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 March 31, 2018
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
7001 Mount Rushmore Road
Rapid City, South Dakota 57702
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 April 30, 2018, 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 Comprehensive Income - unaudited	4
	Three Months Ended March 31, 2018 and 2017
	Condensed Balance Sheets - unaudited	5
	March 31, 2018 and December 31, 2017
	Condensed Statements of Cash Flows - unaudited	7
	Three Months Ended March 31, 2018 and 2017
	Notes to Condensed Financial Statements - unaudited	8
Item 2.	Managements’ Discussion and Analysis of Financial Condition and Results of Operations	17
Item 4.	Controls and Procedures	21
PART II.	OTHER INFORMATION	22
Item 1.	Legal Proceedings	22
Item 1A.	Risk Factors	22
Item 6.	Exhibits	22
	Signatures	23

2

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

AFUDC	Allowance for Funds Used During Construction
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.
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
Happy Jack	Happy Jack Wind Farms, LLC, a subsidiary of Duke Energy Generation Services
Heating degree day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations over a 30-year average.
kV	Kilovolt
LIBOR	London Interbank Offered Rate
Moody’s	Moody’s Investors Service, Inc.
MW	Megawatts
SDPUC	South Dakota Public Utilities Commission
SEC	U. S. Securities and Exchange Commission
Silver Sage	Silver Sage Windpower, LLC, a subsidiary of Duke Energy Generation Services
South Dakota Electric	Includes Black Hills Power operations in South Dakota, Wyoming and Montana
S&P	Standard & Poor’s, a division of The McGraw-Hill Companies, Inc.
TCA	Transmission Cost Adjustment - adjustments passed through to the customer based on transmission costs that are higher or lower than the costs approved in the rate case.
TCJA	Tax Cuts and Jobs Act enacted December 22, 2017
WRDC	Wyodak Resources Development Corp., an indirect, wholly-owned subsidiary of BHC

3

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF COMPREHENSIVE INCOME

	Three Months Ended March 31,
(unaudited)	2018			2017
	(in thousands)
Revenue	$	73,815		$	73,794
Operating expenses:
Fuel and purchased power	22,440			23,149
Operations and maintenance	19,151			16,954
Depreciation and amortization	9,884			8,694
Taxes - property	1,976			1,621
Total operating expenses	53,451			50,418
Operating income	20,364			23,376
Other income (expense):
Interest expense	(5,587		)	(6,336		)
AFUDC - borrowed	48			192
Interest income	115			707
AFUDC - equity	34			471
Other income (expense), net	(151		)	(53		)
Total other income (expense)	(5,541		)	(5,019		)
Income before income taxes	14,823			18,357
Income tax expense	(3,063		)	(5,787		)
Net income	11,760			12,570
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 March 31, 2018 and 2017, respectively)	10			10
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(9) and $(8) for the three months ended March 31, 2018 and 2017, respectively)	17			14
Other comprehensive income	27			24
Comprehensive income	$	11,787		$	12,594

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)	March 31, 2018			December 31, 2017
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	12		$	16
Receivables - customers, net	29,502			29,050
Receivables - affiliates	6,925			5,664
Other receivables, net	252			196
Materials, supplies and fuel	24,471			23,443
Regulatory assets, current	20,078			18,993
Other current assets	4,076			4,528
Total current assets	85,316			81,890
Investments	4,918			4,926
Property, plant and equipment	1,318,781			1,311,819
Less accumulated depreciation and amortization	(359,344		)	(358,946		)
Total property, plant and equipment, net	959,437			952,873
Other assets:
Regulatory assets, non-current	56,134			59,710
Other non-current assets	8,796			3,747
Total other assets	64,930			63,457
TOTAL ASSETS	$	1,114,601		$	1,103,146

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

5

BLACK HILLS POWER, INC.

CONDENSED BALANCE SHEETS

(unaudited)	March 31, 2018			December 31, 2017
	(in thousands, except common stock par value and share amounts)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	15,187		$	14,766
Accounts payable - affiliates	24,767			25,653
Accrued liabilities	45,512			38,205
Money pool notes payable	13,541			13,397
Regulatory liabilities, current	3,996			842
Total current liabilities	103,003			92,863
Long-term debt	339,930			339,895
Deferred credits and other liabilities:
Deferred income tax liabilities, net	110,081			110,618
Regulatory liabilities, non-current	153,607			148,013
Benefit plan liabilities	16,540			16,285
Other, non-current liabilities	1,420			1,240
Total deferred credits and other liabilities	281,648			276,156
Commitments and contingencies (Notes 5, 6 and 9)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416			23,416
Additional paid-in capital	39,575			39,575
Retained earnings	328,260			332,499
Accumulated other comprehensive loss	(1,231		)	(1,258		)
Total stockholder’s equity	390,020			394,232
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	1,114,601		$	1,103,146

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

6

BLACK HILLS POWER, INC.

CONDENSED STATEMENTS OF CASH FLOWS

(unaudited)	Three Months Ended March 31,
	2018			2017
	(in thousands)
Operating activities:
Net income	$	11,760		$	12,570
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	9,884			8,694
Deferred income tax	(898		)	2,704
Employee benefits	380			205
AFUDC	(34		)	(471		)
Other adjustments, net	1,052			559
Change in operating assets and liabilities -
Accounts receivable and other current assets	(2,478		)	7,908
Accounts payable and other current liabilities	3,320			(380		)
Regulatory assets - current	1,807			(2,170		)
Regulatory liabilities - current	3,171			(84		)
Other operating activities, net	35			(152		)
Net cash provided by (used in) operating activities	27,999			29,383
Investing activities:
Property, plant and equipment additions	(13,533		)	(16,976		)
Proceeds from sale of assets	4,994			—
Change in money pool notes receivable, net	—			(11,540		)
Other investing activities	(3,608		)	26
Net cash provided by (used in) investing activities	(12,147		)	(28,490		)
Financing activities:
Change in money pool notes payable, net	(15,856		)	—
Net cash provided by (used in) financing activities	(15,856		)	—
Net change in cash and cash equivalents	(4		)	893
Cash and cash equivalents, beginning of period	16			234
Cash and cash equivalents, end of period	$	12		$	1,127

See Note 8 for supplemental cash flow information.

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

7

BLACK HILLS POWER, INC.

