Black Hills (BKH) 10-K 26 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jan. 31, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	BLACK HILLS CORP /SD/
Entity Central Index Key	1,130,464
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Current Fiscal Year End Date	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		53,544,761
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Public Float			$ 3,563,087,139

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenue:
Revenue	$ 1,680,266	$ 1,538,916	$ 1,261,322
Operating expenses:
Fuel, purchased power and cost of natural gas sold	563,288	499,132	456,887
Operations and maintenance	454,605	426,603	323,809
Depreciation, depletion and amortization	188,246	175,533	126,533
Taxes - property and production	51,578	46,160	40,060
Other operating expenses	5,813	55,307	13,613
Total operating expenses	1,263,530	1,202,735	960,902
Operating income	416,736	336,181	300,420
Interest charges -
Interest expense incurred (including amortization of debt issuance costs, premiums and discounts)	(140,756)	(139,447)	(86,226)
Allowance for funds used during construction - borrowed	2,415	2,981	1,250
Capitalized interest	223	356	326
Interest income	1,016	1,429	1,621
Allowance for funds used during construction - equity	2,321	3,270	897
Other expense	(1,559)	(626)	(158)
Other income	1,346	1,750	2,075
Total other income (expense)	(134,994)	(130,287)	(80,215)
Income before income taxes	281,742	205,894	220,205
Income tax benefit (expense)	(73,367)	(59,101)	(78,657)
Income (loss) from continuing operations	208,375	146,793	141,548
Net (loss) from discontinued operations	(17,099)	(64,162)	(173,659)
Net income (loss)	191,276	82,631	(32,111)
Net income attributable to noncontrolling interest	(14,242)	(9,661)	0
Net income (loss) available for common stock	177,034	72,970	(32,111)
Amounts attributable to common shareholders:
Net income from continuing operations	194,133	137,132	141,548
Net (loss) from discontinued operations	(17,099)	(64,162)	(173,659)
Net income (loss) available for common stock	$ 177,034	$ 72,970	$ (32,111)
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations, Basic (usd per share)	$ 3.65	$ 2.64	$ 3.12
(Loss) from discontinued operations per share, Basic (usd per share)	(0.32)	(1.23)	(3.83)
Total earnings (loss) per share of common stock, Basic (usd per share)	3.33	1.41	(0.71)
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations, Diluted (usd per share)	3.52	2.57	3.12
(Loss) from discontinued operations, Diluted (usd per share)	(0.31)	(1.20)	(3.83)
Total earnings (loss) per share of common stock, Diluted (usd per share)	$ 3.21	$ 1.37	$ (0.71)
Weighted average common shares outstanding:
Basic	53,221	51,922	45,288
Diluted	55,120	53,271	45,288

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net income (loss)	$ 191,276	$ 82,631	$ (32,111)
Other Comprehensive (Income) Loss, Defined Benefit Plan, before Reclassification Adjustment, after Tax [Abstract]
Benefit plan liability adjustments - net gain (loss) (net of tax of $1,030, $757 and $(1,375), respectively)	(1,890)	(1,738)	2,657
Benefit plan liability adjustments - prior service (costs) (net of tax of $0, $107 and $0, respectively)	0	(247)	0
Reclassification adjustment of benefit plan liability - net gain (loss) (net of tax of $(585), $(600) and $(972), respectively)	1,072	1,378	1,850
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $69, $67 and $88, respectively)	(128)	(154)	(150)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]
Other comprehensive income (loss), net of tax	681	(25,828)	5,989
Comprehensive income (loss)	191,957	56,803	(26,122)
Net income attributable to noncontrolling interest	(14,242)	(9,661)	0
Comprehensive income (loss) available for common stock	177,715	47,142	(26,122)
Interest rate swaps
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]
Net unrealized gains (losses) net of tax	0	(20,302)	2,290
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax	1,912	2,534	2,299
Commodity derivatives
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax [Abstract]
Net unrealized gains (losses) net of tax	231	(361)	5,884
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax	$ (516)	$ (6,938)	$ (8,841)

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Benefit plan liability adjustments - net gain (loss), Tax	$ 1,030	$ 757	$ (1,375)
Benefit plan liability adjustments - prior service (costs), Tax	0	107	0
Reclassification adjustment of benefit plan liability - net gain (loss) tax	(585)	(600)	(972)
Reclassification adjustment of benefit plan liability - prior service cost, tax	69	67	88
Interest Rate Swap
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax	0	10,920	(598)
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax	(1,029)	(1,365)	(1,348)
Commodity Contract
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax	(135)	212	(3,898)
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax	$ 154	$ 4,067	$ 5,619

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 15,420	$ 13,518
Restricted cash and equivalents	2,820	2,274
Accounts receivable, net	248,330	259,311
Materials, supplies and fuel	113,283	103,606
Derivative assets, current	304	3,985
Regulatory assets, current	81,016	49,260
Other current assets	25,367	23,928
Current assets held for sale	84,242	10,932
Total current assets	570,782	466,814
Investments	13,090	12,561
Property, plant and equipment	5,567,518	5,315,296
Less accumulated depreciation and depletion	(1,026,088)	(929,119)
Total property, plant and equipment, net	4,541,430	4,386,177
Other assets:
Goodwill	1,299,454	1,299,454
Intangible assets, net	7,559	8,392
Derivative assets, non-current	0	222
Regulatory assets, non-current	216,438	246,882
Other assets, non-current	10,149	11,508
Noncurrent assets held for sale	0	109,763
Total other assets, non-current	1,533,600	1,676,221
TOTAL ASSETS	6,658,902	6,541,773
Current liabilities:
Accounts payable	160,887	152,129
Accrued liabilities	219,462	235,548
Derivative liabilities, current	2,081	1,104
Accrued income tax, net	1,022	12,552
Regulatory liabilities, current	6,832	13,067
Notes payable	211,300	96,600
Current maturities of long-term debt	5,743	5,743
Current liabilities held for sale	41,774	11,189
Total current liabilities	649,101	527,932
Long-term debt, net of current maturities	3,109,400	3,211,189
Deferred credits and other liabilities:
Deferred income tax liabilities, net	336,520	561,935
Regulatory liabilities, non-current	478,294	193,689
Benefit plan liabilities	159,646	173,682
Other deferred credits and other liabilities	105,735	115,883
Noncurrent liabilities held for sale	0	23,034
Total deferred credits and other liabilities	1,080,195	1,068,223
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)
Redeemable noncontrolling interest	0	4,295
Stockholders’ equity -
Common stock $1 par value; 100,000,000 shares authorized; issued: 53,579,986 and 53,397,467, respectively	53,580	53,397
Additional paid-in capital	1,150,285	1,138,982
Retained earnings	548,617	457,934
Treasury stock at cost - 39,064 and 15,258, respectively	(2,306)	(791)
Accumulated other comprehensive income (loss)	(41,202)	(34,883)
Total stockholders’ equity	1,708,974	1,614,639
Noncontrolling interest	111,232	115,495
Total equity	1,820,206	1,730,134
TOTAL LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND TOTAL EQUITY	$ 6,658,902	$ 6,541,773

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1
Treasury Stock, Shares	39,064	15,258
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	53,579,986	53,397,467

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income (loss)	$ 191,276	$ 82,631	$ (32,111)
(Income) loss from discontinued operations, net of tax	17,099	64,162	173,659
Income (loss) from continuing operations	208,375	146,793	141,548
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	188,246	175,533	126,533
Deferred financing cost amortization	8,261	6,180	6,364
Stock compensation	7,626	10,885	4,076
Deferred income taxes	80,992	82,704	74,704
Employee benefit plans	10,141	14,291	20,616
Other adjustments, net	(4,773)	(5,519)	(4,872)
Change in certain operating assets and liabilities:
Materials, supplies and fuel	(10,089)	1,211	7,216
Accounts receivable, unbilled revenues and other current assets	4,534	(27,172)	33,255
Accounts payable and other current liabilities	(28,222)	(33,023)	(74,748)
Regulatory assets	(15,407)	3,614	21,883
Regulatory liabilities	(4,536)	(14,082)	1,675
Contributions to defined benefit pension plans	(27,700)	(14,200)	(10,200)
Interest rate swap settlement	0	(28,820)	0
Other operating activities, net	(8,418)	(660)	(9,033)
Net cash provided by operating activities of continuing operations	409,030	317,735	339,017
Net cash provided by (used in) operating activities of discontinued operations	19,231	2,744	85,366
Net cash provided by operating activities	428,261	320,479	424,383
Investing activities:
Property, plant and equipment additions	(326,010)	(454,952)	(266,375)
Acquisition of net assets, net of long-term debt assumed	0	(1,124,238)	(21,970)
Other investing activities	465	(1,139)	(444)
Net cash (used in) investing activities of continuing operations	(325,545)	(1,580,329)	(288,789)
Net cash provided by (used in) investing activities of discontinued operations	7,881	(8,413)	(187,600)
Net cash provided by (used in) investing activities	(317,664)	(1,588,742)	(476,389)
Financing activities:
Dividends paid on common stock	(96,744)	(87,570)	(72,604)
Common stock issued	4,408	121,619	248,759
Net increase (decrease) in commercial paper and short-term borrowings	114,700	19,800	1,800
Long-term debt - issuance	0	1,767,608	300,000
Long-term debt - repayments	(105,743)	(1,164,308)	(275,000)
Sale of noncontrolling interest	0	216,370	0
Distributions to noncontrolling interests	(18,397)	(9,561)	0
Equity units - issuance	0	0	290,030
Other financing activities	(6,919)	(22,960)	(9,283)
Net cash provided by (used in) financing activities	(108,695)	840,998	483,702
Net change in cash and cash equivalents	1,902	(427,265)	431,696
Cash and cash equivalents:
Cash and cash equivalents beginning of year	13,518	440,783	9,087
Cash and cash equivalents end of year	$ 15,420	$ 13,518	$ 440,783

Consolidated Statements Of Equi

Consolidated Statements Of Equity - USD ($) $ in Thousands	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Total equity at Dec. 31, 2014	$ 1,353,884	$ 44,714	$ (1,875)	$ 748,840	$ 577,249	$ (15,044)
Common Stock, Shares, Outstanding at Dec. 31, 2014		44,714,072
Treasury Stock, Shares at Dec. 31, 2014			42,226
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss) available for common stock	(32,111)				(32,111)
Net income attributable to noncontrolling interest	0
Net income (loss)	(32,111)
Other comprehensive income (loss), net of tax	5,989					5,989
Dividends on common stock	(72,604)				(72,604)
Share-based compensation	4,240	$ 127	$ (13)	4,126
Share-based compensation, Shares		126,765	(2,506)
Issuance of common stock	254,581	$ 6,325		248,256
Issuance of common stock, shares		6,325,000
Issuance costs	(17,926)			(17,926)
Premium on Equity Units	(33,118)			(33,118)
Dividend reinvestment and stock purchase plan	2,957	$ 66		2,891
Dividend reinvestment and stock purchase plan, shares		66,024
Other stock transactions	(25)			(25)
Total equity at Dec. 31, 2015	$ 1,465,867	$ 51,232	$ (1,888)	953,044	472,534	(9,055)
Common Stock, Shares, Outstanding at Dec. 31, 2015		51,231,861
Treasury Stock, Shares at Dec. 31, 2015			39,720
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.62
Net income (loss) available for common stock	$ 72,970				72,970
Net income attributable to noncontrolling interest	(9,661)						$ 9,661
Net income (loss)	82,631
Other comprehensive income (loss), net of tax	(25,828)					(25,828)
Dividends on common stock	(87,570)				(87,570)
Share-based compensation	5,479	$ 146	$ 668	4,665
Share-based compensation, Shares		145,634	(16,165)
Issuance of common stock	119,990	$ 1,969		118,021
Issuance of common stock, shares		1,968,738
Issuance costs	(1,566)			(1,566)
Dividend reinvestment and stock purchase plan	2,983	$ 50		2,933
Dividend reinvestment and stock purchase plan, shares		51,234
Other stock transactions	476		$ 429	47
Other stock transactions, shares			(8,297)
Sale of noncontrolling interest	177,233			61,838			115,395
Redemption of and distributions to noncontrolling interest	(9,561)						(9,561)
Total equity at Dec. 31, 2016	$ 1,730,134	$ 53,397	$ (791)	1,138,982	457,934	(34,883)	115,495
Common Stock, Shares, Outstanding at Dec. 31, 2016		53,397,467
Treasury Stock, Shares at Dec. 31, 2016	15,258		15,258
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.68
Net income (loss) available for common stock	$ 177,034				177,034
Net income attributable to noncontrolling interest	(14,242)						14,242
Net income (loss)	191,276
Other comprehensive income (loss), net of tax	681					681
Reclassification of certain tax effects from AOCI	0				7,000	(7,000)
Dividends on common stock	(96,744)				(96,744)
Share-based compensation	7,567	$ 134	$ (1,515)	8,948
Share-based compensation, Shares		134,266	23,806
Tax effect of share-based compensation	3,717			533	3,184
Issuance costs	(189)			(189)
Dividend reinvestment and stock purchase plan	3,156	$ 49		3,107
Dividend reinvestment and stock purchase plan, shares		48,253
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests				(1,096)	209
Redemption of and distributions to noncontrolling interest	(19,392)						(18,505)
Total equity at Dec. 31, 2017	$ 1,820,206	$ 53,580	$ (2,306)	$ 1,150,285	$ 548,617	$ (41,202)	$ 111,232
Common Stock, Shares, Outstanding at Dec. 31, 2017		53,579,986
Treasury Stock, Shares at Dec. 31, 2017	39,064		39,064
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.81

