non-qualified Defined Benefit Plans	$	185	$	62	$	246

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Fair Value of Financial Instruments: (Tables)

9 Months Ended

Sep. 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:

	September 30, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	1,171	$	1,171	$	234	$	234
Long-term debt, including current maturities (b) (c)	$	339,860	$	439,973	$	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.

(c) Carrying amount of long-term debt is net of deferred financing costs.

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Supplemental Disclosure of Cash Flow Information: (Tables)

9 Months Ended

Sep. 30, 2017

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Nine months ended September 30,	2017			2016
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	10,242		$	5,565
Non-cash (decrease) to money pool notes receivable, net	$	(32,000	)	$	(36,500	)
Non-cash dividend to Parent	$	32,000		$	36,500
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(12,838	)	$	(13,486	)

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Management's Statement: Revision (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Prior Period Adjustments Restatement [Line Items]
Decreased net cash flows provided by operations	$ (74,633)	$ (76,637)
Restatement Adjustment
Prior Period Adjustments Restatement [Line Items]
Decreased net cash flows provided by operations		(2,200)
Cash and Cash Equivalents
Prior Period Adjustments Restatement [Line Items]
Prior Period Reclassification Adjustment		$ (9,400)

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Accounts Receivable and Allowance for Doubtful Accounts: (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016
Accounts Receivable, Net [Abstract]
Accounts receivable trade	$ 17,356	$ 16,972
Unbilled revenues	10,348	13,799
Allowance for doubtful accounts	(125)	(157)
Receivables - customers, net	$ 27,579	$ 30,614

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Regulatory Accounting: Regulatory Assets (Details) - USD ($) $ in Thousands		9 Months Ended
	Jul. 01, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Regulatory Assets		$ 91,997		$ 92,134
Annual amortization expense	$ 2,700
Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Maximum Amortization (in years)		8 years
Regulatory Assets		$ 1,604		1,815
Deferred taxes on AFUDC
Regulatory Assets [Line Items]
Maximum Amortization (in years)		45 years
Regulatory Assets		$ 10,192		9,367
Employee benefit plans
Regulatory Assets [Line Items]
Maximum Amortization (in years)		12 years
Regulatory Assets		$ 20,180		20,100
Deferred energy and fuel cost adjustments - current
Regulatory Assets [Line Items]
Maximum Amortization (in years)		1 year
Regulatory Assets		$ 13,754		18,119
Deferred gas cost adjustments
Regulatory Assets [Line Items]
Maximum Amortization (in years)		1 year
Regulatory Assets		$ 5,324		4,897
Deferred taxes on flow through accounting
Regulatory Assets [Line Items]
Maximum Amortization (in years)		35 years
Regulatory Assets		$ 14,906		12,545
Decommissioning costs, net of amortization
Regulatory Assets [Line Items]
Maximum Amortization (in years)		6 years
Regulatory Assets		$ 10,766		12,456
Decommissioning costs, net of amortization | South Dakota Public Utilities Commission (SDPUC)
Regulatory Assets [Line Items]
Maximum Amortization (in years)	6 years
Regulatory Assets			$ 11,000
Other regulatory assets
Regulatory Assets [Line Items]
Maximum Amortization (in years)		6 years
Regulatory Assets		$ 15,271		$ 12,835
Other regulatory assets | South Dakota Public Utilities Commission (SDPUC)
Regulatory Assets [Line Items]
Maximum Amortization (in years)	6 years
Regulatory Assets			14,000
Other regulatory assets | South Dakota Public Utilities Commission (SDPUC) | Winter Storm Atlas
Regulatory Assets [Line Items]
Maximum Amortization (in years)	6 years
Regulatory Assets			$ 2,000

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Regulatory Accounting: Regulatory Liabilities (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$ 56,647	$ 53,950
Cost Of Removal
Regulatory Liabilities [Line Items]
Maximum Amortization (in years)	61 years
Regulatory Liabilities	$ 43,518	41,541
Employee benefit plan costs and related deferred taxes
Regulatory Liabilities [Line Items]
Maximum Amortization (in years)	12 years
Regulatory Liabilities	$ 12,304	12,304
Other regulatory liabilities
Regulatory Liabilities [Line Items]
Maximum Amortization (in years)	13 years
Regulatory Liabilities	$ 825	$ 105