Notes to Condensed Financial Statements

(unaudited)

(Reference is made to Notes to Financial Statements

included in our 2017 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 2017 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 March 31, 2018, December 31, 2017 and March 31, 2017 financial information and are of a normal recurring nature. The results of operations for the three months ended March 31, 2018 and March 31, 2017, and our financial condition as of March 31, 2018 and December 31, 2017 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued Accounting Standards

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 most leases, 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. Under the current guidance, 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. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing not to assess existing or expired land easements that were not previously accounted for as a lease when transitioning to the new standard. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor utility industry implementation guidance. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and initiated implementation of a new lease software solution.

8

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.

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

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires 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. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

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

Effective January 1, 2018, we adopted 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. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

9

(2)    REVENUE

Revenue Recognition

Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:

• Regulated electric utility services tariffs - Our regulated operations, as defined by ASC 980, provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of commodity electricity and electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our regulated utility sales are subject to regulatory-approved tariffs.

• Power sales agreements - We have long-term wholesale power sales agreements with other load serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price, and is variable based on energy delivered.

The following table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments. Sales tax and other similar taxes are excluded from revenues.

	Three Months Ended March 31, 2018
	(in thousands)
Customer types:
Retail	$	50,641
Wholesale	9,050
Market - off-system sales	2,275
Transmission/Other	11,718
Revenue from contracts with customers	73,684
Other revenues	131
Total revenues	$	73,815
Timing of revenue recognition:
Services transferred at a point in time	—
Services transferred over time	73,684
Revenue from contracts with customers	$	73,684

The majority of the our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.

10

Revenue Not in Scope of ASC 606

Other revenues included in the table above include revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980.

Significant Judgments and Estimates

TCJA revenue reserve

The TCJA or “tax reform”, signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills Power’s regulators have directed the utility to calculate the impact of tax reform on existing customer rates and tariffs caused by the income tax rate reduction. Until the regulators have a chance to review and approve these calculations, the utility continues to charge customers existing rates with the embedded 35% tax rate and estimate a reserve to revenue based on current discussions or filed applications with the regulators. We estimated and recorded a revenue reserve of approximately $3.1 million during the three months ended March 31, 2018.

Unbilled Revenue

Revenues attributable to energy delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues may include estimates of delivered sales volumes based on weather information and customer consumption trends.

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable and is further discussed in Note 1 of our Notes to the Financial Statements of our 2017 Annual Report on Form 10-K Business Description. We do not typically incur costs that would be capitalized, to obtain or fulfill a contract.

Practical Expedients

Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

(3) 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:

	March 31, 2018			December 31, 2017
Accounts receivable trade	$	16,992		$	15,994
Unbilled revenues	12,772			13,280
Allowance for doubtful accounts	(262		)	(224		)
Receivables - customers, net	$	29,502		$	29,050

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(4) 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)	March 31, 2018		December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt (a)	7	$	1,464	$	1,534
Deferred taxes on AFUDC (b)	45	5,050		5,095
Employee benefit plans(c)	12	19,723		19,465
Deferred energy and fuel cost adjustments - current (a)	1	17,912		19,602
Deferred taxes on flow through accounting	54	7,929		7,579
Decommissioning costs, net of amortization	6	9,738		10,252
Vegetation management, net of amortization	6	12,093		12,669
Other regulatory assets (a)	6	2,303		2,507
Total regulatory assets		$	76,212	$	78,703

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	49,580	$	44,056
Employee benefit plan costs and related deferred taxes (c)	12	6,808		6,808
Excess deferred income taxes	40	97,061		97,101
TCJA revenue reserve (d)	subject to approval	3,121		—
Other regulatory liabilities	13	1,033		890
Total regulatory liabilities		$	157,603	$	148,855

____________________

(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) As of March 31, 2018, the amortization period is yet to be determined and subject to approval by our regulators.

Regulatory Matters

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 1 of the Notes to the Financial Statements in our 2017 Annual Report on Form 10-K.

TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Black Hills Power’s regulators have issued orders directing the utility to calculate the impacts of tax reform on existing rates/tariffs caused by the income tax rate reduction. Until each regulator has a chance to review and approve the calculations, the utility continues to charge customers existing rates with the embedded 35% federal tax rate, resulting in a reserve to revenue until new rates reflecting the 21% federal tax rate are effective. We estimated and recorded a reserve to revenue of approximately $3.1 million during the three months ended March 31, 2018.

We are working with our respective regulators to address the impact of tax reform and the appropriate benefit to customers.

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(5) RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of $16 million and $7.0 million for three months ended March 31, 2018 and March 31, 2017, respectively, and decreased the utility Money pool note receivable by $16 million and $7.0 million for the three months ended March 31, 2018 and March 31, 2017, respectively.

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:

	March 31, 2018		December 31, 2017
Receivables - affiliates	$	6,925	$	5,664
Accounts payable - affiliates	$	24,767	$	25,653

Money Pool Notes Receivable and Notes Payable

We 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 March 31, 2018, the average cost of borrowing under the Utility Money Pool was 2.54%.

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

	March 31, 2018		December 31, 2017
Money pool notes payable	$	13,541	$	13,397

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

	Three Months Ended March 31,
	2018			2017
Net interest income (expense)	$	(36	)	$	126

13

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

	Three Months Ended March 31,
	2018		2017
Revenue:
Energy sold to Cheyenne Light	$	703	$	878
Rent from electric properties	$	3,678	$	1,272
Fuel and purchased power:
Purchases of coal from WRDC	$	4,067	$	4,280
Purchase of excess energy from Cheyenne Light	$	86	$	40
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	641	$	606
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	1,093	$	1,019
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	96	$	99
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,606	$	6,611

Horizon Point Agreement

We have a shared facility agreement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric.  This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

(6) EMPLOYEE BENEFIT PLANS

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

	Three Months Ended March 31,
	2018			2017
Service cost	$	129		$	136
Interest cost	548			585
Expected return on plan assets	(886		)	(897		)
Prior service cost	11			11
Net loss (gain)	516			307
Net periodic benefit cost	$	318		$	142

14

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 March 31,
	2018			2017
Service cost	$	48		$	52
Interest cost	45			44
Prior service cost (benefit)	(84		)	(84		)
Net periodic benefit cost	$	9		$	12

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended March 31,
	2018		2017
Interest cost	$	27	$	29
Net loss (gain)	26		22
Net periodic benefit cost	$	53	$	51

For the three months ended March 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net on the Condensed Statements of Comprehensive Income. For the three months ended March 31, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Statements of Comprehensive Income. See Note 1 for additional information.