Business Description And Signif

Business Description And Significant Accounting Policies:	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business Description and Significant Accounting Policies	BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Corporation is a customer-focused, growth-oriented, vertically-integrated utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana. Our Gas Utilities Segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska. All of our non-utility business segments support our electric utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5 . On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90% of our oil and gas properties. We have executed agreements to sell all our operated properties and have only non-operated assets left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. The consolidated financial statements and accompanying notes for current and prior periods have been restated. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21 . Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5 . Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information. Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if so, if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12 . Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Equivalents We maintain cash accounts for various specified purposes. Therefore, we classify these amounts as restricted cash. Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining and Power Generation business segments consists of amounts due from sales of coal, natural gas, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. Following is a summary of accounts receivable as of December 31 (in thousands): 2017 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 39,347 $ 36,384 $ (586 ) $ 75,145 Gas Utilities 81,256 88,967 (2,495 ) 167,728 Power Generation 1,196 — — 1,196 Mining 2,804 — — 2,804 Corporate 1,457 — — 1,457 Total $ 126,060 $ 125,351 $ (3,081 ) $ 248,330 2016 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 41,730 $ 36,463 $ (353 ) $ 77,840 Gas Utilities 88,168 88,329 (2,026 ) 174,471 Power Generation 1,420 — — 1,420 Mining 3,352 — — 3,352 Corporate 2,228 — — 2,228 Total $ 136,898 $ 124,792 $ (2,379 ) $ 259,311 Revenue Recognition Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Natural gas and crude oil sales included in discontinued operations are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. BHEP records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment. Materials, Supplies and Fuel The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2017 2016 Materials and supplies $ 69,732 $ 64,852 Fuel - Electric Utilities 2,962 3,667 Natural gas in storage 40,589 35,087 Total materials, supplies and fuel $ 113,283 $ 103,606 Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2017 2016 Accrued employee compensation, benefits and withholdings $ 52,467 $ 54,553 Accrued property taxes 42,029 37,379 Customer deposits and prepayments 44,420 55,191 Accrued interest 33,822 33,982 CIAC current portion 1,552 1,575 Other (none of which is individually significant) 45,172 52,868 Total accrued liabilities $ 219,462 $ 235,548 Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity and both are in the fourth quarter of the year. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital and long-term earnings and merger multiples for comparable companies. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results. See Note 5 for additional business segment information. Goodwill at our Electric Utilities primarily arose from Colorado Electric, acquired in the Aquila acquisition, which allocated approximately $246 million , or 72% of the transaction to Colorado Electric. Goodwill at our Gas Utilities is primarily from the SourceGas Acquisition, which was allocated entirely to the Gas Utilities adding $940 million in goodwill and the Aquila Transaction, which allocated approximately $94 million , or 28% of the transaction, to the Gas Utilities. We believe that the goodwill reflects the inherent value of the relatively stable, long-lived cash flows of the regulated electric and gas utility businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our utilities. Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Ending balance at December 31, 2015 $ 248,479 $ 102,515 $ 8,765 $ 359,759 Additions (a) — 939,695 — 939,695 Ending balance at December 31, 2016 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Additions — — — — Ending balance at December 31, 2017 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 _________________ (a) Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information. Our intangible assets represent easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 2 years to 40 years . Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2017 2016 2015 Intangible assets, net, beginning balance $ 8,392 $ 3,380 $ 3,176 Additions — 5,522 434 Amortization expense (a) (833 ) (510 ) (230 ) Intangible assets, net, ending balance $ 7,559 $ 8,392 $ 3,380 _________________ (a) Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years. Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting. Additional information is included in Note 8 and 21 . Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives Electric Utilities and Gas Utilities Segments: • The commodity contracts for the Electric and Gas Utilities, valued using the market approach, include exchange-traded futures, options, basis swaps and over-the-counter swaps (Level 2) for natural gas contracts. For exchanged-traded futures, options and basis swap Level 2 assets and liabilities, fair value was derived using broker quotes validated by the Chicago Mercantile Exchange pricing for similar instruments. For over-the-counter swaps and option Level 2 assets and liabilities, fair value was derived from, or corroborated by, observable market pricing data. In addition, the fair value for the over-the-counter swaps and option derivatives include a CVA component. The CVA considers the fair value of the derivative and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. Corporate Segment: • Interest rate swaps are valued using the market valuation approach. We establish fair value by obtaining price quotes directly from the counterparty which are based on the floating three-month LIBOR curve for the term of the contract. The fair value obtained from the counterparty is then validated by utilizing a nationally recognized service that obtains observable inputs to compute fair value for the same instrument. In addition, the fair value for the interest rate swap derivatives includes a CVA component. The CVA considers the fair value of the interest rate swap and the probability of default based on the life of the contract. For the probability of a default component, we utilize observable inputs supporting Level 2 disclosure by using our credit default spread, if available, or a generic credit default spread curve that takes into account our credit ratings. We have no interest rate swaps as of December 31, 2017. Additional information is included in Note 10 . Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, if they qualify for certain exemptions, including the normal purchases and normal sales exemption, or if regulatory rulings require a different accounting treatment. Changes in the fair value for derivative instruments that do not meet any of these criteria are recognized in the income statement as they occur. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Revenues and expenses on contracts that qualify as derivatives may be elected under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our electric and gas utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. Deferred Financing Costs Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. Regulatory Accounting Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material. We had the following regulatory assets and liabilities as of December 31 (in thousands): Maximum Amortization (in years) 2017 2016 Regulatory assets Deferred energy and fuel cost adjustments - current (a) 1 $ 20,187 $ 17,491 Deferred gas cost adjustments (a) 1 31,844 15,329 Gas price derivatives (a) 3 11,935 8,843 Deferred taxes on AFUDC (b) 45 7,847 15,227 Employee benefit plans (c) 12 109,235 108,556 Environmental (a) subject to approval 1,031 1,108 Asset retirement obligations (a) 44 517 505 Loss on reacquired debt (a) 30 20,667 22,266 Renewable energy standard adjustment (a) 5 1,088 1,605 Deferred taxes on flow through accounting (c) 54 26,978 37,498 Decommissioning costs 10 13,287 16,859 Gas supply contract termination (a) 4 20,001 26,666 Other regulatory assets (a) 30 32,837 24,189 $ 297,454 $ 296,142 Regulatory liabilities Deferred energy and gas costs (a) 1 $ 3,427 $ 10,368 Employee benefit plan costs and related deferred taxes (c) 12 40,629 68,654 Cost of removal (a) 44 130,932 118,410 Excess deferred income taxes (c) (d) 40 301,553 62 Revenue subject to refund 1 1,488 2,485 Other regulatory liabilities (c) 25 7,097 6,777 $ 485,126 $ 206,756 __________ (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) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018. Regulatory assets represent items we expect to recover from customers through probable future rates. Deferred Energy and Fuel Cost Adjustments - Current - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our electric utility customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state commission. Our electric and gas utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state utility commissions. Deferred Gas Cost Adjustment - Our regulated gas utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic estimates of future gas costs based on market forecasts with state utility commissions. Gas Price Derivatives - Our regulated utilities, as allowed or required by state utility commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. The 3-year term represents the maximum forward term hedged. Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax pu

Acquisition_

Acquisition:	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisition	ACQUISITION Acquisition of SourceGas On February 12, 2016, Black Hills Corporation acquired SourceGas, pursuant to the purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion , including the assumption of $760 million in debt at closing. The purchase price was subject to post-closing adjustments for capital expenditures, indebtedness and working capital. Post-closing adjustments of approximately $11 million were agreed to and received from the sellers in June 2016. SourceGas is a 100% owned subsidiary of Black Hills Utility Holdings, Inc., a wholly-owned subsidiary of Black Hills Corporation and has been renamed Black Hills Gas Holdings, LLC. Black Hills Gas Holdings primarily operates four regulated natural gas utilities serving approximately 429,000 customers in Arkansas, Colorado, Nebraska and Wyoming, and a 512 -mile regulated intrastate natural gas transmission pipeline in Colorado. Cash consideration of $1.135 billion paid on February 12, 2016 to close the SourceGas Acquisition included net proceeds of approximately $536 million from the November 23, 2015 issuance of 6.325 million shares of our common stock, 5.98 million equity units, and $546 million in net proceeds from our debt offerings on January 13, 2016. We funded the cash consideration and out-of-pocket expenses payable with the SourceGas Acquisition using the proceeds listed above, cash on hand, and draws under our revolving credit facility. In connection with the acquisition, the Company recorded pre-tax, incremental acquisition costs of approximately $45 million and $10 million for the years ending December 31, 2016 and 2015, respectively. These costs consisted of transaction costs, professional fees, employee-related expenses and other miscellaneous costs. The costs are recorded primarily in Other operating expenses and Interest expense on the Consolidated Statements of Income (Loss). Our consolidated operating results for the year ended December 31, 2016 include revenues of $348 million and net income (loss) of $15 million , attributable to SourceGas for the period from February 12 through December 31, 2016 . The SourceGas operating results are reported in our Gas Utilities segment. We believe the SourceGas Acquisition enhances Black Hills Corporation’s utility growth strategy, providing greater operating scale, driving more efficient delivery of services and benefiting customers. We accounted for the SourceGas Acquisition in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. Substantially all of SourceGas’ operations are subject to the rate-setting authority of state regulatory commissions, and are accounted for in accordance with GAAP for regulated operations. SourceGas’ assets and liabilities subject to rate setting provisions provide revenues derived from costs, including a return on investment of assets and liabilities included in rate base. As such, the fair value of these assets and liabilities equal their historical net book values. The final purchase price allocation of the fair value of the assets acquired and liabilities assumed is included in the table below. The cash consideration paid of $1.124 billion , net of long-term debt assumed of $760 million and a working capital adjustment received of approximately $11 million , resulted in goodwill of $940 million . We had up to one year from the acquisition date to finalize the purchase price allocation. The working capital adjustment received in 2016 of $11 million reflected changes in valuation estimates for intangible assets, accrued liabilities and deferred taxes. Approximately $252 million of the goodwill balance is amortizable for tax purposes, relating to the partnership interests that were directly acquired in the transaction. The remainder of the goodwill balance is not amortizable for tax purposes. Goodwill generated from the acquisition reflects the benefits of increased operating scale and organic growth opportunities. (in thousands) Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration paid, net of working capital adjustment received $ 1,124,238 Allocation of Purchase Price: Current Assets $ 112,983 Property, plant & equipment, net 1,058,093 Goodwill 939,695 Deferred charges and other assets, excluding goodwill 133,299 Current liabilities (172,454 ) Long-term debt (758,874 ) Deferred credits and other liabilities (188,504 ) Total consideration paid, net of working-capital adjustment received $ 1,124,238 Conditions of SourceGas Acquisition Regulatory Approval The acquisition was subject to regulatory approvals from the public utility commissions in Arkansas (APSC), Colorado (CPUC), Nebraska (NPSC), and Wyoming (WPSC). Approvals were obtained from all commissions, subject to various conditions as set forth below: The APSC order includes a twelve -month base rate moratorium, an annual $0.25 million customer credit for a term of up to five years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate review, as well as various other terms and reporting requirements. The CPUC order includes a two -year base rate moratorium for our regulated transmission and wholesale natural gas provider, a three -year base rate moratorium for our regulated gas distribution utility, an annual $0.2 million customer credit for a term of up to five -years or until we file the next rate review, whichever comes first, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate case, as well as various other terms and reporting requirements. The NPSC order includes a three -year base rate moratorium, a three -year continuation of the Choice Gas Program, and provides the Company recovery of a portion of specific labor synergies at the time of the next base rate review, as well as various other terms and reporting requirements. The WPSC order includes a three -year continuation of the Choice Gas Program, as well as various other terms and reporting requirements. All four orders also disallowed recovery of goodwill and transaction costs. Recovery of transition costs is disallowed in Arkansas, Colorado and Nebraska. However, Wyoming allows for request of recovery of transition costs. Transition costs are those non-recurring costs related to the transition and integration of SourceGas. In the conditions mentioned above, the orders that include base rate moratoriums over a specified period of time do not impact our ability to adjust rates through riders or gas supply cost recovery mechanisms as allowed under the current enacted state tariffs. In certain cases, we may file for leave to increase general base rates and/or cost of sales recovery limited to material adverse changes, but only if there are changes in law or regulations or the occurrence of other extraordinary events outside of our control which result in a material adverse change in revenues, revenue requirement and/or increase in operating costs. Settlement of Gas Supply Contract On April 29, 2016, we settled for $40 million , a former SourceGas contract that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. This contract’s intangible negative fair value is included with Current liabilities in the purchase price allocation. Approximately 75% of these purchases were committed to distribution customers in Nebraska, Colorado and Wyoming, which are subject to cost recovery mechanisms, while the remaining 25% was not subject to regulatory recovery. The prices to be paid under this contract varied, ranging from $6 to $8 per MMBtu at the time of acquisition and exceeded market prices. We applied for and were granted approval to terminate this agreement from the NPSC, CPUC and WPSC, on the basis that the agreement was not beneficial to customers in the long term. We received written orders allowing recovery of the net buyout costs associated with the contract termination that were allocated to regulated subsidiaries. These costs were recorded as a regulatory asset of approximately $30 million that is being recovered over a five -year period beginning April 29, 2016. Pro Forma Results (unaudited) We calculated the pro forma impact of the SourceGas Acquisition and the associated debt and equity financings on our operating results for the year ended December 31, 2016 and 2015. The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results December 31, 2016 2015 (in thousands, except per share amounts) Revenue $ 1,617,878 $ 1,720,618 Income from continuing operations $ 177,040 $ 160,290 Net income (loss) $ 112,878 $ (13,369 ) Earnings from continuing operations per share, Basic $ 3.41 $ 3.15 Earnings from continuing operations per share, Diluted $ 3.32 $ 3.15 We derived the pro forma results for the SourceGas Acquisition based on historical financial information obtained from the sellers and certain management assumptions. Our pro forma adjustments relate to incremental interest expense associated with the financings to effect the transaction, and for the year ended December 31, 2015 , also include adjustments to shares outstanding to reflect the equity issuances as if they had occurred on January 1, 2015, and to reflect pro forma dilutive effects of the equity units issued. The pro forma results do not reflect any cost savings, (or associated costs to achieve such savings) from operating efficiencies or restructuring that could result from the acquisition, and exclude any unique one-time items resulting from the acquisition that are not expected to have a continuing impact on the combined consolidated results. Pro forma results for the year ended December 31, 2016 reflect unfavorable weather impacts resulting in lower gas usage by our customers than in the same periods of the prior year. In addition, we calculated the tax impact of these adjustments at an estimated combined federal and state income tax rate of 37% . These pro forma results are for illustrative purposes only and do not purport to be indicative of the results that would have been obtained had the SourceGas Acquisition been completed on January 1, 2015, or that may be obtained in the future. Seller’s noncontrolling interest As part of the SourceGas Transaction, a seller retained a 0.5% noncontrolling interest and we entered into an associated option agreement with the holder for the 0.5% retained interest. In March 2017, we exercised our call option and purchased the remaining 0.5% equity interest in SourceGas for $5.6 million .

Property, Plant And Equipment_

Property, Plant And Equipment:	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2017 2016 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,315,044 39 $ 1,303,101 41 30 55 Electric transmission 407,203 51 354,801 52 40 70 Electric distribution 755,213 48 712,575 48 15 75 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 232,842 31 164,761 25 3 65 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 2,976,613 2,801,549 Construction work in progress 13,595 74,045 Total electric plant 2,990,208 2,875,594 Less accumulated depreciation and amortization 644,022 578,162 Electric plant net of accumulated depreciation and amortization $ 2,346,186 $ 2,297,432 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining. (b) Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031. 2017 2016 Lives (in years) Gas Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Gas plant: Production $ 10,495 35 $ 10,821 35 17 71 Gas transmission 366,433 48 338,729 48 22 70 Gas distribution 1,413,431 42 1,303,366 42 33 47 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciated (a) 47,466 0 47,055 0 0 0 Storage 28,520 31 27,686 31 15 48 General 336,869 19 339,382 19 3 44 Total gas plant in service 2,206,753 2,070,578 Construction work in progress 44,440 28,446 Total gas plant 2,251,193 2,099,024 Less accumulated depreciation and amortization 229,170 194,585 Gas plant net of accumulated depreciation and amortization $ 2,022,023 $ 1,904,439 _____________ (a) Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides. 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 155,569 $ 224 $ 155,793 $ 57,813 $ 97,980 33 2 40 Mining 158,370 — 158,370 108,844 49,526 14 2 59 2016 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 161,430 $ 1,298 $ 162,728 $ 55,157 $ 107,571 33 2 40 Mining 151,709 4,642 156,351 105,219 51,132 13 2 59 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,580 $ 6,374 $ 11,954 $ 309 $ 14,070 $ 25,715 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million . 2016 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 9,625 $ 11,974 $ 21,599 $ 2,106 $ 6,110 $ 25,603 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $6.1 million .

