Black Hills Power 10-Q 4 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

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	12,400
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Document Fiscal Year End Focus	2,018
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

Condensed Statements of Compreh

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

Condensed Statements of Compre3

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)

Condensed Balance Sheets

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

Condensed Balance Sheets Parent

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

Condensed Statements of Cash Fl

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

Management's Statement_

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.

Revenue_

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.

Accounts Receivable and Allowan

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

Regulatory Accounting_

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.

Related-Party Transactions_

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 a mong 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.

Employee Benefit Plans_

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

Fair Value of Financial Instrum

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.

Supplemental Disclosure of Cash

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 )

Commitment and Contingencies_

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.

Income Taxes_

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.

Managment's Statement (Policies

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.

Revenue (Tables)

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

Accounts Receivable and Allow19

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

Regulatory Accounting (Tables)

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.

Related-Party Transactions (Tab

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

Employee Benefit Plans (Tables)

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

Fair Value of Financial Instr23

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.

Supplemental Disclosure of Ca24

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 )

Management Statement (Details)

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

Revenue (Details)

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

Revenue_ Significant Judgements

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

Accounts Receivable and Allow28

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

Regulatory Accounting_ Regulato

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

Regulatory Accounting_ Regula30

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

Regulatory Accounting_ TCJA Rev

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

Related-Party Transactions (Det

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

Employee Benefit Plans (Details

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

Fair Value of Financial Instr34

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

Supplemental Disclosure of Ca35

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