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands):

	Contributions Three Months Ended March 31, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
Defined Benefit Pension Plan	$	—	$	1,795	$	1,789
Defined Benefit Postretirement Healthcare Plan	$	134	$	401	$	554
Supplemental Non-qualified Defined Benefit Plans	$	61	$	184	$	241

15

(7) 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 2017 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:

	March 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	12	$	12	$	16	$	16
Long-term debt, including current maturities (b) (c)	$	339,930	$	429,001	$	339,895	$	446,978

_________________

(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.

(8) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Three months ended March 31,	2018			2017
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	7,556		$	10,998
Non-cash (decrease) to money pool notes receivable, net	$	(16,000	)	$	(7,000	)
Non-cash dividend to Parent	$	16,000		$	7,000
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(3,088	)	$	(3,014	)

(9) 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 2017 Annual Report on Form 10-K.

(10) INCOME TAXES

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017. We have made our best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.

16

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

During the first quarter of 2018, we commenced construction of a $70 million, 230-kV, 175 mile-long transmission line that connects Rapid City, South Dakota to Stegall, Nebraska. The project will be constructed in two segments, with the first segment expected to be placed in service in 2018 and the second segment expected to be serving customers in 2019.

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.

17

The following tables provide certain financial information and operating statistics:

	Three Months Ended March 31,
	2018			2017			Variance
	(in thousands)
Revenue	$	73,815		$	73,794		$	21
Fuel and purchased power	22,440			23,149			(709		)
Gross margin	51,375			50,645			730
Operating expenses	31,011			27,269			3,742
Operating income	20,364			23,376			(3,012		)
Interest income (expense), net	(5,424		)	(5,437		)	13
Other income (expense), net	(117		)	418			(535		)
Income tax expense	(3,063		)	(5,787		)	2,724
Net income	$	11,760		$	12,570		$	(810	)

Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017. Net income was $12 million compared to $13 million for the same period in the prior year primarily due to the following:

Gross marginincreased over the prior year reflecting higher non-energy revenue of $2.2 million primarily related to Horizon Point rent income, a $1.1 million increase in residential margins primarily from colder weather in the current year, and higher rider revenues of $0.8 million primarily related to transmission investment recovery. These increases were partially offset by a $3.1 million reserve to revenue to reflect the reduction of the lower federal income tax rate from the TCJA on our existing rate tariffs and $0.3 million lower commercial and industrial demand.

Operating expensesincreased primarily due to $2.8 million of higher vegetation management expenses. Higher employee costs, property taxes and outage related expenses comprise the remainder of the increase compared to the same period in the prior year.

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

Other income (expense), net decreased due to higher prior year AFUDC associated with higher prior year capital spend.

Income tax expense: The effective tax rate decreased from the prior year due to the reduction in the federal corporate income tax rate from 35 percent to 21 percent from the TCJA, effective January 1, 2018.

18

	Electric Revenue by Customer Type
	Three Months Ended March 31,
	(in thousands)
	2018		Percentage Change	2017
Residential	$	21,061	5%	$	20,071
Commercial	23,544		(3)%	24,291
Industrial	8,276		(2)%	8,454
Municipal	811		(3)%	836
Total retail revenue	53,692		—%	53,652
Wholesale (a)	9,050		15%	7,843
Market - off-system sales (b)	2,275		(41)%	3,833
Other revenue	8,798		4%	8,466
Total revenue	$	73,815	—%	$	73,794

____________________

(a) Increase for the three months ended March 31, 2018 was primarily driven by colder weather.

(b) Decrease for three months ended March 31, 2018 was due to softer market conditions driven by natural gas prices and excess energy in the market.

	Megawatt Hours Sold by Customer Type
	Three Months Ended March 31,
	2018	Percentage Change	2017
Residential	163,113	9%	149,572
Commercial	194,931	(1)%	196,406
Industrial	104,302	(5)%	109,796
Municipal	7,503	(1)%	7,605
Total retail quantity sold	469,849	1%	463,379
Wholesale (a)	237,704	28%	186,116
Market - off-system sales (b)	92,102	(40)%	154,496
Total quantity sold	799,655	(1)%	803,991
Losses and company use (c)	28,522	(32)%	41,841
Total energy	828,177	(2)%	845,832

____________________

(a) Increase for the three months ended March 31, 2018 was primarily driven by colder weather.

(b) Decrease for three months ended March 31, 2018 was due to softer market conditions driven by lower natural gas prices and excess energy in the market.

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

19

	Megawatt Hours Generated and Purchased
	Three Months Ended March 31,
Generated -	2018	Percentage Change	2017
Coal-fired	399,087	3%	387,985
Natural Gas and Oil (a)	13,107	27%	10,350
Total generated	412,194	3%	398,335
Total purchased	415,983	(7)%	447,497
Total generated and purchased	828,177	(2)%	845,832

____________________

(a) Increase for the three months ended March 31, 2018 compared to the same periods in the prior year are driven primarily by lower natural gas prices compared to purchased power.

	Power Plant Availability
	Three Months Ended March 31,
	2018		2017
Coal-fired plants (a)	92.9	%	89.2	%
Other plants	99.4	%	99.4	%
Total availability	96.3	%	94.6	%

____________________

(a) Both years included outages. 2018 included planned outages at Neil Simpson II, Wyodak and Wygen II, and 2017 included a planned outage at Wygen III and an extended planned outage at Wyodak.

	Degree Days
	Three Months Ended March 31,
	2018			2017
	Actual	Variance from 30-year Average		Actual	Variance from 30-year Average
Heating degree days	3,699	15	%	3,130	(3	)%
Cooling degree days	—	—	%	—	—	%

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 March 31, 2018:

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

20

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 2017 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, 2017.

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 March 31, 2018. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective as of March 31, 2018.

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 March 31, 2018, 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.

21

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 2017 Annual Report on Form 10-K and Note 9 of our Notes to Condensed Financial Statements in this Quarterly Report on Form 10-Q, which information from Note 9 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, 2017.

Item 6. Exhibits

Exhibit 3.1* Restated Articles of Incorporation of the Registrant dated January 30, 2018 (filed as Exhibit 3 to Registrant’s Form 8-K filed on February 5, 2018).

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

Exhibit 4.1* Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to J.P. Morgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669-01)).

Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registration Statement on Form S-3 (No. 333-150669-01)).