Jointly Owned Facilities_

Jointly Owned Facilities:	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Jointly Owned Facilities	JOINTLY OWNED FACILITIES Utility Plant Our consolidated financial statements include our share of several jointly-owned utility facilities as described below. Our share of the facilities’ expenses are reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income (Loss). Each owner of the facility is responsible for financing its investment in the jointly-owned facilities. • South Dakota Electric owns a 20% interest in the Wyodak Plant, a coal-fired electric generating station located in Campbell County, Wyoming. PacifiCorp owns the remaining ownership percentage and operates the Wyodak Plant. South Dakota Electric receives its proportionate share of the Wyodak Plant’s capacity and is committed to pay its proportionate share of its additions, replacements and operating and maintenance expenses. In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our Mining subsidiary, WRDC, supplies PacifiCorp’s share of the coal to the Wyodak Plant under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves. • South Dakota Electric also owns a 35% interest in, and is the operator of, the Converter Station Site and South Rapid City Interconnection (the transmission tie), an AC-DC-AC transmission tie. Basin Electric owns the remaining ownership percentage. The transmission tie provides an interconnection between the Western and Eastern transmission grids, which provides us with access to both the WECC region and the MAPP region. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie. • South Dakota Electric owns 52% of the Wygen III coal-fired generation facility. MDU and the City of Gillette each owns an undivided ownership interest in Wygen III and are obligated to make payments for costs associated with administrative services and their proportionate share of the costs of operating the plant for the life of the facility. We retain responsibility for plant operations. Our Mining subsidiary supplies coal to Wygen III for the life of the plant. • Colorado Electric owns 50% of the Busch Ranch Wind Farm while AltaGas owns the remaining undivided ownership interest and is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm for the life of the facility. We retain responsibility for operations of the wind farm. Non-Regulated Plants Our consolidated financial statements include our share of a jointly-owned non-regulated power generation facility as described below. Our share of direct expenses for the jointly-owned facility is included in the corresponding categories of operating expenses in the accompanying Consolidated Statements of Income (Loss). Each of the respective owners is responsible for providing its own financing. • Black Hills Wyoming owns 76.5% of the Wygen I plant while MEAN owns the remaining ownership percentage. MEAN is obligated to make payments for its share of the costs associated with administrative services, plant operations and coal supply provided by our Mining subsidiary during the life of the facility. We retain responsibility for plant operations. At December 31, 2017 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 114,405 $ 727 $ 58,955 Transmission Tie $ 20,037 $ 242 $ 6,215 Wygen I $ 109,552 $ 209 $ 40,465 Wygen III $ 138,688 $ 406 $ 19,239 Busch Ranch Wind Farm $ 18,899 $ — $ 3,858

Business Segment Information_

Business Segment Information:	12 Months Ended
	Dec. 31, 2017
Segment Reporting Information, Additional Information [Abstract]
Business Segment Information	BUSINESS SEGMENT INFORMATION Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2017 2016 Electric (a) $ 2,906,275 $ 2,859,559 Gas 3,426,466 3,307,967 Power Generation (a) 60,852 73,445 Mining 65,455 67,347 Corporate and Other 115,612 112,760 Discontinued operations (b) 84,242 120,695 Total assets $ 6,658,902 $ 6,541,773 __________________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information. Capital Expenditures and Asset Acquisitions (a) for the years ended December 31, 2017 2016 Capital expenditures Electric Utilities $ 138,060 $ 258,739 Gas Utilities 184,389 173,930 Power Generation 1,864 4,719 Mining 6,708 5,709 Corporate and Other 6,668 17,353 Total capital expenditures 337,689 460,450 Asset acquisitions Gas Utilities (b) — 1,124,238 Total capital expenditures and asset acquisitions of continuing operations 337,689 1,584,688 Total capital expenditures of discontinued operations 23,222 6,669 Total capital expenditures and asset acquisitions $ 360,911 $ 1,591,357 _________________ (a) Includes accruals for property, plant and equipment. (b) SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2 . Property, Plant and Equipment as of December 31, 2017 2016 Electric Utilities (a) $ 2,990,208 $ 2,875,594 Gas Utilities 2,251,193 2,099,024 Power Generation (a) 155,793 162,728 Mining 158,370 156,351 Corporate and Other 11,954 21,599 Total property, plant and equipment $ 5,567,518 $ 5,315,296 _______________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. Consolidating Income Statement Year ended December 31, 2017 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 689,945 $ 947,595 $ 7,263 $ 35,463 $ — $ — $ — $ 1,680,266 Intercompany revenue 14,705 35 84,283 31,158 344,685 (474,866 ) — — Total revenue 704,650 947,630 91,546 66,621 344,685 (474,866 ) — 1,680,266 Fuel, purchased power and cost of natural gas sold 268,405 409,603 — — 151 (114,871 ) — 563,288 Operations and maintenance 172,307 269,190 32,382 44,882 296,067 (302,832 ) — 511,996 Depreciation, depletion and amortization 93,315 83,732 5,993 8,239 21,031 (24,064 ) — 188,246 Operating income (loss) 170,623 185,105 53,171 13,500 27,436 (33,099 ) — 416,736 Interest expense (55,229 ) (80,829 ) (3,959 ) (228 ) (152,416 ) 154,543 — (138,118 ) Interest income 2,955 2,254 1,123 23 115,382 (120,721 ) — 1,016 Other income (expense), net 1,730 (829 ) (54 ) 2,191 330,373 (331,303 ) — 2,108 Income tax benefit (expense) (a) (9,997 ) (39,799 ) 10,333 (1,100 ) (32,433 ) (371 ) — (73,367 ) Income (loss) from continuing operations 110,082 65,902 60,614 14,386 288,342 (330,951 ) — 208,375 Income (loss) from discontinued operations, net of tax (b) — — — — — — (17,099 ) (17,099 ) Net income (loss) 110,082 65,902 60,614 14,386 288,342 (330,951 ) (17,099 ) 191,276 Net income attributable to noncontrolling interest — (107 ) (14,135 ) — — — — (14,242 ) Net income (loss) available for common stock $ 110,082 $ 65,795 $ 46,479 $ 14,386 $ 288,342 $ (330,951 ) $ (17,099 ) $ 177,034 ________________ (a) The effective tax rate is lower in 2017 resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. (b) Discontinued operations includes oil and gas property impairments (see Note 21 ). Consolidating Income Statement Year ended December 31, 2016 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 664,330 $ 838,343 $ 7,176 $ 29,067 $ — $ — $ — $ 1,538,916 Intercompany revenue 12,951 — 83,955 31,213 347,500 (475,619 ) — — Total revenue 677,281 838,343 91,131 60,280 347,500 (475,619 ) — 1,538,916 Fuel, purchased power and cost of natural gas sold 261,349 352,165 — — 456 (114,838 ) — 499,132 Operations and maintenance 158,134 245,826 32,636 39,576 378,744 (326,846 ) — 528,070 Depreciation, depletion and amortization 84,645 78,335 4,104 9,346 22,930 (23,827 ) — 175,533 Operating income (loss) 173,153 162,017 54,391 11,358 (54,630 ) (10,108 ) — 336,181 Interest expense (56,237 ) (76,586 ) (3,758 ) (401 ) (114,597 ) 115,469 — (136,110 ) Interest income 5,946 1,573 1,983 24 97,147 (105,244 ) — 1,429 Other income (expense), net 3,193 184 2 2,209 179,838 (181,032 ) — 4,394 Income tax benefit (expense) (40,228 ) (27,462 ) (17,129 ) (3,137 ) 28,398 457 — (59,101 ) Income (loss) from continuing operations 85,827 59,726 35,489 10,053 136,156 (180,458 ) — 146,793 (Loss) from discontinued operations, net of tax (a) — — — — — — (64,162 ) (64,162 ) Net income (loss) 85,827 59,726 35,489 10,053 136,156 (180,458 ) (64,162 ) 82,631 Net income attributable to noncontrolling interest — (102 ) (9,559 ) — — — — (9,661 ) Net income (loss) available for common stock $ 85,827 $ 59,624 $ 25,930 $ 10,053 $ 136,156 $ (180,458 ) $ (64,162 ) $ 72,970 ________________ (a) Discontinued operations includes oil and gas property impairments (see Note 21 ). Consolidating Income Statement Year ended December 31, 2015 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 668,226 $ 551,300 $ 7,483 $ 34,313 $ — $ — $ — $ 1,261,322 Intercompany revenue 11,617 — 83,307 30,753 227,708 (353,385 ) — — Total revenue 679,843 551,300 90,790 65,066 227,708 (353,385 ) — 1,261,322 Fuel, purchased power and cost of natural gas sold 269,409 299,645 — — 122 (112,289 ) — 456,887 Operations and maintenance 160,924 140,723 32,140 41,630 231,855 (229,790 ) — 377,482 Depreciation, depletion and amortization 80,929 32,326 4,329 9,806 9,723 (10,580 ) — 126,533 Operating income (loss) 168,581 78,606 54,321 13,630 (13,992 ) (726 ) — 300,420 Interest expense (55,159 ) (17,912 ) (4,218 ) (433 ) (61,496 ) 54,568 — (84,650 ) Interest income 4,114 601 1,015 34 48,799 (52,942 ) — 1,621 Other income (expense), net 1,216 315 71 2,247 70,929 (71,964 ) — 2,814 Income tax benefit (expense) (41,173 ) (22,304 ) (18,539 ) (3,608 ) 6,606 361 — (78,657 ) Income (loss) from continuing operations 77,579 39,306 32,650 11,870 50,846 (70,703 ) — 141,548 Income (loss) from discontinued operations, net of tax (a) — — — — — — (173,659 ) (173,659 ) Net income (loss) 77,579 39,306 32,650 11,870 50,846 (70,703 ) (173,659 ) (32,111 ) Net income attributable to noncontrolling interest — — — — — — — — Net income (loss) available for common stock $ 77,579 $ 39,306 $ 32,650 $ 11,870 $ 50,846 $ (70,703 ) $ (173,659 ) $ (32,111 ) ________________ (a) Discontinued operations includes oil and gas property impairments (see Note 21 ). Corporate expense reallocation In accordance with GAAP, indirect corporate operating costs previously allocated to BHEP were not reclassified to discontinued operations. These corporate operating costs for 2017 were reallocated to our operating segments; allocated interest was reclassified to Corporate and Other. Indirect corporate operating costs for 2016 and 2015 were reclassified to Corporate and Other. The reallocation of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 and 2015 is as follows (in thousands): Year Ended Business Segment December 31, 2017 December 31, 2016 December 31, 2015 Electric Utilities $ 1,323 $ 2,079 $ 3,344 Gas Utilities 1,571 2,292 1,815 Power Generation 177 320 543 Mining 101 196 321 Total reportable segments 3,172 4,887 6,023 Corporate and Other (a) 6,405 6,037 3,957 Total $ 9,577 $ 10,924 $ 9,980 ________________________ (a) Includes interest allocations in 2017, 2016 and 2015 of approximately $4.9 million , $5.6 million and $3.4 million , respectively.

Long-Term Debt_

Long-Term Debt:	12 Months Ended
	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Long-term Debt	LONG-TERM DEBT Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2017 December 31, 2017 December 31, 2016 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2020 July 15, 2020 5.88% 200,000 200,000 Remarketable junior subordinated notes (b) November 1, 2028 3.50% 299,000 299,000 Senior unsecured notes due 2019 January 11, 2019 2.50% 250,000 250,000 Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 300,000 Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 400,000 Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Corporate term loan due 2019 (a) August 9, 2019 2.55% 300,000 400,000 Corporate term loan due 2021 June 7, 2021 2.32% 18,664 24,406 Total Corporate debt 2,592,664 2,698,406 Less unamortized debt discount (3,808 ) (4,413 ) Total Corporate debt, net 2,588,856 2,693,993 Electric Utilities First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 Industrial development revenue bonds due 2021 (c) September 1, 2021 1.78% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 1.78% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 1.83% 2,855 2,855 Total Electric Utilities debt 544,855 544,855 Less unamortized debt discount (90 ) (94 ) Total Electric Utilities debt, net 544,765 544,761 Total long-term debt 3,133,621 3,238,754 Less current maturities 5,743 5,743 Less deferred financing costs (d) 18,478 21,822 Long-term debt, net of current maturities and deferred financing costs $ 3,109,400 $ 3,211,189 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) See Note 12 for RSN details. (c) Variable interest rate. (d) Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2017 and December 31, 2016 , respectively. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2018 $ 5,743 2019 $ 555,742 2020 $ 205,743 2021 $ 8,436 2022 $ — Thereafter $ 2,361,855 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2017 . Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. The first mortgage bonds issued by South Dakota Electric and Wyoming Electric are callable, but are subject to make-whole provisions which would eliminate any economic benefit for us to call the bonds. Assumption of Long-Term Debt At the closing of the SourceGas Acquisition on February 12, 2016, we assumed $760 million in long-term debt, consisting of the following: • $325 million , 5.9% senior unsecured notes with an original issue date of April 16, 2007, due April 1, 2017. • $95 million , 3.98% senior secured notes with an original issue date of September 29, 2014, due September 29, 2019. • $340 million unsecured corporate term loan due June 30, 2017. Interest under this term loan was LIBOR plus a margin of 0.875% . The $760 million in long-term debt assumed in the SourceGas Acquisition was repaid in August 2016. Debt Transactions On May 16, 2017, we paid down $50 million on our Corporate term loan due August 9, 2019. On July 17, 2017, we paid down an additional $50 million on the same term loan. Short-term borrowings from our CP program were used to fund the payments on the Corporate term loan. On August 19, 2016, we completed a public debt offering of $700 million principal amount of senior unsecured notes. The debt offering consisted of $400 million of 3.15% 10 -year senior notes due January 15, 2027 and $300 million of 4.20% 30 -year senior notes due September 15, 2046 (together the “Notes”). The proceeds of the Notes were used for the following: • Repay the $325 million 5.9% senior unsecured notes assumed in the SourceGas Acquisition; • Repay the $95 million , 3.98% senior secured notes assumed in the SourceGas Acquisition; • Repay $100 million on the $340 million unsecured term loan assumed in the SourceGas Acquisition; • Pay down $100 million of the $500 million three -year unsecured term loan discussed below; • Payment of $29 million for the settlement of $400 million notional interest rate swap; and • Remainder was used for general corporate purposes. On August 9, 2016, we entered into a $500 million , three -year, unsecured term loan expiring on August 9, 2019. The proceeds of this term loan were used to pay down $240 million of the $340 million unsecured term loan assumed in the SourceGas Acquisition and the $260 million term loan expiring on April 12, 2017. This new term loan has substantially similar terms and covenants as the amended and restated Revolving Credit Facility. In accordance with regulatory orders related to the early termination and settlement of the gas supply contract described in Note 1 , on June 7, 2016, we entered into a 2.32% , $29 million term loan, due June 7, 2021. Proceeds from this term loan were used to finance the early termination of the gas supply contract, resulting in a regulatory asset. Principal and interest are payable quarterly at approximately $1.6 million . On January 13, 2016, we completed a public debt offering of $550 million principal amount of senior unsecured notes. The debt offering consisted of $300 million of 3.95% , ten -year senior notes due 2026, and $250 million of 2.50% , three -year senior notes due 2019. After discounts and underwriter fees, net proceeds from the offering totaled $546 million and were used as funding for the SourceGas Acquisition. The discounts are amortized over the life of each respective note. Amortization Expense Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2017 2017 2016 2015 Revolving Credit Facility $ 1,703 $ 638 $ 537 $ 504 Senior unsecured notes due 2023 2,427 494 494 494 Senior unsecured notes due 2019 59 704 643 — Senior unsecured notes due 2020 425 167 167 167 Senior unsecured notes due 2026 2,031 287 262 — Senior unsecured notes due 2027 2,918 363 121 — Senior unsecured notes due 2046 3,082 111 37 — Corporate term loan due 2019 86 201 144 — Bridge Term Loan — — 843 4,213 RSNs due 2028 1,326 122 122 10 First mortgage bonds due 2044 (South Dakota Electric) 639 24 24 24 First mortgage bonds due 2044 (Wyoming Electric) 591 22 23 22 First mortgage bonds due 2032 485 33 33 33 First mortgage bonds due 2039 1,657 76 76 76 First mortgage bonds due 2037 613 31 31 31 Other 436 76 304 43 Total $ 18,478 $ 3,349 $ 3,861 $ 5,617 Dividend Restrictions Our credit facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. In addition, the agreements governing our equity units contain restrictions on the payment of cash dividends upon any time we have exercised our right to defer payment of contract adjustment payments under the purchase contracts or interest payments under the RSNs included in such equity units. As of December 31, 2017 , we were in compliance with these covenants. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. The following restrictions on distributions from our subsidiaries existed at December 31, 2017 : • Our utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2017 , the restricted net assets at our Electric and Gas Utilities were approximately $257 million .