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Regulatory Accounting: Recovery Period (Details)		6 Months Ended	9 Months Ended
	Jul. 01, 2017	Jun. 30, 2017	Sep. 30, 2017
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)
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)
Regulatory Assets [Line Items]
Regulatory Assets Amortization Period, Unclassified (less than)	6 years
Other Regulatory Assets | South Dakota Public Utilities Commission (SDPUC) | 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		9 Months Ended
	Sep. 01, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016	Dec. 31, 2016
Related Party Transaction [Line Items]
Receivables - affiliates		$ 5,498		$ 5,498		$ 9,526
Accounts payable - affiliates		26,828		$ 26,828		31,799
Related Party Transaction, Utility Money Pool Interest Rate				1.66%
Money pool notes receivable, net		8,881		$ 8,881		$ 28,409
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	297	$ 300
Subsidiary of Common Parent | Purchases of coal from WRDC
Related Party Transaction [Line Items]
Fuel and purchased power		4,054	4,122	11,386	12,275
Subsidiary of Common Parent | Purchase of excess energy from Cheyenne Light
Related Party Transaction [Line Items]
Fuel and purchased power		208	64	324	172
Subsidiary of Common Parent | Purchase of renewable wind energy from Cheyenne Light - Happy Jack
Related Party Transaction [Line Items]
Fuel and purchased power		199	312	1,174	1,329
Subsidiary of Common Parent | Purchase of renewable wind energy from Cheyenne Light - Silver Sage
Related Party Transaction [Line Items]
Fuel and purchased power		351	547	2,007	2,276
Subsidiary of Common Parent | Energy sold to Cheyenne Light
Related Party Transaction [Line Items]
Revenue		361	599	1,866	1,908
Subsidiary of Common Parent | Rent from electric properties
Related Party Transaction [Line Items]
Revenue		935	1,229	2,805	3,817
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		6,626	6,257	$ 20,346	19,155
Parent
Related Party Transaction [Line Items]
Commitment fee percentage				1.00%
Utility Money Pool
Related Party Transaction [Line Items]
Net interest income (expense)		$ 53	$ 277	$ 269	$ 845
Cash and Cash Equivalents | Subsidiary of Common Parent | Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ (700)
Money Pool Notes Receivable | Subsidiary of Common Parent | Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	(1,000)
Retained Earnings | Subsidiary of Common Parent | Utility Money Pool Transfered From Black HIlls Power To Affiliate Black Hills Utility Holdings
Related Party Transaction [Line Items]
Related Party Transaction, Amounts of Transaction	$ (300)

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Employee Benefit Plans: (Details) - USD ($) $ in Thousands			3 Months Ended		9 Months Ended
	Sep. 15, 2017	Jul. 24, 2017	Sep. 30, 2017	Sep. 30, 2016	Sep. 30, 2017	Sep. 30, 2016
Defined Benefit Pension Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			$ 137	$ 151	$ 409	$ 453
Interest cost			585	625	1,755	1,875
Expected return on plan assets			(898)	(908)	(2,692)	(2,724)
Prior service cost (benefit)			10	11	32	33
Net loss (gain)			308	498	922	1,496
Net periodic benefit cost			142	377	426	1,133
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer	$ 2,200	$ 1,800			4,000
Remaining Anticipated Contributions for Current Year					0
Anticipated Contributions for Next Year					1,834
Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Service cost			52	51	155	153
Interest cost			44	47	132	141
Prior service cost (benefit)			(84)	(84)	(252)	(252)
Net periodic benefit cost			12	14	35	42
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer					406
Remaining Anticipated Contributions for Current Year					135
Anticipated Contributions for Next Year					565
Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan, Net Periodic Benefit Cost [Abstract]
Interest cost			29	30	87	90
Net loss (gain)			22	20	65	62
Net periodic benefit cost			$ 51	$ 50	152	$ 152
Pension and Other Postretirement Benefit Contributions [Abstract]
Contributions made by Employer					185
Remaining Anticipated Contributions for Current Year					62
Anticipated Contributions for Next Year					$ 246

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Fair Value of Financial Instruments: (Details) - USD ($) $ in Thousands	Sep. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	$ 1,171	$ 234	$ 825	$ 297
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	1,171	234
Long-term debt, including current maturities, carrying amount	339,860	339,756
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, fair value	1,171	234
Long-term debt, including current maturities, fair value	$ 439,973	$ 410,466

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Supplemental Disclosure of Cash Flow Information: (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2016
Noncash Investing and Financing Items [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 10,242	$ 5,565
Interest and Income Taxes Paid Net [Abstract]
Interest (net of amounts capitalized)	(12,838)	(13,486)
Subsidiary of Common Parent
Noncash Investing and Financing Items [Abstract]
Non-cash (decrease) to money pool notes receivable, net	(32,000)	(36,500)
Parent
Noncash Investing and Financing Items [Abstract]
Non-cash dividend to Parent	$ 32,000	$ 36,500