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

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

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

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

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

Exhibit 101 Financial Statements for XBRL Format

_________________________

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

22

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: May 4, 2018

23

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, David R. Emery, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date:	May 4, 2018
		/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:	May 4, 2018
		/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 March 31, 2018 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:	May 4, 2018
		/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 March 31, 2018 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:	May 4, 2018
		/S/ RICHARD W. KINZLEY
		Richard W. Kinzley
		Senior Vice President and Chief Financial Officer

XML

Document and Entity Information Document - shares	3 Months Ended
	Mar. 31, 2018	Apr. 30, 2018
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	Mar. 31, 2018
Amendment Flag	false
Document Fiscal Year End Focus	2018
Document Fiscal Period Focus	Q1
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 Comprehensive Income - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Statement [Abstract]
Revenue	$ 73,815	$ 73,794
Operating expenses:
Fuel and purchased power	22,440	23,149
Operations and maintenance	19,151	16,954
Depreciation and amortization	9,884	8,694
Taxes - property	1,976	1,621
Total operating expenses	53,451	50,418
Operating income	20,364	23,376
Other income (expense):
Interest expense	(5,587)	(6,336)
AFUDC - borrowed	48	192
Interest income	115	707
AFUDC - equity	34	471
Other income (expense), net	(151)	(53)
Total other income (expense)	(5,541)	(5,019)
Income before income taxes	14,823	18,357
Income tax expense	(3,063)	(5,787)
Net income	11,760	12,570
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 March 31, 2018 and 2017, respectively)	10	10
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax (expense) benefit of $(9) and $(8) for the three months ended March 31, 2018 and 2017, respectively)	17	14
Other comprehensive income	27	24
Comprehensive income	$ 11,787	$ 12,594

XML

Condensed Statements of Comprehensive Income OCI Parenthetical - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Statement [Abstract]
Reclassification adjustment of cash flow hedges settled, (tax) benefit	$ (6)	$ (6)
Reclassification adjustment of benefit and other postretirement plans included in net income, (tax) benefit	$ (9)	$ (8)

XML

Condensed Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 12	$ 16
Receivables - customers, net	29,502	29,050
Receivables - affiliates	6,925	5,664
Other receivables, net	252	196
Materials, supplies and fuel	24,471	23,443
Regulatory assets, current	20,078	18,993
Other current assets	4,076	4,528
Total current assets	85,316	81,890
Investments	4,918	4,926
Property, plant and equipment	1,318,781	1,311,819
Less accumulated depreciation and amortization	(359,344)	(358,946)
Total property, plant and equipment, net	959,437	952,873
Other assets:
Regulatory assets, non-current	56,134	59,710
Other non-current assets	8,796	3,747
Total other assets	64,930	63,457
TOTAL ASSETS	1,114,601	1,103,146
Current liabilities:
Accounts payable	15,187	14,766
Accounts payable - affiliates	24,767	25,653
Accrued liabilities	45,512	38,205
Money pool notes payable	13,541	13,397
Regulatory liabilities, current	3,996	842
Total current liabilities	103,003	92,863
Long-term debt	339,930	339,895
Deferred credits and other liabilities:
Deferred income tax liabilities, net	110,081	110,618
Regulatory liabilities, non-current	153,607	148,013
Benefit plan liabilities	16,540	16,285
Other, non-current liabilities	1,420	1,240
Total deferred credits and other liabilities	281,648	276,156
Commitments and contingencies (Notes 5, 6 and 9)
Stockholder’s equity:
Common stock $1 par value; 50,000,000 shares authorized; 23,416,396 shares issued	23,416	23,416
Additional paid-in capital	39,575	39,575
Retained earnings	328,260	332,499
Accumulated other comprehensive loss	(1,231)	(1,258)
Total stockholder’s equity	390,020	394,232
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$ 1,114,601	$ 1,103,146

XML

Condensed Balance Sheets Parenthetical - $ / shares	Mar. 31, 2018	Dec. 31, 2017
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	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities:
Net income	$ 11,760	$ 12,570
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation and amortization	9,884	8,694
Deferred income tax	(898)	2,704
Employee benefits	380	205
AFUDC	(34)	(471)
Other adjustments, net	1,052	559
Change in operating assets and liabilities -
Accounts receivable and other current assets	(2,478)	7,908
Accounts payable and other current liabilities	3,320	(380)
Regulatory assets - current	1,807	(2,170)
Regulatory liabilities - current	3,171	(84)
Other operating activities, net	35	(152)
Net cash provided by (used in) operating activities	27,999	29,383
Investing activities:
Property, plant and equipment additions	(13,533)	(16,976)
Proceeds from sale of assets	4,994	0
Change in money pool notes receivable, net	0	(11,540)
Other investing activities	(3,608)	26
Net cash provided by (used in) investing activities	(12,147)	(28,490)
Financing activities:
Change in money pool notes payable, net	(15,856)	0
Net cash provided by (used in) financing activities	(15,856)	0
Net change in cash and cash equivalents	(4)	893
Cash and cash equivalents, beginning of period	16	234
Cash and cash equivalents, end of period	$ 12	$ 1,127

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Management's Statement:

3 Months Ended

Mar. 31, 2018

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 2017 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 March 31, 2018, December 31, 2017 and March 31, 2017 financial information and are of a normal recurring nature. The results of operations for the three months ended March 31, 2018 and March 31, 2017, and our financial condition as of March 31, 2018 and December 31, 2017 are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period.

Recently Issued Accounting Standards

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 most leases, 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. Under the current guidance, 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. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing not to assess existing or expired land easements that were not previously accounted for as a lease when transitioning to the new standard. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor utility industry implementation guidance. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and initiated implementation of a new lease software solution.

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.

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

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires 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. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

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

Effective January 1, 2018, we adopted 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. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

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Revenue:

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

Revenue Recognition

Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:

• Regulated electric utility services tariffs - Our regulated operations, as defined by ASC 980, provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of commodity electricity and electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our regulated utility sales are subject to regulatory-approved tariffs.

• Power sales agreements - We have long-term wholesale power sales agreements with other load serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price, and is variable based on energy delivered.

The following table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments. Sales tax and other similar taxes are excluded from revenues.

	Three Months Ended March 31, 2018
	(in thousands)
Customer types:
Retail	$	50,641
Wholesale	9,050
Market - off-system sales	2,275
Transmission/Other	11,718
Revenue from contracts with customers	73,684
Other revenues	131
Total revenues	$	73,815
Timing of revenue recognition:
Services transferred at a point in time	—
Services transferred over time	73,684
Revenue from contracts with customers	$	73,684

The majority of the our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.

Revenue Not in Scope of ASC 606

Other revenues included in the table above include revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980.