Notes Payable_

Notes Payable:	12 Months Ended
	Dec. 31, 2017
Notes Payable [Abstract]
Notes Payable	NOTES PAYABLE Our Revolving Credit Facility and debt securities contain certain restrictive financial covenants. As of December 31, 2017 , we were in compliance with all of these financial covenants. We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands): Balance Outstanding at December 31, 2017 December 31, 2016 Revolving Credit Facility $ — $ 96,600 CP Program 211,300 — Total $ 211,300 $ 96,600 Revolving Credit Facility On August 9, 2016, we amended and restated our corporate Revolving Credit Facility to increase total commitments to $750 million from $500 million and extend the term through August 9, 2021 with two one -year extension options (subject to consent from the lenders). This facility is similar to the former agreement, which includes an accordion feature that allows us, with the consent of the administrative agent and issuing agents and subject to receipt of additional commitments from existing or new lenders, to increase total commitments of the facility up to $1.0 billion . Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our most favorable Corporate credit rating from either S&P or Moody’s for our unsecured debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.250% , 1.250% , and 1.250% , respectively, at December 31, 2017 . A 0.200% commitment fee is charged on the unused amount of the Revolving Credit Facility. On December 22, 2016, we implemented a $750 million , unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million . The notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our net amount borrowed under the CP Program during 2017 and our notes outstanding as of December 31, 2017 were $211 million . We did not borrow under the CP Program in 2016 and did not have any notes outstanding as of December 31, 2016. As of December 31, 2017 , the weighted average interest rate on CP Program borrowings was 1.76% . As of December 31, 2017 and 2016 , we had outstanding letters of credit totaling approximately $27 million and approximately $36 million , respectively. Deferred financing costs on the Revolving Credit Facility of $5.4 million are being amortized over its estimated useful life and included in Interest expense on the accompanying Consolidated Statements of Income (Loss). Debt Covenants On December 7, 2016, we amended our Revolving Credit Facility and term loan agreements, allowing the exclusion of the Remarketable Junior Subordinated Notes (RSNs) from our Consolidated Indebtedness to Capitalization Ratio covenant calculation. Under the amended and restated Revolving Credit Facility and term loan agreements, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00 . Our Consolidated Indebtedness to Capitalization Ratio is calculated by dividing (i) Consolidated Indebtedness, which includes letters of credit, certain guarantees issued and excludes RSNs by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interests in subsidiaries and includes the aggregate outstanding amount of the RSNs. Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: At December 31, 2017 Covenant Requirement at December 31, 2017 Consolidated Indebtedness to Capitalization Ratio 61 % Less than 65 %

Asset Retirement Obligations_

Asset Retirement Obligations:	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS We have identified legal retirement obligations related to reclamation of coal mining sites in the Mining segment and removal of fuel tanks, asbestos, transformers containing polychlorinated biphenyls, an evaporation pond and wind turbines at the regulated Electric Utilities segment, retirement of gas pipelines at our Gas Utilities and asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these asset retirement obligations. The actual cost may vary from estimates because of regulatory requirements, changes in technology and increased costs of labor, materials and equipment. The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2016 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired Revisions to Prior Estimates (b) December 31, 2017 Electric Utilities $ 4,661 $ — $ (4 ) $ 268 $ — $ 1,362 $ 6,287 Gas Utilities 29,775 — — 1,142 — 2,321 33,238 Mining 12,440 — (107 ) 651 — (485 ) 12,499 Total $ 46,876 $ — $ (111 ) $ 2,061 $ — $ 3,198 $ 52,024 December 31, 2015 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired (a) Revisions to Prior Estimates (b)(c) December 31, 2016 Electric Utilities $ 4,462 $ — $ — $ 191 $ — $ 8 $ 4,661 Gas Utilities 136 — — 791 22,412 6,436 29,775 Mining 18,633 — (105 ) 822 — (6,910 ) 12,440 Total $ 23,231 $ — $ (105 ) $ 1,804 $ 22,412 $ (466 ) $ 46,876 _____________________ (a) Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas. (b) The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming. We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled and therefore, a liability for the cost of these obligations cannot be measured at this time. We have identified legal retirement obligations related to plugging and abandonment of natural gas and oil wells. These obligations are classified as held for sale at December 31, 2017. See Note 21 .

Risk Management Activities_

Risk Management Activities:	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities	RISK MANAGEMENT ACTIVITIES Our activities in the regulated and non-regulated energy sectors expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1 . Market Risk Market risk is the potential loss that may occur as a result of an adverse change in market price or rate. We are exposed to the following market risks, including, but not limited to: • Commodity price risk associated with our retail natural gas marketing activities and our fuel procurement for certain of our gas-fired generation assets; and • Interest rate risk associated with our variable rate debt . Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. For production and generation activities, we attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, prepayments, letters of credit and other security agreements. We perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience and any specific customer collection issue that is identified. Our credit exposure at December 31, 2017 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income (Loss) and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10 . Utilities The operations of our utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements) expose our utility customers to volatility in natural gas prices. Therefore, as allowed or required by state utility commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income (Loss). We buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and/or sales during time frames ranging from January 2018 through May 2020. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The effective portion of the gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and the ineffective portion, if any is reported in Fuel, purchased power and cost of natural gas sold. Effectiveness of our hedging position is evaluated at least quarterly. The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of: December 31, 2017 December 31, 2016 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 8,330,000 36 14,770,000 48 Natural gas options purchased, net (b) 3,540,000 14 3,020,000 5 Natural gas basis swaps purchased 8,060,000 36 12,250,000 48 Natural gas over-the-counter swaps, net (c) 3,820,000 29 4,622,302 28 Natural gas physical commitments, net (d) 12,826,605 35 21,504,378 10 __________ (a) Term reflects the maximum forward period hedged. (b) Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions. (c) As of December 31, 2017 , 1,650,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (d) Volumes exclude contracts that qualify for normal purchase, normal sales exception. Based on December 31, 2017 prices, a $0.7 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. Financing Activities At December 31, 2017 , we had no outstanding interest rate swap agreements. In October 2015 and January 2016, we entered into forward starting interest rate swaps with a notional value totaling $400 million to fix the Treasury yield component associated with the anticipated issuance of senior notes. These swaps were settled at a loss of $29 million in connection with the issuance of our $400 million of unsecured ten -year senior notes in August 2016. The effective portion of the loss in the amount of $28 million was recognized as a component of AOCI and will be recognized as interest expense over the ten -year life of the $400 million unsecured note issued on August 19, 2016. The ineffective portion of $1.0 million , related to the timing of the debt issuance, was recognized in earnings as a component of interest expense in 2016. The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of: December 31, 2016 Interest Rate Swaps (a) Notional $ 50,000 Weighted average fixed interest rate 4.94 % Maximum terms in months 1 Derivative assets, non-current $ — Derivative liabilities, current $ 90 Derivative liabilities, non-current $ — ___________________ (a) The $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings. Discontinued Operations Our Oil and Gas segment was exposed to risks associated with changes in the market prices through the sale and delivery of oil and gas to its customers at competitive prices. Through December 2017, we used exchange traded futures, swaps and options to hedge portions of our crude oil and natural gas production to mitigate commodity price risk and preserve cash flows. Hedge accounting was elected on the swaps and futures contracts. These transactions were designated upon inception as cash flow hedges, documented under accounting standards for derivatives and hedging and initially met prospective effectiveness testing. As a result of divesting our Oil and Gas segment assets, these activities were discontinued and there were no outstanding derivative agreements as of December 31, 2017 . Any cash flows associated with our crude oil and natural gas cash flow hedges were no longer probable of occurring; therefore, we discontinued hedge accounting as of November 1, 2017. As a result, we reclassified the loss in accumulated other comprehensive income associated with the commodity contracts into earnings as a reduction of revenues and recognized a pre-tax loss of $0.3 million , which is included in net loss from discontinued operations on the Consolidated Statements of Income (Loss) for the year ended December 31, 2017 . At December 31, 2016, we had outstanding crude oil futures and swap contracts with notional volumes of 108,000 Bbls, crude oil options contracts with notional volumes of 36,000 Bbls and natural gas futures and swap contracts with notional volumes of 2,700,000 MMBtus. Cash Flow Hedges The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2017 , 2016 and 2015 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. December 31, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (2,941 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 913 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (243 ) Fuel, purchased power and cost of natural gas sold (75 ) Total impact from cash flow hedges $ (2,271 ) $ (75 ) December 31, 2016 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (3,899 ) Interest expense $ (953 ) Commodity derivatives Net (loss) from discontinued operations 11,019 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (14 ) Fuel, purchased power and cost of natural gas sold — Total $ 7,106 $ (953 ) December 31, 2015 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (3,647 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 14,460 Net (loss) from discontinued operations — Total $ 10,813 $ — The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2017 , 2016 and 2015 . The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred. December 31, 2017 December 31, 2016 December 31, 2015 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ — $ (31,222 ) $ 2,888 Forward commodity contracts 366 (573 ) 9,782 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,941 3,899 3,647 Forward commodity contracts (670 ) (11,005 ) (14,460 ) Total other comprehensive income (loss) from hedging $ 2,637 $ (38,901 ) $ 1,857 Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2017 , 2016 and 2015 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. 2017 2016 2015 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ (50 ) $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (2,207 ) 940 — $ (2,207 ) $ 890 $ — As discussed above, financial instruments used in our regulated utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory assets or Regulatory liability accounts related to the hedges in our Utilities were $12 million and $8.8 million at December 31, 2017 and 2016 , respectively.

Fair Value Measurements_

Fair Value Measurements:	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements There have been no significant transfers between Level 1 and Level 2 derivative balances during 2017 or 2016 . Amounts included in cash collateral and counterparty netting in the following tables represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions, netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as cash collateral posted with the same counterparties. A discussion of fair value of financial instruments is included in Note 11 . Oil and gas derivative instruments are included in assets and liabilities held for sale discussed in Note 21. The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands): As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 1,586 $ — $ (1,282 ) $ 304 Total $ — $ 1,586 $ — $ (1,282 ) $ 304 Liabilities: Commodity derivatives - Utilities $ — $ 13,756 $ — $ (11,497 ) $ 2,259 Total $ — $ 13,756 $ — $ (11,497 ) $ 2,259 As of December 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 7,469 $ — $ (3,262 ) $ 4,207 Total — 7,469 — (3,262 ) 4,207 Liabilities: Commodity derivatives - Utilities $ — $ 12,201 $ — $ (11,144 ) $ 1,057 Interest rate swaps — 90 — — 90 Total $ — $ 12,291 $ — $ (11,144 ) $ 1,147 Fair Value Measures by Balance Sheet Classification As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis, aside from the netting of asset and liability positions permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements and the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions. The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands): 2017 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets - current $ — $ — $ 1,007 $ — Commodity derivatives Derivative assets - non-current — — 124 — Commodity derivatives Current assets held for sale — — 154 — Commodity derivatives Derivative liabilities - current — 817 — — Commodity derivatives Other deferred credits and other liabilities — 67 — 7 Commodity derivatives Current liabilities held for sale — — — 1,090 Commodity derivatives Noncurrent liabilities held for sale — — — 231 Interest rate swaps Derivative liabilities - current — — — 90 Total derivatives designated as hedges $ — $ 884 $ 1,285 $ 1,418 Derivatives not designated as hedges: Commodity derivatives Derivative assets - current $ 304 $ — $ 2,977 $ — Commodity derivatives Derivative assets - non-current — — 98 — Commodity derivatives Derivative liabilities - current — 1,264 — 1,014 Commodity derivatives Other deferred credits and other liabilities — 111 — 36 Commodity derivatives Current liabilities held for sale — — — 265 Total derivatives not designated as hedges $ 304 $ 1,375 $ 3,075 $ 1,315 Derivatives Offsetting It is our policy to offset in our Consolidated Balance Sheets contracts which provide for legally enforceable netting of our accounts receivable and payable and derivative activities. As required by accounting standards for derivatives and hedges, fair values within the following tables reconcile the gross amounts to the net amounts. Amounts included in Gross Amounts Offset on Consolidated Balance Sheets in the following tables include the netting of asset and liability positions permitted in accordance with accounting standards for offsetting as well as the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral posted with the same counterparties. Additionally, the amounts reflect cash collateral on deposit in margin accounts at December 31, 2017 and December 31, 2016 , to collateralize certain financial instruments, which are included in Derivative assets and/or Derivative liabilities. Therefore, the gross amounts are not indicative of either our actual credit exposure or net economic exposure. Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2017 was as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Subject to master netting agreement or similar arrangement: Commodity derivative: Utilities $ 1,282 $ (1,282 ) $ — Total derivative assets subject to a master netting agreement or similar arrangement 1,282 (1,282 ) — Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 304 — 304 Total derivative assets not subject to a master netting agreement or similar arrangement 304 — 304 Total derivative assets $ 1,586 $ (1,282 ) $ 304 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities $ 11,497 $ (11,497 ) $ — Total derivative liabilities subject to a master netting agreement or similar arrangement 11,497 (11,497 ) — Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 2,259 — 2,259 Total derivative liabilities not subject to a master netting agreement or similar arrangement 2,259 — 2,259 Total derivative liabilities $ 13,756 $ (11,497 ) $ 2,259 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2016 were as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Subject to master netting agreement or similar arrangement: Commodity derivative: Utilities $ 4,269 $ (3,262 ) $ 1,007 Total derivative assets subject to a master netting agreement or similar arrangement 4,269 (3,262 ) 1,007 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 3,200 — 3,200 Total derivative assets not subject to a master netting agreement or similar arrangement 3,200 — 3,200 Total derivative assets $ 7,469 $ (3,262 ) $ 4,207 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities $ 11,144 $ (11,144 ) $ — Total derivative liabilities subject to a master netting agreement or similar arrangement 11,144 (11,144 ) — Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 1,057 — 1,057 Interest Rate Swaps 90 — 90 Total derivative liabilities not subject to a master netting agreement or similar arrangement 1,147 — 1,147 Total derivative liabilities $ 12,291 $ (11,144 ) $ 1,147

Fair Value Of Financial Instrum

Fair Value Of Financial Instruments:	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10 , were as follows at December 31 (in thousands): 2017 2016 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 15,420 $ 15,420 $ 13,518 $ 13,518 Restricted cash and equivalents (a) $ 2,820 $ 2,820 $ 2,274 $ 2,274 Notes payable (b) $ 211,300 $ 211,300 $ 96,600 $ 96,600 Long-term debt, including current maturities (c) (d) $ 3,115,143 $ 3,350,544 $ 3,216,932 $ 3,351,305 _______________ (a) Carrying value approximates fair value. Cash and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings in 2017 and borrowings on our Revolving Credit Facility in 2016. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) 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. (d) Carrying amount of long-term debt is net of deferred financing costs. Cash and Cash Equivalents Included in cash and cash equivalents is cash, money market mutual funds, and term deposits. As part of our cash management process, excess operating cash is invested in money market mutual funds with our bank. Money market mutual funds are not deposits and are not insured by the U.S. Government, the FDIC, or any other government agency and involve investment risk including possible loss of principal. We believe however, that the market risk arising from holding these financial instruments is minimal. Restricted Cash and Equivalents Restricted cash and cash equivalents represent restricted cash and uninsured term deposits. Notes Payable and Long-Term Debt For additional information on our notes payable and long-term debt, see Note 6 and Note 7 .

Equity_

Equity:	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Equity	EQUITY Equity Units On November 23, 2015, we issued 5.98 million equity units for total gross proceeds of $299 million . Each Equity Unit has a stated amount of $50 and consists of (i) a forward purchase contract to purchase the Company’s common stock and (ii) a 1/20, or 5% , undivided beneficial ownership interest in $1,000 principal amount of RSNs due 2028. The RSNs, a debt instrument, and the forward purchase contracts, an equity instrument, are deemed to be separate instruments as the investor may trade the RSNs separately from the forward purchase contract and may also settle the forward purchase contract separately. The forward purchase contracts obligate the holders to purchase from the Company on the settlement date, which shall be no later than November 1, 2018, for a price of $50 in cash, the following number of shares of our common stock, subject to anti-dilution adjustments: • if the “Applicable Market Value” (AMV) of the Company’s common stock, which is the average volume-weighted average price of the Company’s common stock for the trading days during the 20 consecutive scheduled trading day period ending on the third scheduled trading day immediately preceding the forward purchase contract settlement date, equals or exceeds $47.2938 , 1.0572 shares of the Company’s common stock per Equity Unit; • if the AMV is less than $47.2938 but greater than $40.25 , a number of shares of the Company’s common stock having a value, based on the AMV, equal to $50 ; and • if the AMV is less than or equal to $40.25 , 1.2422 shares of the Company’s common stock. The RSNs bear interest at a rate of 3.5% per year, payable quarterly, and mature on November 1, 2028. The RSNs will be remarketed in 2018. If this remarketing is successful, the interest rate on the RSNs will be reset, and thereafter interest will be payable semi-annually at the reset rate. If there is no successful remarketing, the interest rate on the RSNs will not be reset, and the holders of the RSNs will have the right to put the RSNs to the Company at a price equal to 100% of the principal amount, and the proceeds of the put right will be deemed to have been applied against the holders’ obligation under the forward purchase contracts. The Company also pays the Equity Unit holders quarterly contract adjustment payments at a rate of 4.25% per year of the stated amount of $50 per Equity Unit, or $2.125 per year up to November 1, 2018. The present value of the future contract adjustment payments, $33 million , was recorded as a reduction of shareholders’ equity in the accompanying Consolidated Balance Sheets. Until settlement of the forward purchase contracts, the shares of stock underlying each forward purchase contract are not outstanding. The forward purchase contracts will only be included in the computation of diluted earnings per share to the extent they are dilutive. As of December 31, 2017, the forward purchase contracts were dilutive and therefore included in the computation of diluted earnings per share. Basic earnings per share will not be affected until the forward purchase contracts are settled and the holders thereof become stockholders. Selected information about our equity units is presented below (in thousands except for percentages): Issuance Date Units Issued Total Net Proceeds Total Long-term Debt (RSNs) RSN Interest Rate (annual) Stock Purchase Contract Rate (annual) Stock Purchase Contract Liability as of December 31, 2017 11/23/2015 5,980 $ 290,030 $ 299,000 3.50 % 4.25 % $ 12,115 At-the-Market Equity Offering Program On August 4, 2017, we renewed the ATM equity offering program, which reset the size of the program to an aggregate value of up to $300 million . The renewed program, which allows us to sell shares of our common stock, is the same as the prior year program other than the aggregate value increased from $200 million to $300 million . The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2017. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2017. During the three months ended December 31, 2016, we issued 218,647 common shares for $13 million , net of $0.1 million in commissions under the ATM equity offering program. During the twelve months ended December 31, 2016, we issued an aggregate of 1,968,738 shares of common stock under the ATM equity offering program for $119 million , net of $1.2 million in commissions. Common Stock Offering On November 23, 2015, we issued 6.325 million shares of common stock pursuant to a public offering at $40.25 per share. Net proceeds were $246 million . The proceeds from the offering were used to partially fund the purchase of SourceGas, which closed on February 12, 2016. Equity Compensation Plans Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options and performance shares. We had 979,464 shares available to grant at December 31, 2017 . Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2017 , total unrecognized compensation expense related to non-vested stock awards was approximately $12.0 million and is expected to be recognized over a weighted-average period of 1.9 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands): 2017 2016 2015 Stock-based compensation expense $ 7,626 $ 10,885 $ 4,076 Stock Options The Company has not issued any stock options since 2014 and has 96,749 stock options outstanding at December 31, 2017. The amount of stock options granted during the last three years, and related exercise activity are not material to the Company’s consolidated financial statements. Restricted Stock The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant. The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over 3 years , contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period. A summary of the status of the restricted stock and restricted stock units at December 31, 2017 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 295 $ 52.15 Granted 111 60.63 Vested (128 ) 51.44 Forfeited (11 ) 53.80 Balance at end of period 267 $ 55.94 The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2017 $ 60.63 $ 7,909 2016 $ 53.55 $ 4,602 2015 $ 50.01 $ 6,009 As of December 31, 2017 , there was $9.9 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.0 years . Performance Share Plan Certain officers of the Company and its subsidiaries are participants in a performance share award plan, a market-based plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. The performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $2.5 million at December 31, 2017 would be reclassified as a liability. Outstanding performance periods at December 31 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2015 January 1, 2015 - December 31, 2017 43 0% 200% January 1, 2016 January 1, 2016 - December 31, 2018 53 0% 200% January 1, 2017 January 1, 2017 - December 31, 2019 51 0% 200% A summary of the status of the Performance Share Plan at December 31 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2017 (in thousands) (in thousands) Performance Shares balance at beginning of period 71 $ 52.29 71 Granted 26 63.52 26 Forfeited (1 ) 55.01 (1 ) Vested (22 ) 55.18 (22 ) Performance Shares balance at end of period 74 $ 55.31 74 $ 22.31 _____________________ (a) The grant date fair values for the performance shares granted in 2017 , 2016 and 2015 were determined by Monte Carlo simulation using a blended volatility of 23% , 24% and 21% , respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2017 $ 63.52 December 31, 2016 $ 47.76 December 31, 2015 $ 54.92 Performance plan payouts have been as follows (dollars and shares in thousands): Performance Period Year of Payment Shares Issued Cash Paid Total Intrinsic Value January 1, 2014 to December 31, 2016 2017 — $ — $ — January 1, 2013 to December 31, 2015 2016 — $ — $ — January 1, 2012 to December 31, 2014 2015 69 $ 3,657 $ 7,314 On January 30, 2018 , the Compensation Committee of our Board of Directors determined that the Company’s performance criteria for the January 1, 2015 through December 31, 2017 performance period was not met. As a result, there will be no payout for this period. As of December 31, 2017 , there was $2.1 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.6 years . Shareholder Dividend Reinvestment and Stock Purchase Plan We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares during 2017 and 2016. A summary of the DRSPP for the years ended December 31 is as follows (shares in thousands): 2017 2016 Shares Issued 48 51 Weighted Average Price $ 65.40 $ 58.24 Unissued Shares Available 308 356 Preferred Stock Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding. Sale of Noncontrolling Interest in Subsidiary Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. On April 14, 2016, Black Hills Electric Generation sold a 49.9% , noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. FERC approval of the sale was received on March 29, 2016. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Black Hills Colorado Electric. Proceeds from the sale were used to pay down short-term debt and for other general corporate purposes. ASC 810 requires the accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Distributions of net income attributable to noncontrolling interests are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. Net income available for common stock for the years ended December 31, 2017 and December 31, 2016 was reduced by $14 million and $9.6 million , respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holders is based on ownership interests with the exception of certain agreed upon adjustments. Black Hills Colorado IPP has been determined to be a variable interest entity (VIE) in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31: 2017 2016 (in thousands) Assets Current assets $ 14,837 $ 12,627 Property, plant and equipment of variable interest entities, net $ 208,595 $ 218,798 Liabilities Current liabilities $ 4,565 $ 4,342

Regulatory Matters_ Regulatory

Regulatory Matters: Regulatory Matters (Notes)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Regulatory Matters	REGULATORY MATTERS Electric Utilities Rate Activity South Dakota Electric Common Use System (CUS) : The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2018 the annual revenue requirement increased by $3.3 million and included estimated weighted average capital additions of $45 million for 2017 and 2018. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year. South Dakota Electric Settlement: On June 16, 2017, South Dakota Electric received approval from the SDPUC on a settlement reached with the SDPUC staff agreeing to a 6 -year moratorium period effective July 1, 2017. As part of this agreement, South Dakota Electric will not increase base rates, absent an extraordinary event. The moratorium period also includes suspension of both the Transmission Facility Adjustment and the Environmental Improvement Adjustment, and a $1.0 million increase to the annual power marketing margin guarantee during this period. Additionally, existing regulatory asset balances of approximately $13 million related to decommissioning and Winter Storm Atlas are being amortized over the moratorium period. These balances were previously being amortized over a 10 -year period ending September 30, 2024. The vegetation management regulatory asset of $14 million , previously unamortized, is also being amortized over the moratorium period. The change in amortization periods for these costs increased annual amortization expense by approximately $2.7 million . The June 16, 2017 settlement had no impact to base rates. Colorado Electric Rate Case filing: On December 19, 2016, Colorado Electric received approval from the CPUC to increase its annual revenues by $1.2 million to recover investments in a $63 million , 40 MW natural gas-fired combustion turbine and normal increases in operating expenses. This increase is in addition to approximately $5.9 million in annualized revenue being recovered under the Clean Air Clean Jobs Act construction financing rider. This turbine was completed in the fourth quarter of 2016, achieving commercial operation on December 29, 2016. The approval allowed a return on rate base of 6.02% for this turbine, with a 9.37% return on equity and a capital structure of 67.34% debt and 32.66% equity. Whereas, an authorized return on rate base of 7.4% was received for the remaining system investments, with a return on equity of 9.37% and an approved capital structure of 47.6% debt and 52.4% equity. On January 9, 2017, we filed an application with the CPUC for rehearing, reargument or reconsideration of the Commission’s December 19, 2016 decision which reduced our proposed $8.9 million annual revenue increase to $1.2 million . Concurrent with this application, we filed a motion for a Commissioner to recuse themselves from continuing to participate in any further proceedings in the rate review. On October 4, 2017, the Company filed an Opening Brief. The Company filed a Reply Brief on November 22, 2017. The matter is pending. We believe the CPUC made errors in their December decision by demonstrating bias, making decisions not supported by evidence, making findings inconsistent with cost-recovery provisions of the Colorado Clean Air-Clean Jobs Act and the Commission’s own prior decisions, and treating Colorado Electric differently than other regulated utilities in Colorado have been treated in similar situations. Gas Utilities Rate Activity On December 15, 2017, Arkansas Gas filed a rate review application with the APSC requesting an annual increase in revenue of approximately $30 million . The annual increase is based on a return on equity of 10.2% and a capital structure of 45.3% debt and 54.7% equity. This rate review was driven by approximately $160 million of investments made since 2016 to replace, upgrade and maintain Arkansas Gas’ approximately 5,500 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implemented in the fourth quarter of 2018. We are reviewing the impact of tax reform as it applies to the filing. On November 17, 2017, Wyoming Gas filed a rate review application with the WPSC requesting an annual increase in revenue of approximately $1.4 million for natural gas system improvements supporting its Northwest Wyoming customers. The annual increase is based on a return on equity of 10.2% and a capital structure of 46.0% debt and 54.0% equity. This rate review was driven by approximately $6 million of investments made since 2015 to replace, upgrade and maintain approximately 620 miles of natural gas transmission and distribution pipelines. If approved, new rates would be implemented in mid-2018. We are reviewing the impact of tax reform as it applies to the filing. On November 1, 2017, RMNG filed a rate review with the CPUC requesting recovery of $3.1 million , which includes $0.2 million of new revenue related to system safety and integrity expenditures on projects for the period of 2014 through 2018. This SSIR request was approved by the CPUC in December 2017, and is effective January 1, 2018. On October 3, 2017, RMNG filed a rate review application with the CPUC requesting an annual increase in revenue of $2.2 million and an extension of the SSIR to recover costs from 2018 through 2022. The annual increase is based on a return on equity of 12.25% and a capital structure of 53.37% debt and 46.63% equity. This rate review was driven by the impending expiration of the SSIR on May 31, 2018; this application requests a continuation of the SSIR through 2022. We are reviewing the impact of tax reform as it applies to the filing. Monthly, Arkansas Gas files for recovery of projects related to the replacement of eligible mains (MRP) and projects for the relocation of certain at risk meters (ARMRP). On February 1, 2018, Arkansas Gas requested MRP revenue of $2.8 million and ARMPR revenue of $0.5 million for assets placed in service between April 1, 2016 and December 31, 2017. Pursuant to the Arkansas Gas Tariff, the filed rates are effective the date filed. Annually, Arkansas Gas files for recovery of Stockton Storage revenue requirement through the Stockton Storage Acquisition Rates regulatory mechanism. On November 16, 2017 Arkansas Gas filed a request for recovery of $3.3 million for the revenue requirement year ended September 30, 2017. Rates were effective January 1, 2017. On October 2, 2017, Nebraska Gas Distribution filed with the NPSC requesting recovery of $6.8 million , which includes $0.3 million of increased annual revenue related to system safety and integrity expenditures on projects for the period of 2012 through 2017. This SSIR tariff was approved by the NPSC in January 2018, and went into effect on February 1, 2018. In February 2016, Arkansas Gas implemented new base rates resulting in a revenue increase of $8.0 million . The APSC modified a stipulation reached between the APSC Staff and all intervenors except the Attorney General and Arkansas Gas in its order issued on January 28, 2016. The modified stipulation revised the capital structure to 52% debt and 48% equity and also limited recovery of portions of cost related to incentive compensation.

Operating Leases_

Operating Leases:	12 Months Ended
	Dec. 31, 2017
Leases, Operating [Abstract]
Operating Leases	OPERATING LEASES We have entered into lease agreements for vehicles, equipment and office facilities. Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands): 2017 2016 2015 Rent expense $ 10,325 $ 9,568 $ 7,177 The following is a schedule of future minimum payments required under the operating lease agreements (in thousands): 2018 $ 5,030 2019 $ 3,840 2020 $ 1,957 2021 $ 918 2022 $ 808 Thereafter $ 3,085