Significant Judgments and Estimates

TCJA revenue reserve

The TCJA or “tax reform”, signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills Power’s regulators have directed the utility to calculate the impact of tax reform on existing customer rates and tariffs caused by the income tax rate reduction. Until the regulators have a chance to review and approve these calculations, the utility continues to charge customers existing rates with the embedded 35% tax rate and estimate a reserve to revenue based on current discussions or filed applications with the regulators. We estimated and recorded a revenue reserve of approximately $3.1 million during the three months ended March 31, 2018.

Unbilled Revenue

Revenues attributable to energy delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues may include estimates of delivered sales volumes based on weather information and customer consumption trends.

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable and is further discussed in Note 1 of our Notes to the Financial Statements of our 2017 Annual Report on Form 10-K Business Description. We do not typically incur costs that would be capitalized, to obtain or fulfill a contract.

Practical Expedients

Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

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Accounts Receivable and Allowance for Doubtful Accounts:

3 Months Ended

Mar. 31, 2018

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:

	March 31, 2018			December 31, 2017
Accounts receivable trade	$	16,992		$	15,994
Unbilled revenues	12,772			13,280
Allowance for doubtful accounts	(262		)	(224		)
Receivables - customers, net	$	29,502		$	29,050

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Regulatory Accounting:

3 Months Ended

Mar. 31, 2018

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)	March 31, 2018		December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt (a)	7	$	1,464	$	1,534
Deferred taxes on AFUDC (b)	45	5,050		5,095
Employee benefit plans(c)	12	19,723		19,465
Deferred energy and fuel cost adjustments - current (a)	1	17,912		19,602
Deferred taxes on flow through accounting	54	7,929		7,579
Decommissioning costs, net of amortization	6	9,738		10,252
Vegetation management, net of amortization	6	12,093		12,669
Other regulatory assets (a)	6	2,303		2,507
Total regulatory assets		$	76,212	$	78,703

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	49,580	$	44,056
Employee benefit plan costs and related deferred taxes (c)	12	6,808		6,808
Excess deferred income taxes	40	97,061		97,101
TCJA revenue reserve (d)	subject to approval	3,121		—
Other regulatory liabilities	13	1,033		890
Total regulatory liabilities		$	157,603	$	148,855

____________________

(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) As of March 31, 2018, the amortization period is yet to be determined and subject to approval by our regulators.

Regulatory Matters

Except as discussed below, there have been no other significant changes to our Regulatory Matters from those previously disclosed in Note 1 of the Notes to the Financial Statements in our 2017 Annual Report on Form 10-K.

TCJA revenue reserve - The TCJA signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21%. Effective January 1, 2018, the key impact of tax reform on existing utility revenues/tariffs established prior to tax reform results primarily from the change in the federal tax rate from 35% to 21% (including the effects of tax gross-ups not yet approved) affecting current income tax expense embedded in those tariffs. Black Hills Power’s regulators have issued orders directing the utility to calculate the impacts of tax reform on existing rates/tariffs caused by the income tax rate reduction. Until each regulator has a chance to review and approve the calculations, the utility continues to charge customers existing rates with the embedded 35% federal tax rate, resulting in a reserve to revenue until new rates reflecting the 21% federal tax rate are effective. We estimated and recorded a reserve to revenue of approximately $3.1 million during the three months ended March 31, 2018.

We are working with our respective regulators to address the impact of tax reform and the appropriate benefit to customers.

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Related-Party Transactions:

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Related-Party Transactions

RELATED-PARTY TRANSACTIONS

Non-Cash Dividend to Parent

We recorded non-cash dividends to our Parent of $16 million and $7.0 million for three months ended March 31, 2018 and March 31, 2017, respectively, and decreased the utility Money pool note receivable by $16 million and $7.0 million for the three months ended March 31, 2018 and March 31, 2017, respectively.

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:

	March 31, 2018		December 31, 2017
Receivables - affiliates	$	6,925	$	5,664
Accounts payable - affiliates	$	24,767	$	25,653

Money Pool Notes Receivable and Notes Payable

We 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 March 31, 2018, the average cost of borrowing under the Utility Money Pool was 2.54%.

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

	March 31, 2018		December 31, 2017
Money pool notes payable	$	13,541	$	13,397

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

	Three Months Ended March 31,
	2018			2017
Net interest income (expense)	$	(36	)	$	126

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

	Three Months Ended March 31,
	2018		2017
Revenue:
Energy sold to Cheyenne Light	$	703	$	878
Rent from electric properties	$	3,678	$	1,272
Fuel and purchased power:
Purchases of coal from WRDC	$	4,067	$	4,280
Purchase of excess energy from Cheyenne Light	$	86	$	40
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	641	$	606
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	1,093	$	1,019
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	96	$	99
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,606	$	6,611

Horizon Point Agreement

We have a shared facility agreement among South Dakota Electric, Black Hills Service Company, and Black Hills Utility Holdings where there is a cost allocation for the use of the Horizon Point facility that is owned by South Dakota Electric.  This cost allocation includes the recovery of and return on allocable property and recovery of incurred administrative service expenses for the operation and maintenance of the Horizon Point facility.

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Employee Benefit Plans:

3 Months Ended

Mar. 31, 2018

Defined Benefit Plan [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 March 31,
	2018			2017
Service cost	$	129		$	136
Interest cost	548			585
Expected return on plan assets	(886		)	(897		)
Prior service cost	11			11
Net loss (gain)	516			307
Net periodic benefit cost	$	318		$	142

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 March 31,
	2018			2017
Service cost	$	48		$	52
Interest cost	45			44
Prior service cost (benefit)	(84		)	(84		)
Net periodic benefit cost	$	9		$	12

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended March 31,
	2018		2017
Interest cost	$	27	$	29
Net loss (gain)	26		22
Net periodic benefit cost	$	53	$	51

For the three months ended March 31, 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other income (expense), net on the Condensed Statements of Comprehensive Income. For the three months ended March 31, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because prior years’ costs were not considered material, they were not reclassified on the Condensed Statements of Comprehensive Income. See Note 1 for additional information.