Income Taxes_

Income Taxes:	12 Months Ended
	Dec. 31, 2017
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 uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the book and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their 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. As a result of the revaluation, deferred tax assets and liabilities were reduced by approximately $309 million . Of the $309 million , approximately $301 million is related to our regulated utilities and is reclassified to a regulatory liability. This regulatory liability will generally be amortized over the remaining life of the related assets using the normalization principles as specifically prescribed in the TCJA. In addition, as allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Company has recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation, for which the impacts could not be finalized upon issuance of the Company’s financial statements but reasonable estimates could be determined. The provisional amounts may change as the Company finalizes the analysis and computations, and such changes could be material to the Company’s future results of operations, cash flows or financial position. Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2017 2016 2015 Current: Federal $ (6,193 ) $ (21,806 ) $ 2,624 State (1,432 ) (1,797 ) 1,329 (7,625 ) (23,603 ) 3,953 Deferred: Federal 76,567 78,997 71,332 State 4,470 3,759 3,485 Tax credit amortization (45 ) (52 ) (113 ) 80,992 82,704 74,704 $ 73,367 $ 59,101 $ 78,657 Included in discontinued operations is a tax benefit of $8.4 million , $49 million and $101 million for 2017 , 2016 and 2015 , respectively. The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2017 2016 Deferred tax assets: Regulatory liabilities $ 90,742 $ 58,200 Employee benefits 18,724 28,873 Federal net operating loss 155,276 252,780 Other deferred tax assets (a) 74,561 83,675 Less: Valuation allowance (9,121 ) (9,263 ) Total deferred tax assets 330,182 414,265 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (b) (510,774 ) (782,674 ) Regulatory assets (26,245 ) (49,471 ) Goodwill (46,392 ) (60,544 ) State deferred tax liability (58,930 ) (50,258 ) Deferred costs (16,063 ) (18,551 ) Other deferred tax liabilities (8,298 ) (14,702 ) Total deferred tax liabilities (666,702 ) (976,200 ) Net deferred tax liability $ (336,520 ) $ (561,935 ) _______________ (a) Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability. (b) The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $309 million . Due to the regulatory construct, approximately $301 million of the revaluation was reclassified to a regulatory liability. The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax (net of federal tax effect) 0.9 1.2 1.5 Percentage depletion (0.6 ) (0.8 ) (0.7 ) Non-controlling interest (a) (1.8 ) (1.6 ) — Equity AFUDC (0.2 ) (0.5 ) (0.1 ) Tax credits (1.7 ) (0.4 ) (0.1 ) Transaction costs — 0.5 — Accounting for uncertain tax positions adjustment (0.2 ) (2.7 ) 0.8 Flow-through adjustments (b) (1.1 ) (2.1 ) (1.0 ) Other tax differences (0.9 ) 0.1 0.3 IRC 172(f) carryback claim (0.7 ) — — Tax Cuts & Jobs Act corporate rate reduction (c) (2.7 ) — — 26.0 % 28.7 % 35.7 % _________________________ (a) The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (b) Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. (c) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change. At December 31, 2017 , we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal Net Operating Loss Carryforward $ 739,184 2019 to 2037 State Net Operating Loss Carryforward $ 688,335 2017 to 2038 As of December 31, 2017 , we had a $1.3 million valuation allowance against the state NOL carryforwards. Our 2017 analysis of the ability to utilize such NOLs resulted in a slight increase in the valuation allowance of approximately $0.4 million , which resulted in an increase to tax expense. The valuation allowance adjustment was primarily attributable to a projected decrease in state taxable income for years beyond 2017. This projected decrease impacted the utilization of NOL carryforward in those states where the carryforward period is significantly shorter than the federal carryforward period of 20 years. In certain states, the carryforward period is limited to 5 years. Ultimate usage of these NOLs depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense. The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands): Changes in Uncertain Tax Positions Beginning balance at January 1, 2015 $ 32,192 Additions for prior year tax positions 3,285 Reductions for prior year tax positions (3,491 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2015 31,986 Additions for prior year tax positions 2,423 Reductions for prior year tax positions (19,174 ) Additions for current year tax positions — Settlements (11,643 ) Ending balance at December 31, 2016 3,592 Additions for prior year tax positions 358 Reductions for prior year tax positions (5,713 ) Additions for current year tax positions 5,026 Settlements — Ending balance at December 31, 2017 $ 3,263 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.2 million . We recognized no interest expense for the years ended December 31, 2017 and December 31, 2016 , and approximately $1.6 million for the year ended December 31, 2015 . We had no accrued interest (before tax effect) associated with income taxes at December 31, 2017 and December 31, 2016 . Black Hills Corporation and its subsidiaries are currently under examination by the IRS for the 2010 to 2012 tax years. A 30-day Letter was received in second quarter 2016 along with a Revenue Agent’s Report from the IRS in regard to the audit of the 2010 to 2012 tax years disallowing certain R&D credits and deductions claimed with respect to certain costs and projects. In response to the 30-day Letter, a protest was timely filed with IRS Appeals in the second quarter of 2016 and a final settlement at IRS Appeals is expected to be reached in 2018. Black Hills Gas, Inc. and subsidiaries, which files a separate consolidated tax return from Black Hills Corporation and subsidiaries, is under examination by the IRS for 2014. We had deferred a substantial amount of tax payments through various tax planning strategies including the deferral of approximately $125 million in income taxes attributable to the like-kind exchange effectuated in connection with the IPP Transaction and Aquila Transaction that occurred in 2008. The IRS had challenged our position with respect to the like-kind exchange. In the first quarter of 2016, we reached a settlement agreement in principle with IRS Appeals related to both the like-kind exchange transaction in addition to the R&D credits and deductions issues. In 2016, the settlement resulted in a reduction to the liability for unrecognized tax benefits of approximately $29 million excluding interest. Approximately $17 million of the reduction was to restore accumulated deferred income taxes and the remaining portion of approximately $12 million was reclassified to current taxes payable. As of December 31, 2017 , we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2018 . State tax credits have been generated and are available to offset future state income taxes. At December 31, 2017 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year Investment tax credit $ 20,285 2023 to 2036 Research and development $ 179 No expiration As of December 31, 2017 , we had a $7.8 million valuation allowance against the state tax credit carryforwards. The re-evaluation of our ability to utilize such credits resulted in an increase of the valuation allowance of approximately $1.2 million of which approximately $0.6 million resulted in an increase to tax expense. The remaining $0.6 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to tax expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to the impact of lower projected apportionment factors resulting in decreased state taxable income in years beyond 2017. Ultimate usage of these credits depends upon our future tax filings. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the state tax credit carryforwards, the offsetting amount will affect tax expense.

Other Comprehensive Income_

Other Comprehensive Income:	12 Months Ended
	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income	OTHER COMPREHENSIVE INCOME We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The following table details reclassifications out of AOCI and into net income. The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands): Location on the Consolidated Statements of Income (Loss) Amount Reclassified from AOCI December 31, 2017 December 31, 2016 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,941 ) $ (3,899 ) Commodity contracts (Loss) from discontinued operations 913 11,019 Commodity contracts Fuel, purchased power and cost of natural gas sold (243 ) (14 ) (2,271 ) 7,106 Income tax Income tax benefit (expense) 875 (2,702 ) Total reclassification adjustments related to cash flow hedges, net of tax $ (1,396 ) $ 4,404 Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 168 $ 194 Prior service cost (Loss) from discontinued operations 29 27 Actuarial gain (loss) Operations and maintenance (1,599 ) (1,881 ) Actuarial gain (loss) (Loss) from discontinued operations (58 ) (97 ) (1,460 ) (1,757 ) Income tax Income tax benefit (expense) (516 ) 533 Total reclassification adjustments related to defined benefit plans, net of tax $ (1,976 ) $ (1,224 ) Total reclassifications $ (3,372 ) $ 3,180 Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 231 (1,890 ) (1,659 ) Amounts reclassified from AOCI 1,912 (516 ) 944 2,340 Reclassification of certain tax effects from AOCI (3,384 ) — (3,616 ) (7,000 ) As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss) before reclassifications (20,302 ) (361 ) (1,985 ) (22,648 ) Amounts reclassified from AOCI 2,534 (6,938 ) 1,224 (3,180 ) As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 )

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash flow Information:	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Years ended December 31, 2017 2016 2015 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 28,191 $ 27,034 $ 25,039 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 3,198 $ 8,577 $ (1,498 ) Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (132,428 ) $ (113,627 ) $ (78,744 ) Income taxes (paid) refunded $ 1,775 $ (1,156 ) $ (1,202 )

Employee Benefit Plans_

Employee Benefit Plans:	12 Months Ended
	Dec. 31, 2017
Defined Benefit Plan [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS Defined Contribution Plans We sponsor 401(k) retirement savings plans (the 401(k) Plans). Participants in the 401(k) Plans may elect to invest a portion of their eligible compensation in the 401(k) Plans up to the maximum amounts established by the IRS. The 401(k) Plans provide employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plans provide either a Company Matching Contribution or a Non-Elective Safe Harbor Contribution for all eligible participants, depending upon the Plan in which the employee participates. Certain eligible participants receive a Company Retirement Contribution based on the participant’s age and years of service or a Company Discretionary Contribution, depending upon the pension plan in which the employee participates. Vesting of all Company contributions ranges from immediate vesting to graduated vesting at 20% per year with 100% vesting when the participant has 5 years of service with the Company. The SourceGas Retirement Savings Plan was merged into the Black Hills Corporation Retirement Savings Plan effective December 31, 2017. The plan design of the Black Hills Corporation 401(k) Plan will apply to all employees as of January 1, 2018. Defined Benefit Pension Plan (Pension Plan) At December 31, 2016 our three previous defined benefit pension plans consisting of the Black Hills Corporation Pension Plan, the Black Hills Utility Holding, Inc. Pension Plan and the SourceGas Retirement Plan were merged into one single plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service based criteria. The Pension Plan assets are held in a Master Trust. Due to the plan merger on December 31, 2016 , reporting beginning in 2017 no longer represents an undivided interest in the Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments. The expected rate of return on the Pension Plan assets is based on a targeted asset allocation range determined by the funded ratio of the plan. As of December 31, 2017 , the expected rate of return on pension plan assets was based on the targeted asset allocation range of 37% to 45% equity securities and 55% to 63% fixed-income securities and the expected rate of return from these asset categories. The expected rate of return on other postretirement plan assets was based on the targeted asset allocation range of 15% to 25% equity securities and 75% to 85% fixed-income securities and the expected rate of return from these asset categories. The expected long-term rate of return for investments was 6.25% and 6.75% for the Pension Plan 2017 and 2016 plan years, respectively. Our Pension Plan is funded in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows: 2017 2016 Equity 26% 28% Real estate 4 5 Fixed income 63 57 Cash 1 2 Hedge funds 6 8 Total 100% 100% Supplemental Non-qualified Defined Benefit Plans We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are not funded by the Company. Plan Assets We do not fund our Supplemental Plans. We fund on a cash basis as benefits are paid. Non-pension Defined Benefit Postretirement Healthcare Plans BHC sponsors retiree healthcare plans (Healthcare Plans) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plans for participating business units are pre-funded via VEBAs. Pre-65 retirees as well as a grandfathered group of post-65 Cheyenne Light, Fuel and Power (“CLFP”) retirees and a grandfathered group of post-65 former SourceGas employees who retired prior to January 1, 2017 receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible BHC and Black Hills Utility Holdings retirees is provided through an individual market healthcare exchange. Medicare-eligible SourceGas employees who retired after December 31, 2016 also receive retiree medical coverage through an individual market healthcare exchange. Plan Assets We fund the Healthcare Plans on a cash basis as benefits are paid. The Black Hills Utility Holding and SourceGas Postretirement - AWG Plans provide for partial pre-funding via VEBAs and a Grantor Trust. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Kansas and Iowa. We do not pre-fund the Healthcare Plans for those employees outside Arkansas, Kansas and Iowa. Plan Contributions Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands): 2017 2016 Defined Contribution Plan Company retirement contribution $ 10,223 $ 9,632 Matching contributions $ 9,811 $ 9,645 2017 2016 Defined Benefit Plans Defined Benefit Pension Plan $ 27,700 $ 14,200 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 4,332 $ 4,965 Supplemental Non-Qualified Defined Benefit Plans $ 3,217 $ 1,565 While we do not have required contributions, we expect to make approximately $13 million in contributions to our Pension Plan in 2018 . Fair Value Measurements Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels. The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,280 $ — $ 1,280 $ — $ 1,280 Common Collective Trust - Cash and Cash Equivalents — 2,184 — 2,184 — 2,184 Common Collective Trust - Equity — 109,496 — 109,496 — 109,496 Common Collective Trust - Fixed Income — 262,329 — 262,329 — 262,329 Common Collective Trust - Real Estate — 1,728 — 1,728 15,701 17,429 Hedge Funds — — — — 23,625 23,625 Total investments measured at fair value $ — $ 377,017 $ — $ 377,017 $ 39,326 $ 416,343 Pension Plan December 31, 2016 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,325 $ — $ 1,325 $ — $ 1,325 Common Collective Trust - Cash and Cash Equivalents — 5,307 — 5,307 — 5,307 Common Collective Trust - Equity — 101,020 — 101,020 — 101,020 Common Collective Trust - Fixed Income — 209,815 — 209,815 — 209,815 Common Collective Trust - Real Estate — 2,349 — 2,349 15,563 17,912 Hedge Funds — — — — 29,316 29,316 Total investments measured at fair value $ — $ 319,816 $ — $ 319,816 $ 44,879 $ 364,695 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 4,671 $ — $ — $ 4,671 $ — $ 4,671 Equity Securities 1,374 — — 1,374 — 1,374 Intermediate-term Bond — 2,576 — 2,576 — 2,576 Total investments measured at fair value $ 6,045 $ 2,576 $ — $ 8,621 $ — $ 8,621 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2016 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 111 $ — — $ 111 — $ 111 Equity Securities 1,154 — — $ 1,154 — 1,154 Registered Investment Company Trust - Money Market Mutual Fund — 4,732 — $ 4,732 — 4,732 Intermediate-term Bond — 2,473 — $ 2,473 — 2,473 Total investments measured at fair value $ 1,265 $ 7,205 $ — $ 8,470 $ — $ 8,470 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above. Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows: Cash and Cash Equivalents: This represents an investment in Invesco Treasury Portfolio, which is a short-term investment trust, as well as an investment in Northern Institutional Government Assets Portfolio, which is described as a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Equity Securities: These represent investments in a combination of equity positions for mainly large cap core allocation and Exchange Trade Funds (ETFs) for diversification into the other sectors of the economy. ETFs are a basket of securities traded like individual stocks on the exchange. Value of equity securities held at year end are based on published market quotations of active markets. The ETF funds can be redeemed on a daily basis at their market price and have no redemption restrictions. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Intermediate-term bond: This is comprised of a diversified pool of high quality, individual municipal bonds. Pricing is evaluated using multi-dimensional relational models, as well as a series of matrices using Standard Inputs, including Municipal Securities Rule Making Board (MSRB) reported trades and material event notices, plus Municipal Market Data (MMD) benchmark yields and new issue data. As the models use observable inputs and standard data, the investments are categorized as Level 2. AXA Equitable General Fixed Income Fund : This fund is a diversified portfolio, primarily composed of fixed income instruments. Assets are invested in long-term holdings, such as commercial, agricultural and residential mortgages, publicly traded and privately placed bonds and real estate as well as short-term bonds. Fair values of mortgage loans are measured by discounting future contractual cash flows to be received on the mortgage loans using interest rates of loans with similar characteristics. The discount rate is derived from taking the appropriate U.S. Treasury rate with a like term. The fair value of public fixed maturity securities are generally based on prices obtained from independent valuation service providers with reasonableness prices compared with directly observable market trades. The fair value of privately placed securities are determined using a discounted cash flow model. These models use observable inputs with a discount rate based upon the average of spread surveys collected from private market intermediaries and industry sector of the issuer. The Plan’s investments in the AXA Equitable General Fixed Income Fund are categorized as Level 2. Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2. Common Collective Trust-Real Estate Fund : This fund is valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. The funds without participant withdrawal limitations are categorized as Level 2. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance. Common Collective Trust-Real Estate Fund : This is the same fund as above except that certain of the funds’ assets contain participant withdrawal policies with restrictions on redemption and are therefore not included in the fair value hierarchy. Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. Generally, shares may be redeemed at the end of each quarter, with a 65 day notice and are limited to a percentage of total net asset value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI (in thousands): Benefit Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans As of December 31, 2017 2016 2017 2016 2017 2016 Change in benefit obligation: Projected benefit obligation at beginning of year $ 440,179 $ 356,575 $ 43,869 $ 40,219 $ 68,023 $ 48,077 Transfer from SourceGas Acquisition — 75,254 — — — 15,091 Service cost 7,034 7,619 2,937 2,099 2,300 1,757 Interest cost 15,520 15,743 1,276 1,257 2,141 1,942 Actuarial (gain) loss (a) 36,661 7,001 247 2,049 (396 ) 2,808 Amendments — — — — 265 2,203 Benefits paid (24,669 ) (22,013 ) (3,217 ) (1,755 ) (4,332 ) (4,965 ) Plan participants’ contributions — — — — 1,338 1,110 Projected benefit obligation at end of year $ 474,725 $ 440,179 $ 45,112 $ 43,869 $ 69,339 $ 68,023 ____________________ (a) Increase from 2016 is primarily the result of a decrease in the discount rate. Employee Benefit Plan Assets Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans (a) As of December 31, 2017 2016 2017 2016 2017 2016 Change in fair value of plan assets: Beginning fair value of plan assets $ 364,695 $ 288,622 $ — $ — $ 8,470 $ 4,681 Transfer from SourceGas Acquisition — 53,067 — — — 3,340 Investment income (loss) 48,617 30,819 — — 120 256 Employer contributions 27,700 14,200 3,217 1,755 3,025 4,048 Retiree contributions — — — — 1,338 1,110 Benefits paid (24,669 ) (22,013 ) (3,217 ) (1,755 ) (4,332 ) (4,965 ) Ending fair value of plan assets $ 416,343 $ 364,695 $ — $ — $ 8,621 $ 8,470 ____________________ (a) Assets of VEBAs and Grantor Trust. The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Regulatory assets $ 72,756 $ 66,640 $ — $ — $ 11,507 $ 11,401 Current liabilities $ — $ — $ 1,372 $ 1,583 $ 4,423 $ 4,360 Non-current assets $ — $ — $ — $ — $ 69 $ 21 Non-current liabilities $ 58,381 $ 75,484 $ 43,739 $ 42,286 $ 56,365 $ 55,214 Regulatory liabilities $ 5,232 $ 5,195 $ — $ — $ 3,334 $ 3,419 Accumulated Benefit Obligation As of December 31 (in thousands) Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Accumulated Benefit Obligation (a) $ 450,394 $ 416,786 $ 41,243 $ 32,090 $ 69,339 $ 68,023 ____________________ (a) The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2017 and 2016 represents that obligation for the five postretirement plans maintained by BHC. Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service cost $ 7,034 $ 7,619 $ 6,093 $ 1,546 $ 1,335 $ 1,380 $ 2,300 $ 1,757 $ 1,808 Interest cost 15,520 15,743 15,522 1,276 1,257 1,455 2,141 1,942 1,801 Expected return on assets (24,517 ) (23,062 ) (19,470 ) — — — (315 ) (279 ) (131 ) Net amortization of prior service cost 58 58 58 2 2 2 (411 ) (428 ) (428 ) Recognized net actuarial loss (gain) 4,007 7,173 11,037 1,001 829 1,081 499 335 408 Settlement expense (a) — 10 — — — — — — — Net periodic expense $ 2,102 $ 7,541 $ 13,240 $ 3,825 $ 3,423 $ 3,918 $ 4,214 $ 3,327 $ 3,458 ____________________ (a) Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year. AOCI For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Net (gain) loss $ 10,056 $ 8,472 $ 6,639 $ 7,132 $ 1,309 $ 1,595 Prior service cost (gain) 21 31 4 5 (542 ) (694 ) Reclassification of certain tax effects from AOCI 2,087 — 1,371 — 158 — Total AOCI $ 12,164 $ 8,503 $ 8,014 $ 7,137 $ 925 $ 901 The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Net loss $ 5,610 $ 650 $ 141 Prior service cost (credit) 38 1 (258 ) Total net periodic benefit cost expected to be recognized during calendar year 2018 $ 5,648 $ 651 $ (117 ) Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine benefit obligations: 2017 2016 2015 2017 2016 2015 2017 2016 2015 Discount rate 3.71 % 4.27 % 4.58 % 3.56 % 4.02 % 4.28 % 3.60 % 3.96 % 4.17 % Rate of increase in compensation levels 3.43 % 3.47 % 3.51 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2017 2016 2015 2017 2016 2015 2017 2016 2015 Discount rate (a) 4.27 % 4.50 % 4.19 % 4.02 % 4.28 % 4.19 % 4.05 % 4.18 % 3.82 % Expected long-term rate of return on assets (b) 6.75 % 6.87 % 6.75 % N/A N/A N/A 3.88 % 3.83 % 3.00 % Rate of increase in compensation levels 3.47 % 3.42 % 3.76 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the merged Black Hills Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs. (b) The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost. The healthcare benefit obligation was determined at December 31 as follows: 2017 2016 (a) Trend Rate - Medical Pre-65 for next year - All Plans 7.00% 6.10% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2024 Post-65 for next year - All Plans 5.00% 5.10% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2026 2023 _____________________________ (a) The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas. We do not pre-fund our supplemental plans or three of the five healthcare plans. The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands): Change in Assumed Trend Rate Impact on December 31, 2017 Accumulated Postretirement Benefit Obligation Impact on 2018 Service and Interest Cost Increase 1% $ 2,968 $ 148 Decrease 1% $ (2,534 ) $ (126 ) Beginning in 2016, the Company changed the method used to estimate the service and interest cost components of the net periodic pension, supplemental non-qualified defined benefit and other postretirement benefit costs. See “Pension and Postretirement Benefit Obligations” within our Critical Accounting Policies in Item 7 on Form 10-K for additional details. The following benefit payments, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-Pension Defined Benefit Postretirement Healthcare Plans 2018 $ 21,495 $ 1,372 $ 5,633 2019 $ 23,238 $ 1,617 $ 6,231 2020 $ 27,203 $ 1,558 $ 6,328 2021 $ 26,990 $ 1,773 $ 6,072 2022 $ 27,427 $ 1,872 $ 5,920 2023-2027 $ 154,771 $ 11,304 $ 26,365

Commitments And Contingencies_

Commitments And Contingencies:	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	COMMITMENTS AND CONTINGENCIES Power Purchase and Transmission Services Agreements Through our subsidiaries, we have the following significant long-term power purchase contracts with non-affiliated third-parties: • Black Hills Wyoming sold its CTII 40 MW natural gas-fired generating unit to the City of Gillette, Wyoming on September 3, 2014. Under the terms of the sale, Black Hills Wyoming entered into ancillary agreements to operate CTII, provide use of shared facilities including a ground lease and dispatch generation services. In addition, the agreement includes a 20 -year economy energy PPA that contains a sharing arrangement in which the parties share the savings of wholesale power purchases made when market power prices are less than the cost of operating the generating unit. • South Dakota Electric’s PPA with PacifiCorp, expiring December 31, 2023 , for the purchase of 50 MW of electric capacity and energy from PacifiCorp’s system. The price paid for the capacity and energy is based on the operating costs of one of PacifiCorp’s coal-fired electric generating plants. • South Dakota Electric’s firm point-to-point transmission service agreement with PacifiCorp that expires December 31, 2023 . The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp. • Wyoming Electric’s PPA with Duke Energy’s Happy Jack wind site, expiring September 3, 2028 , provides up to 30 MW of wind energy from Happy Jack to Wyoming Electric. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric. • Wyoming Electric’s PPA with Duke Energy’s Silver Sage wind site, expiring September 30, 2029 , provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 20 MW of energy from Silver Sage to South Dakota Electric. • Colorado Electric’s REPA with AltaGas expiring October 16, 2037 , provides up to 14.5 MW of wind energy from the Busch Ranch Wind Farm in which Colorado Electric owns a 50% undivided ownership interest. Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands): 2017 2016 2015 PPA with PacifiCorp $ 13,218 $ 12,221 $ 13,990 Transmission services agreement with PacifiCorp $ 1,671 $ 1,428 $ 1,213 PPA with Happy Jack $ 3,846 $ 3,836 $ 3,155 PPA with Silver Sage $ 4,934 $ 4,949 $ 4,107 Busch Ranch Wind Farm $ 1,966 $ 2,071 $ 1,734 PPAs with Cargill (a) $ — $ 10,995 $ 16,112 ________________ (a) PPAs with Cargill expired on December 31, 2016. Other Gas Supply Agreements Our Utilities also purchase natural gas, including transportation and storage capacity to meet customers’ needs, under short-term and long-term purchase contracts. These contracts extend to 2044 . Purchase Commitments We maintain natural gas supply contracts with several vendors that generally cover a period of up to one year. Commitments for estimated baseload gas volumes are established prior to the beginning of the month under these contracts on a monthly basis at contractually negotiated prices. Commitments for incremental daily purchases are made as necessary during the month based on requirements in accordance with the terms of the individual contract. Our Gas Utilities segment has commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. At December 31, 2017 , the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): CIG Rockies NNG-Ventura NWPL-Wyoming EP-San Juan Basin Other 2018 5,784,827 3,759,500 1,298,970 278,600 30,562 2019 5,776,125 3,704,300 786,470 287,000 — 2020 75,075 3,660,000 — 206,600 — 2021 — 3,650,000 — — — 2022 — 1,810,000 — — — Purchases under these contracts totaled $65 million, $31 million and $48 million for 2017, 2016 and 2015, respectively. The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands): Power Purchase Agreements Transportation, storage and coal agreements 2018 $ 28,041 $ 121,485 2019 $ 6,837 $ 122,351 2020 $ 6,837 $ 117,332 2021 $ 6,203 $ 107,918 2022 $ 6,203 $ 87,393 Thereafter $ 6,204 $ 202,831 Future Purchase Agreement - Related Party Wyoming Electric’s PPA for 60 MW of capacity and energy from Black Hills Wyoming’s Wygen I generating facility expiring on December 31, 2022 , includes an option for Wyoming Electric to purchase Black Hills Wyoming’s ownership in the Wygen I facility. The purchase price related to the option is $2.6 million per MW which is the equivalent per MW of the pre-construction estimated cost of the Wygen III plant, which was completed in April 2010. This option purchase price is adjusted for capital additions and reduced by an amount equal to annual depreciation based on a 35 -year life starting January 1, 2009. The purchase option would be subject to WPSC and FERC approval in order to obtain regulatory treatment. Power Sales Agreements Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties: • During periods of reduced production at Wygen III in which MDU owns a portion of the capacity, or during periods when Wygen III is off-line, MDU will be provided with 25 MW from our other generation facilities or from system purchases with reimbursement of costs by MDU. This agreement expires January 31, 2023. • South Dakota Electric has an agreement to serve MDU capacity and energy up to a maximum of 50 MW in excess of Wygen III ownership. This agreement expires December 31, 2023. • During periods of reduced production at Wygen III in which the City of Gillette owns a portion of the capacity, or during periods when Wygen III is off-line, we will provide the City of Gillette with its first 23 MW from our other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which expires September 3, 2019, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves. • South Dakota Electric has a PPA with MEAN expiring May 31, 2023 . This contract is unit-contingent on up to 10 MW from Neil Simpson II and up to 10 MW from Wygen III based on the availability of these plants. The capacity purchase requirements decrease over the term of the agreement. • South Dakota Electric has an agreement from January 1, 2017 through December 31, 2021 to provide 50 MW of energy to Cargill (assigned to Macquarie on January 3, 2018) during heavy and light load timing intervals. Related Party Lease Colorado Electric’s PPA with Black Hills Colorado IPP expiring on December 31, 2031 , provides 200 MW of power to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines. This PPA is accounted for as a capital lease whereby Colorado Electric, as lessee, has included the combined-cycle turbines as property, plant and equipment along with the related lease obligation and Black Hills Colorado IPP, as lessor, has recorded a lease receivable. Segment revenue and expenses associated with the PPA have been impacted by the lease accounting. The effect of the lease accounting is eliminated in corporate consolidations. Reimbursement Agreement We have a reimbursement agreement in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due in 2027 and the 2009B bonds of $7.0 million due in 2021 . In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. Environmental Matters We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies. Solid Waste Disposal Various materials used at our facilities are subject to disposal regulations. Our Osage plant, permanently retired on March 21, 2014, had an on-site ash impoundment that was near capacity. An application to close the impoundment was approved on April 13, 2012. Site closure work was completed in 2013 with the state providing closure certification in 2014. Post closure monitoring activities will continue for 30 years following the closure certification date. In September 2013, Osage also received a permit to close the small industrial rubble landfill. Site work was completed with the state providing closure certification in 2014. Post closure monitoring will continue for 30 years following the closure certification date. Our W.N. Clark plant, which has been retired, previously delivered coal ash to a permitted, privately-owned landfill. While we do not believe that any substances from our solid waste disposal activities will pollute underground water, we can provide no assurance that pollution will not occur over time. In this event, we could incur material costs to mitigate any resulting damages. Reclamation Liability For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under its land lease for Busch Ranch, Colorado Electric is required to reclaim all land where it has placed wind turbines. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under its mining permit, WRDC is required to reclaim all land where it has mined coal reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. See Note 8 for additional information. Manufactured Gas Processing As a result of the Aquila Transaction, we acquired whole and partial liabilities for several former manufactured gas processing sites in Nebraska and Iowa which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.5 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.0 million regulatory asset for manufactured gas processing sites; see Note 1. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties. As of December 31, 2017 , our estimated liabilities for Iowa’s MGP sites currently range from approximately $2.6 million to $6.1 million for which we had $2.6 million accrued for remediation of sites as of December 31, 2017 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. For additional information on environmental matters, see Item 1 in this Annual Report on Form 10-K. Legal Proceedings In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements. In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities.

Guarantees_

Guarantees:	12 Months Ended
	Dec. 31, 2017
Guarantees [Abstract]
Guarantees	GUARANTEES We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements include indemnification for reclamation and surety bonds and a contract performance guarantee. We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2017 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 58,221 Ongoing $ 58,221 _______________________ (a) We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Discontinued Operations_

Discontinued Operations:	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS Results of operations for discontinued operations have been classified as Income from discontinued operations, net of income taxes in the accompanying Consolidated Statements of Income. Current assets, noncurrent assets, current liabilities and non-current liabilities of the discontinued operations have been reclassified and reflected on the accompanying Consolidated Balance Sheets as “Current assets held for sale,” “Noncurrent assets held for sale,” “Current liabilities held for sale,” and “Noncurrent liabilities held for sale”, respectively. Prior periods relating to our discontinued operations have also been reclassified to reflect consistency within our consolidated financial statements. Oil and Gas Segment On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90% of our oil and gas properties. We have executed agreements to sell all our operated properties and have only non-operated assets left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018. We are in the process of divesting our Oil and Gas segment; therefore, we performed a fair value assessment of the assets and liabilities classified as held for sale. We evaluated our disposal groups classified as held for sale based on the lower of carrying value or fair value less cost to sell. The market approach was based on our recent fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties. There is risk involved when determining the fair value of assets, as there may be unforeseen events and changes in circumstances and market conditions that have a material impact on the estimated amount and timing of future cash flows. In addition, the fair value of the assets and liabilities could be different using different estimates and assumptions in the valuation techniques used. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale are reasonable based on the information that was known when the estimates were made. At December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required an after-tax write down of $13 million . There were no adjustments made to the fair value of our held for sale liabilities. Total assets and liabilities of BHEP at December 31, 2017 have been classified as Current assets held for sale and Current liabilities held for sale on the accompanying Consolidated Balance Sheets due to the expected final disposals occurring by mid-year 2018. Held for sale assets and liabilities at December 31, 2016 are classified as current and non-current. As of (in thousands) December 31, 2017 December 31, 2016 Other current assets $ 10,360 $ 11,401 Derivative assets, current and noncurrent — 153 Deferred income tax assets, noncurrent, net 16,966 26,329 Property, plant and equipment, net 56,916 82,812 Other current liabilities (18,966 ) (9,834 ) Derivative liabilities, current and noncurrent — (1,586 ) Other noncurrent liabilities (22,808 ) (22,803 ) Net assets $ 42,468 $ 86,472 At December 31, 2017 and 2016, the Oil and Gas segment’s net deferred tax assets were primarily comprised of basis differences on oil and gas properties. BHEP’s accrued liabilities at December 31, 2017 and 2016 consisted primarily of accrued royalties, payroll and property taxes. Other liabilities at December 31, 2017 and 2016 consisted primarily of ARO obligations relating to plugging and abandonment of oil and gas wells. Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands): For the Years Ended December 31, 2017 December 31, 2016 December 31, 2015 Revenue $ 25,382 $ 34,058 $ 43,283 Operations and maintenance 22,872 27,187 35,461 Depreciation, depletion and amortization 7,521 13,510 28,838 Impairment of long-lived assets 20,385 106,957 249,608 Total operating expenses 50,778 147,654 313,907 Operating (loss) (25,396 ) (113,596 ) (270,624 ) Interest income (expense), net 181 698 931 Other income (expense), net (297 ) 110 (378 ) Impairment of equity investments — — (4,405 ) Income tax benefit (expense) 8,413 48,626 100,817 (Loss) from discontinued operations $ (17,099 ) $ (64,162 ) $ (173,659 ) Full Cost Accounting Historically, we used the full cost method of accounting for oil and gas production activities. Under the full cost method, costs related to acquisition, exploration and estimated future expenditures to be incurred in developing proved reserves as well as estimated reclamation and abandonment costs, net of estimated salvage values are capitalized. These costs are amortized using a unit-of-production method based on volumes produced and proved reserves. Any conveyances of properties, including gains or losses on abandonment of properties, are typically treated as adjustments to the cost of the properties with no gain or loss recognized. Costs directly associated with unproved properties and major development projects, if any, are excluded from the costs to be amortized. These excluded costs are subsequently included within the costs to be amortized when it is determined whether or not proved reserves can be assigned to the properties. The properties excluded from the costs to be amortized are assessed for impairment at least annually and any amount of impairment is added to the costs to be amortized. Under the full cost method, net capitalized costs, less accumulated amortization and related deferred income taxes, are subject to a ceiling test which limits the pooled costs to the aggregate of the discounted value of future net revenue attributable to proved natural gas and crude oil reserves using a discount rate defined by the SEC, plus the lower of cost or market value of unevaluated properties. Future net cash flows are estimated based on SEC-defined end-of-period commodity prices adjusted for contracted price changes and held constant for the life of the reserves. An average price is calculated using the price at the first day of each month for each of the preceding 12 months. If the net capitalized costs exceed the full cost “ceiling” at period end, a permanent non-cash write-down would be charged to earnings in that period. Impairment of long-lived assets As discussed above, at December 31, 2017, the fair value of our held for sale assets was less than our carrying value, which required a write down of $20 million . There were no adjustments made to the fair value of our held for sale liabilities. As a result of continued low commodity prices throughout 2016, we recorded non-cash ceiling test impairments of oil and gas assets totaling approximately $92 million for the year ended December 31, 2016. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.48 per Mcf, adjusted to $2.25 per Mcf at the wellhead; for crude oil, the average NYMEX price was $42.75 per barrel, adjusted to $37.35 per barrel at the wellhead. In 2015, we recorded a non-cash ceiling test impairment of oil and gas assets totaling approximately $250 million for the year ended December 31, 2015. In determining the ceiling value of our assets, we utilized the average of the quoted prices from the first day of each month from the previous 12 months. For natural gas, the average NYMEX price was $2.59 per Mcf, adjusted to $1.27 per Mcf at the wellhead; for crude oil, the average NYMEX price was $50.28 per barrel, adjusted to $44.72 per barrel at the wellhead. During the second quarter of 2016, certain non-core assets were identified that were not suitable for inclusion in a possible Cost of Service Gas Program. We assessed these assets for impairment in accordance with ASC 360. We valued the assets applying a market method approach utilizing assumptions consistent with similar known and measurable transactions and determined that the carrying amount exceeded the fair value. As a result, we recorded a pre-tax impairment of depreciable properties at June 30, 2016 of $14 million , in addition to the ceiling test impairments noted above. Equity investments in unconsolidated subsidiaries BHEP owned a 25% interest in a pipeline and gathering system, accounted for under the equity method of accounting. During the second quarter of 2015, due to sustained low commodity prices, recurring operating losses and future expectations we reviewed this investment interest for impairment utilizing the other-than-temporary impairment model under ASC 820, Fair Value Measurements . We valued the investment applying a market method approach utilizing assumptions consistent with similar known and measurable transactions. The carrying amount of this equity method investment exceeded the fair value, and we concluded the decline was considered to be other than temporary. As a result, we recorded a pre-tax impairment loss in 2015 of $4.4 million , the difference between the carrying amount and the fair value of the investment. In December of 2015, we sold our 25% interest in this pipeline and gathering system.