Contributions

Contributions to the Defined Benefit Pension Plan are cash contributions made directly to the Pension Plan Trust account. Contributions to the Postretirement Healthcare and Supplemental Plans are made in the form of benefit payments. Contributions made for 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands):

	Contributions Three Months Ended March 31, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
Defined Benefit Pension Plan	$	—	$	1,795	$	1,789
Defined Benefit Postretirement Healthcare Plan	$	134	$	401	$	554
Supplemental Non-qualified Defined Benefit Plans	$	61	$	184	$	241

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Fair Value of Financial Instruments:

3 Months Ended

Mar. 31, 2018

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 2017 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:

	March 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	12	$	12	$	16	$	16
Long-term debt, including current maturities (b) (c)	$	339,930	$	429,001	$	339,895	$	446,978

_________________

(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:

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Supplemental Disclosure of Cash Flow Information

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Three months ended March 31,	2018			2017
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	7,556		$	10,998
Non-cash (decrease) to money pool notes receivable, net	$	(16,000	)	$	(7,000	)
Non-cash dividend to Parent	$	16,000		$	7,000
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(3,088	)	$	(3,014	)

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Commitment and Contingencies:

3 Months Ended

Mar. 31, 2018

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 2017 Annual Report on Form 10-K.

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Income Taxes:

3 Months Ended

Mar. 31, 2018

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. The Company remeasured deferred income taxes at the 21% federal tax rate as of December 31, 2017. We have made our best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Company’s future results of operations, cash flows or financial position. We revalued our deferred tax assets and liabilities as of December 31, 2017, which reflected our estimate of the impact of the TCJA. We will continue to evaluate subsequent regulations, clarifications and interpretations with the assumptions made, which could materially change our estimate.

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Managment's Statement (Policies)

3 Months Ended

Mar. 31, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Recently Issued and Adopted Accounting Standards

Recently Issued Accounting Standards

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 most leases, 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. Under the current guidance, 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. In January 2018, the FASB issued amendments to the new lease standard, ASU No. 2018-01, allowing an entity to elect not to assess whether certain land easements are, or contain, leases when transitioning to the new lease standard.

We currently expect to adopt this standard on January 1, 2019 and anticipate electing not to assess existing or expired land easements that were not previously accounted for as a lease when transitioning to the new standard. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor utility industry implementation guidance. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes relating to leases. We have selected and initiated implementation of a new lease software solution.

Recently Adopted Accounting Standards

Revenue from Contracts with Customers, ASU 2014-09

Effective January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and its related amendments (collectively known as ASC 606). Under this standard, revenue is recognized when a customer obtains control of promised goods or services in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We applied the five-step method outlined in the ASU to all in-scope revenue streams and elected the modified retrospective implementation method. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows. Implementation of the standard did not have a significant impact on the measurement or recognition of revenue; therefore, no cumulative adoption adjustment to the opening balance of Retained earnings at the date of initial application was necessary. The additional disclosures required by the ASU are included in Note 2.

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

Effective January 1, 2018, we adopted ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. The standard requires 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. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets was applied on a prospective basis. For our rate-regulated entities, we capitalize the other components of net periodic benefit costs into regulatory assets or regulatory liabilities and maintain a FERC-to-GAAP reporting difference for these capitalized costs. The presentation changes required for net periodic pension and post-retirement costs resulted in offsetting changes to Operating income and Other income. Implementation of the standard did not have a material impact on our financial position, results of operations or cash flows.

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

Effective January 1, 2018, we adopted 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. We implemented this standard effective January 1, 2018 using the retrospective transition method. This standard had no impact on our financial position, results of operations or cash flows.

Revenue Recognition, Policy

Revenues are recognized in an amount that reflects the consideration we expect to receive in exchange for goods or services, when control of the promised goods or services is transferred to our customers. Our primary types of revenue contracts are:

• Regulated electric utility services tariffs - Our regulated operations, as defined by ASC 980, provide services to regulated customers under rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Collectively, these rates, charges, terms and conditions are included in a tariff, which governs all aspects of the provision of our regulated services. Our regulated services primarily encompass single performance obligations material to the context of the contract for delivery of commodity electricity and electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the regulator-empowered statute to establish contractual rates between the utility and its customers. All of our regulated utility sales are subject to regulatory-approved tariffs.

• Power sales agreements - We have long-term wholesale power sales agreements with other load serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis as a member of the Western States Power Pool. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price, and is variable based on energy delivered.

The following table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments. Sales tax and other similar taxes are excluded from revenues.

	Three Months Ended March 31, 2018
	(in thousands)
Customer types:
Retail	$	50,641
Wholesale	9,050
Market - off-system sales	2,275
Transmission/Other	11,718
Revenue from contracts with customers	73,684
Other revenues	131
Total revenues	$	73,815
Timing of revenue recognition:
Services transferred at a point in time	—
Services transferred over time	73,684
Revenue from contracts with customers	$	73,684

The majority of the our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer.

Revenue Not in Scope of ASC 606

Other revenues included in the table above include revenue accounted for under separate accounting guidance, including lease revenue under ASC 840 and alternative revenue programs revenue under ASC 980.

Significant Judgments and Estimates

TCJA revenue reserve

The TCJA or “tax reform”, signed into law on December 22, 2017, reduced the federal corporate income tax rate from 35% to 21% effective for tax years beginning after December 31, 2017. Black Hills Power’s regulators have directed the utility to calculate the impact of tax reform on existing customer rates and tariffs caused by the income tax rate reduction. Until the regulators have a chance to review and approve these calculations, the utility continues to charge customers existing rates with the embedded 35% tax rate and estimate a reserve to revenue based on current discussions or filed applications with the regulators. We estimated and recorded a revenue reserve of approximately $3.1 million during the three months ended March 31, 2018.

Unbilled Revenue

Revenues attributable to energy delivered to customers but not yet billed are estimated and accrued, and the related costs are charged to expense. Factors influencing the determination of unbilled revenues may include estimates of delivered sales volumes based on weather information and customer consumption trends.

Contract Balances

The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable and is further discussed in Note 1 of our Notes to the Financial Statements of our 2017 Annual Report on Form 10-K Business Description. We do not typically incur costs that would be capitalized, to obtain or fulfill a contract.

Practical Expedients

Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice.

We have revenue contract performance obligations with similar characteristics, and we reasonably expect that the financial statement impact of applying the new revenue recognition guidance to a portfolio of contracts would not differ materially from applying this guidance to the individual contracts or performance obligations within the portfolio. Therefore, we have elected the portfolio approach in applying the new revenue guidance.

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Revenue (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table depicts the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments. Sales tax and other similar taxes are excluded from revenues.

	Three Months Ended March 31, 2018
	(in thousands)
Customer types:
Retail	$	50,641
Wholesale	9,050
Market - off-system sales	2,275
Transmission/Other	11,718
Revenue from contracts with customers	73,684
Other revenues	131
Total revenues	$	73,815
Timing of revenue recognition:
Services transferred at a point in time	—
Services transferred over time	73,684
Revenue from contracts with customers	$	73,684

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Accounts Receivable and Allowance For Doubtful Accounts (Tables)

3 Months Ended

Mar. 31, 2018

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:

	March 31, 2018			December 31, 2017
Accounts receivable trade	$	16,992		$	15,994
Unbilled revenues	12,772			13,280
Allowance for doubtful accounts	(262		)	(224		)
Receivables - customers, net	$	29,502		$	29,050

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Regulatory Accounting (Tables)

3 Months Ended

Mar. 31, 2018

Regulated Operations [Abstract]

Schedule of Regulatory Assets

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

	Maximum Amortization (in years)	March 31, 2018		December 31, 2017
Regulatory assets:
Unamortized loss on reacquired debt (a)	7	$	1,464	$	1,534
Deferred taxes on AFUDC (b)	45	5,050		5,095
Employee benefit plans(c)	12	19,723		19,465
Deferred energy and fuel cost adjustments - current (a)	1	17,912		19,602
Deferred taxes on flow through accounting	54	7,929		7,579
Decommissioning costs, net of amortization	6	9,738		10,252
Vegetation management, net of amortization	6	12,093		12,669
Other regulatory assets (a)	6	2,303		2,507
Total regulatory assets		$	76,212	$	78,703

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	49,580	$	44,056
Employee benefit plan costs and related deferred taxes (c)	12	6,808		6,808
Excess deferred income taxes	40	97,061		97,101
TCJA revenue reserve (d)	subject to approval	3,121		—
Other regulatory liabilities	13	1,033		890
Total regulatory liabilities		$	157,603	$	148,855

____________________

(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) As of March 31, 2018, the amortization period is yet to be determined and subject to approval by our regulators.

Schedule of Regulatory Liabilities

Regulatory liabilities:
Cost of removal for utility plant (a)	61	$	49,580	$	44,056
Employee benefit plan costs and related deferred taxes (c)	12	6,808		6,808
Excess deferred income taxes	40	97,061		97,101
TCJA revenue reserve (d)	subject to approval	3,121		—
Other regulatory liabilities	13	1,033		890
Total regulatory liabilities		$	157,603	$	148,855

____________________

(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) As of March 31, 2018, the amortization period is yet to be determined and subject to approval by our regulators.

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Related-Party Transactions (Tables)

3 Months Ended

Mar. 31, 2018

Related Party Transactions [Abstract]

Schedule of Related Party Accounts Receivable and Payable

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

	March 31, 2018		December 31, 2017
Receivables - affiliates	$	6,925	$	5,664
Accounts payable - affiliates	$	24,767	$	25,653

Schedule of Related Party Notes

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

	March 31, 2018		December 31, 2017
Money pool notes payable	$	13,541	$	13,397

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 March 31,
	2018			2017
Net interest income (expense)	$	(36	)	$	126

Schedule of Revenues and Purchases from Related Parties

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

	Three Months Ended March 31,
	2018		2017
Revenue:
Energy sold to Cheyenne Light	$	703	$	878
Rent from electric properties	$	3,678	$	1,272
Fuel and purchased power:
Purchases of coal from WRDC	$	4,067	$	4,280
Purchase of excess energy from Cheyenne Light	$	86	$	40
Purchase of renewable wind energy from Cheyenne Light - Happy Jack	$	641	$	606
Purchase of renewable wind energy from Cheyenne Light - Silver Sage	$	1,093	$	1,019
Gas transportation service agreement:
Gas transportation service agreement with Cheyenne Light for firm and interruptible gas transportation	$	96	$	99
Corporate support:
Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings	$	7,606	$	6,611

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Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2018

Defined Benefit Plan [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 March 31,
	2018			2017
Service cost	$	129		$	136
Interest cost	548			585
Expected return on plan assets	(886		)	(897		)
Prior service cost	11			11
Net loss (gain)	516			307
Net periodic benefit cost	$	318		$	142

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 March 31,
	2018			2017
Service cost	$	48		$	52
Interest cost	45			44
Prior service cost (benefit)	(84		)	(84		)
Net periodic benefit cost	$	9		$	12

Supplemental Non-qualified Defined Benefit Plans

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

	Three Months Ended March 31,
	2018		2017
Interest cost	$	27	$	29
Net loss (gain)	26		22
Net periodic benefit cost	$	53	$	51

Schedule of Defined Benefit Plans Contributions

Contributions made for 2018 and anticipated contributions for 2018 and 2019 are as follows (in thousands):

	Contributions Three Months Ended March 31, 2018		Remaining Anticipated Contributions for 2018		Anticipated Contributions for 2019
Defined Benefit Pension Plan	$	—	$	1,795	$	1,789
Defined Benefit Postretirement Healthcare Plan	$	134	$	401	$	554
Supplemental Non-qualified Defined Benefit Plans	$	61	$	184	$	241

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2018

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:

	March 31, 2018				December 31, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Cash and cash equivalents (a)	$	12	$	12	$	16	$	16
Long-term debt, including current maturities (b) (c)	$	339,930	$	429,001	$	339,895	$	446,978

_________________

(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)

3 Months Ended

Mar. 31, 2018

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

Three months ended March 31,	2018			2017
	(in thousands)
Non-cash investing and financing activities -
Property, plant and equipment acquired with accrued liabilities	$	7,556		$	10,998
Non-cash (decrease) to money pool notes receivable, net	$	(16,000	)	$	(7,000	)
Non-cash dividend to Parent	$	16,000		$	7,000
Cash (paid) refunded during the period for -
Interest (net of amounts capitalized)	$	(3,088	)	$	(3,014	)

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Management Statement (Details) - USD ($)	Mar. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Cumulative adoption adjustment to the opening balance of Retained earnings	$ 328,260,000	$ 332,499,000
Accounting Standards Update 2014-09
Disaggregation of Revenue [Line Items]
Cumulative adoption adjustment to the opening balance of Retained earnings	$ 0

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Revenue (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 73,684
Other revenues	131
Total revenues	73,815	$ 73,794
Services transferred at a point in time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	0
Services transferred over time
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	73,684
Retail
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	50,641
Wholesale
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	9,050
Market - off-system sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,275
Transmission/Other
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 11,718

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Revenue: Significant Judgements and Estimates (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Revenue from Contract with Customer [Abstract]
Estimated and recorded revenue reduction from TCJA tax benefits	$ 3.1

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Accounts Receivable and Allowance For Doubtful Accounts (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Accounts Receivable, Net [Abstract]
Accounts receivable trade	$ 16,992	$ 15,994
Unbilled revenues	12,772	13,280
Allowance for doubtful accounts	(262)	(224)
Receivables - customers, net	$ 29,502	$ 29,050

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Regulatory Accounting: Regulatory Assets (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Total regulatory assets	$ 76,212	$ 78,703
Unamortized loss on reacquired debt
Regulatory Assets [Line Items]
Maximum Amortization (in years)	7 years
Total regulatory assets	$ 1,464	1,534
Deferred taxes on AFUDC
Regulatory Assets [Line Items]
Maximum Amortization (in years)	45 years
Total regulatory assets	$ 5,050	5,095
Employee benefit plans
Regulatory Assets [Line Items]
Maximum Amortization (in years)	12 years
Total regulatory assets	$ 19,723	19,465
Deferred energy and fuel cost adjustments - current
Regulatory Assets [Line Items]
Maximum Amortization (in years)	1 year
Total regulatory assets	$ 17,912	19,602
Deferred taxes on flow through accounting
Regulatory Assets [Line Items]
Maximum Amortization (in years)	54 years
Total regulatory assets	$ 7,929	7,579
Decommissioning costs, net of amortization
Regulatory Assets [Line Items]
Maximum Amortization (in years)	6 years
Total regulatory assets	$ 9,738	10,252
Vegetation Management [Member]
Regulatory Assets [Line Items]
Maximum Amortization (in years)	6 years
Total regulatory assets	$ 12,093	12,669
Other regulatory assets
Regulatory Assets [Line Items]
Maximum Amortization (in years)	6 years
Total regulatory assets	$ 2,303	$ 2,507

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Regulatory Accounting: Regulatory Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 157,603	$ 148,855
Cost of removal for utility plant
Regulatory Liabilities [Line Items]
Maximum Amortization (in years)	61 years
Total regulatory liabilities	$ 49,580	44,056
Employee benefit plan costs and related deferred taxes
Regulatory Liabilities [Line Items]
Maximum Amortization (in years)	12 years
Total regulatory liabilities	$ 6,808	6,808
Excess deferred income taxes
Regulatory Liabilities [Line Items]
Maximum Amortization (in years)	40 years
Total regulatory liabilities	$ 97,061	97,101
TCJA revenue reduction
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,121	0
Other regulatory liabilities
Regulatory Liabilities [Line Items]
Maximum Amortization (in years)	13 years
Total regulatory liabilities	$ 1,033	$ 890

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Regulatory Accounting: TCJA Revenue Reduction (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($)
Regulated Operations [Abstract]
Estimated and recorded revenue reduction from TCJA tax benefits	$ 3.1

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Related-Party Transactions (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Related Party Transaction [Line Items]
Receivables - affiliates	$ 6,925		$ 5,664
Accounts payable - affiliates	$ 24,767		25,653
Related Party Transaction, Utility Money Pool Interest Rate	2.54%
Money pool notes payable	$ 13,541		$ 13,397
Parent
Related Party Transaction [Line Items]
Non-cash dividend to Parent	$ 16,000	$ 7,000
Commitment fee percentage	1.00%
Utility Money Pool
Related Party Transaction [Line Items]
Net interest income (expense)	$ (36)	126
Subsidiary of Common Parent
Related Party Transaction [Line Items]
Non-cash (decrease) to money pool notes receivable, net	(16,000)	(7,000)
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	96	99
Subsidiary of Common Parent | Purchases of coal from WRDC
Related Party Transaction [Line Items]
Fuel and purchased power	4,067	4,280
Subsidiary of Common Parent | Purchase of excess energy from Cheyenne Light
Related Party Transaction [Line Items]
Fuel and purchased power	86	40
Subsidiary of Common Parent | Purchase of renewable wind energy from Cheyenne Light - Happy Jack
Related Party Transaction [Line Items]
Fuel and purchased power	641	606
Subsidiary of Common Parent | Purchase of renewable wind energy from Cheyenne Light - Silver Sage
Related Party Transaction [Line Items]
Fuel and purchased power	1,093	1,019
Subsidiary of Common Parent | Energy sold to Cheyenne Light
Related Party Transaction [Line Items]
Revenue	703	878
Subsidiary of Common Parent | Rent from electric properties
Related Party Transaction [Line Items]
Revenue	3,678	1,272
Subsidiary of Common Parent | Corporate support services and fees from Parent, Black Hills Service Company and Black Hills Utility Holdings
Related Party Transaction [Line Items]
Fuel and purchased power	$ 7,606	$ 6,611

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Employee Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Pension Plan
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 129	$ 136
Interest cost	548	585
Expected return on plan assets	(886)	(897)
Prior service cost (benefit)	11	11
Net loss (gain)	516	307
Net periodic benefit cost	318	142
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions made by Employer	0
Remaining Anticipated Contributions for Current Year	1,795
Anticipated Contributions for Next Year	1,789
Defined Benefit Postretirement Healthcare Plan
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	48	52
Interest cost	45	44
Prior service cost (benefit)	(84)	(84)
Net periodic benefit cost	9	12
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions made by Employer	134
Remaining Anticipated Contributions for Current Year	401
Anticipated Contributions for Next Year	554
Supplemental Non-qualified Defined Benefit Plans
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Interest cost	27	29
Net loss (gain)	26	22
Net periodic benefit cost	53	$ 51
Payment for Pension and Other Postretirement Benefits [Abstract]
Contributions made by Employer	61
Remaining Anticipated Contributions for Current Year	184
Anticipated Contributions for Next Year	$ 241

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Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	$ 12	$ 16	$ 1,127	$ 234
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, carrying amount	12	16
Long-term debt, including current maturities, carrying amount	339,930	339,895
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents, fair value	12	16
Long-term debt, including current maturities, fair value	$ 429,001	$ 446,978

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Supplemental Disclosure of Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Noncash Investing and Financing Items [Abstract]
Property, plant and equipment acquired with accrued liabilities	$ 7,556	$ 10,998
Interest and Income Taxes Paid Net [Abstract]
Interest (net of amounts capitalized)	(3,088)	(3,014)
Subsidiary of Common Parent
Noncash Investing and Financing Items [Abstract]
Non-cash (decrease) to money pool notes receivable, net	(16,000)	(7,000)
Parent
Noncash Investing and Financing Items [Abstract]
Non-cash dividend to Parent	$ 16,000	$ 7,000