Oil and Gas Reserves (Unaudited

Oil and Gas Reserves (Unaudited):	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Reserves (Unaudited)	OIL AND GAS RESERVES (Unaudited) On November 1, 2017, we initiated the process of divesting all Oil and Gas segment assets in order to fully exit the oil and gas business. On November 1, 2017, we stopped the use of the full-cost method of accounting for our oil and gas business. The assets and liabilities have been classified as held for sale and the results of operations are included in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. As a result, our oil and gas reserves are no longer considered significant. For more information, see Note 21 . Costs Incurred Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands): 2016 2015 Acquisition of properties: Proved $ — $ 1,407 Unproved 910 669 Exploration costs 1,102 35,434 Development costs 4,657 128,998 Asset retirement obligations incurred — 566 Total costs incurred $ 6,669 $ 167,074 Reserves The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and 2015 and a reconciliation of the changes between these dates. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 30 years of practical experience in petroleum engineering and over 28 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding. 2016 2015 Oil Gas NGL Oil Gas NGL (in Mbbls of oil and NGL, and MMcf of gas) Proved developed and undeveloped reserves: Balance at beginning of year 3,450 73,412 1,752 4,276 65,440 1,720 Production (a) (319 ) (9,430 ) (133 ) (371 ) (10,058 ) (102 ) Sales (570 ) (1,291 ) (17 ) (11 ) (828 ) — Additions - extensions and discoveries 3 52 — 199 24,462 232 Revisions to previous estimates (322 ) (8,173 ) 110 (643 ) (5,604 ) (98 ) Balance at end of year 2,242 54,570 1,712 3,450 73,412 1,752 Proved developed reserves at end of year included above 2,242 54,570 1,712 3,436 73,390 1,752 Proved undeveloped reserves at the end of year included in above — — — 14 22 — NYMEX prices $ 42.75 $ 2.48 $ — (b) $ 50.28 $ 2.59 $ — (b) Well-head reserve prices (c) $ 37.35 $ 2.25 $ 11.92 $ 44.72 $ 1.27 $ 18.96 ________________________ (a) Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production. (c) For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54 /Mcf for Piceance, $0.92 /Mcf for San Juan and $0.53 /Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable. Capitalized Costs Following is information concerning capitalized costs for the years ended December 31 (in thousands): 2016 2015 Unproved oil and gas properties $ 18,547 $ 47,254 Proved oil and gas properties 1,043,558 1,008,466 Gross capitalized costs 1,062,105 1,055,720 Accumulated depreciation, depletion and amortization and valuation allowances (1,000,091 ) (888,775 ) Net capitalized costs $ 62,014 $ 166,945 Results of Operations For more on oil and gas producing activities included in discontinued operations, see Note 21. Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands): 2016 2015 Revenue $ 34,058 $ 43,283 Production costs 17,231 19,762 Depreciation, depletion and amortization 12,574 28,062 Impairment of long-lived assets 106,957 249,608 Total costs 136,762 297,432 Results of operations from producing activities before tax (102,704 ) (254,149 ) Income tax benefit (expense) 37,916 93,743 Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (64,788 ) $ (160,406 ) Unproved Properties Unproved properties not subject to amortization at December 31, 2016 and 2015 consisted mainly of exploration costs on various existing work-in-progress projects as well as leasehold acquired through significant natural gas and oil property acquisitions and through direct purchases of leasehold. We capitalized approximately $0.9 million and $1.0 million of interest during 2016 and 2015 , respectively, on significant investments in unproved properties that were not yet included in the amortization base of the full-cost pool. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands): 2016 2015 Prior Total Leasehold acquisition cost $ 963 $ — $ — $ 963 Exploration cost 532 441 — 973 Capitalized interest 50 23 — 73 Total $ 1,545 $ 464 $ — $ 2,009 Standardized Measure of Discounted Future Net Cash Flows Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands): 2016 2015 Future cash inflows $ 246,221 $ 295,173 Future production costs (166,248 ) (146,552 ) Future development costs, including plugging and abandonment (18,333 ) (24,833 ) Future net cash flows 61,640 123,788 10% annual discount for estimated timing of cash flows (26,574 ) (44,760 ) Standardized measure of discounted future net cash flows $ 35,066 $ 79,028 The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands): 2016 2015 Standardized measure - beginning of year $ 79,028 $ 183,022 Sales and transfers of oil and gas produced, net of production costs (4,314 ) (29,948 ) Net changes in prices and production costs (32,698 ) (127,199 ) Extensions, discoveries and improved recovery, less related costs — 15,718 Changes in future development costs 1,825 (7,387 ) Development costs incurred during the period — 27,211 Revisions of previous quantity estimates (7,477 ) (6,941 ) Accretion of discount 7,903 18,870 Net change in income taxes — 5,682 Sales of reserves (9,201 ) — Standardized measure - end of year $ 35,066 $ 79,028 Changes in the standardized measure from “revisions of previous quantity estimates” were driven by reserve revisions, modifications of production profiles and timing of future development. For all years presented, we had minimal net reserve revisions to prior estimates due to performance. Production forecast modifications were generally made at the well level each year through the reserve review process. These production profile modifications were based on incorporation of the most recent production information and applicable technical studies. Timing of future development investments were reviewed each year and were often modified in response to current market conditions for items such as permitting and service availability.

Quarterly Historical Data (Unau

Quarterly Historical Data (Unaudited):	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Historical Data (Unaudited)	QUARTERLY HISTORICAL DATA (Unaudited) The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2017 and 2016 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2017 Revenue $ 547,528 $ 341,829 $ 335,611 $ 455,298 Operating income (loss) $ 150,186 $ 69,796 $ 79,559 $ 117,195 Income (loss) from continuing operations $ 81,715 $ 25,927 $ 32,898 $ 67,835 Income (loss) from discontinued operations $ (1,569 ) $ (616 ) $ (1,300 ) $ (13,614 ) Net income attributable to noncontrolling interest $ (3,623 ) $ (3,116 ) $ (3,935 ) $ (3,568 ) Net income (loss) available for common stock $ 76,523 $ 22,195 $ 27,663 $ 50,653 Amounts attributable to common shareholders: Net income (loss) from continuing operations $ 78,092 $ 22,811 $ 28,963 $ 64,267 Net income (loss) from discontinued operations $ (1,569 ) $ (616 ) $ (1,300 ) $ (13,614 ) Net income (loss) available for common stock $ 76,523 $ 22,195 $ 27,663 $ 50,653 Income (loss) per share for continuing operations - Basic $ 1.47 $ 0.43 $ 0.54 $ 1.21 Income (loss) per share for discontinued operations - Basic $ (0.03 ) $ (0.01 ) $ (0.02 ) $ (0.26 ) Earnings (loss) per share - Basic $ 1.44 $ 0.42 $ 0.52 $ 0.95 Income (loss) per share for continuing operations - Diluted $ 1.42 $ 0.41 $ 0.52 $ 1.17 Income (loss) per share for discontinued operations - Diluted $ (0.03 ) $ (0.01 ) $ (0.02 ) $ (0.25 ) Earnings (loss) per share - Diluted 1.39 0.40 0.50 0.92 Dividends paid per share $ 0.445 $ 0.445 $ 0.445 $ 0.475 Common stock prices - High $ 67.02 $ 72.02 $ 71.01 $ 69.79 Common stock prices - Low $ 60.02 $ 65.37 $ 67.08 $ 57.01 Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter. Included within the Income (loss) from continuing operations in the fourth quarter of 2017 is a net tax benefit of $7.6 million from the impact of the TCJA, as well as a tax benefit of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition. Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13.0 million . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2016 Revenue $ 441,584 $ 317,795 $ 324,147 $ 455,390 Operating income (loss) $ 91,281 $ 63,725 $ 70,844 $ 110,330 Income (loss) from continuing operations $ 45,320 $ 21,128 $ 24,964 $ 55,381 Income (loss) from discontinued operations $ (5,270 ) $ (17,845 ) $ (7,080 ) $ (33,967 ) Net income attributable to noncontrolling interest $ (48 ) $ (2,614 ) $ (3,753 ) $ (3,246 ) Net income (loss) available for common stock $ 40,002 $ 669 $ 14,131 $ 18,168 Amounts attributable to common shareholders: Net income (loss) from continuing operations 45,272 18,514 21,211 52,135 Net income (loss) from discontinued operations (5,270 ) (17,845 ) (7,080 ) (33,967 ) Net income (loss) available for common stock 40,002 669 14,131 18,168 Income (loss) per share for continuing operations - Basic $ 0.88 $ 0.36 $ 0.41 $ 0.98 Income (loss) per share for discontinued operations - Basic (0.10 ) (0.35 ) (0.14 ) (0.64 ) Earnings (loss) per share - Basic $ 0.78 $ 0.01 $ 0.27 $ 0.34 Income (loss) per share for continuing operations - Diluted $ 0.87 $ 0.35 $ 0.39 $ 0.96 Income (loss) per share for discontinued operations - Diluted (0.10 ) (0.34 ) (0.13 ) (0.63 ) Earnings (loss) per share - Diluted $ 0.77 $ 0.01 $ 0.26 $ 0.33 Dividends paid per share $ 0.420 $ 0.420 $ 0.420 $ 0.420 Common stock prices - High $ 61.13 $ 63.53 $ 64.58 $ 62.83 Common stock prices - Low $ 44.65 $ 56.16 $ 56.86 $ 54.76 Income from continuing operations for each quarter of 2016 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $15 million during the first quarter, $4.1 million during the second quarter, $4.1 million during the third quarter and $5.5 million during the fourth quarter. Included with loss from discontinued operations in each quarter of 2016 are non-cash impairments of oil and gas properties. We recorded after-tax impairments of oil and gas properties of $8.8 million during the first quarter, $16 million during the second quarter, $7.9 million during the third quarter and $34 million during the fourth quarter.

Schedule II Consolidated Valuat

Schedule II Consolidated Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2017
Valuation and Qualifying Accounts [Abstract]
Schedule II Consolidated Valuation and Qualifying Accounts	SCHEDULE II BLACK HILLS CORPORATION CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS YEARS ENDED DECEMBER 31, 2017, 2016 AND 2015 Description Balance at Beginning of Year Adjustments (a) Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year (in thousands) Allowance for doubtful accounts: 2017 $ 2,392 $ — $ 4,926 $ 8,262 $ (12,499 ) $ 3,081 2016 $ 1,741 $ 2,158 $ 2,704 $ 4,915 $ (9,126 ) $ 2,392 2015 $ 1,516 $ — $ 3,860 $ 4,132 $ (7,767 ) $ 1,741

Business Description (Policies)

Business Description (Policies)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business Description	Business Description Black Hills Corporation is a customer-focused, growth-oriented, vertically-integrated utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities, Gas Utilities, Power Generation and Mining. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Segment Reporting Our reportable segments are based on our method of internal reporting, which is generally segregated by differences in products, services and regulation. All of our operations and assets are located within the United States. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of South Dakota Electric, Wyoming Electric and Colorado Electric, which supply regulated electric utility services to areas in South Dakota, Wyoming, Colorado and Montana. Our Gas Utilities Segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Wyoming and Nebraska. All of our non-utility business segments support our electric utilities. Our Power Generation segment, which is conducted through Black Hills Electric Generation and its subsidiaries, engages in independent power generation activities in Wyoming and Colorado. Our Mining segment, which is conducted through WRDC, engages in coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 5 . On November 1, 2017, our Board of Directors approved a complete divestiture of our Oil and Gas segment. As of February 23, 2018, we have either closed transactions or signed contracts to sell more than 90% of our oil and gas properties. We have executed agreements to sell all our operated properties and have only non-operated assets left to divest. We plan to conclude the sale of all of our remaining assets by mid-year 2018. The Oil and Gas segment assets and liabilities have been classified as held for sale and the results of operations are shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which do not meet the criteria for income (loss) from discontinued operations. The consolidated financial statements and accompanying notes for current and prior periods have been restated. At the time the assets were classified as held for sale, depreciation, depletion and amortization expenses were no longer recorded. Unless otherwise noted, the amounts presented in the accompanying notes to the consolidated financial statements relate to the Company’s continuing operations. For more information on discontinued operations, see Note 21 .
Use of Estimates and Basis of Presentation	Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Investment in non-controlled entities over which we have the ability to exercise significant influence over operating and financial policies are accounted for using the equity method of accounting. In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for our proportionate share of earnings and losses and distributions. Under this method, a proportionate share of pretax income is recorded as Equity earnings (loss) of unconsolidated subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5 . Our Consolidated Statements of Income (Loss) include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our working interests in oil and gas properties and for our ownership interest in any jointly-owned electric utility generating facility, wind project or transmission tie. See Note 4 for additional information.
Variable Interest Entity	Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if so, if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, noncontrolling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and noncontrolling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12 .
Cash and Cash Equivalents, Restricted Cash and Equivalents	Cash and Cash Equivalents We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Restricted Cash and Equivalents We maintain cash accounts for various specified purposes. Therefore, we classify these amounts as restricted cash.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, municipal and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts net of write-offs and allowance for doubtful accounts. Accounts receivable for our Mining and Power Generation business segments consists of amounts due from sales of coal, natural gas, electric energy and capacity. We maintain an allowance for doubtful accounts which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectibility. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for doubtful accounts to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Revenue Recognition	Revenue Recognition Revenue is recognized when there is persuasive evidence of an arrangement with a fixed or determinable price and delivery has occurred or services have been rendered. Sales and franchise taxes collected from our customers are recorded on a net basis (excluded from Revenue). Utility revenues are based on authorized rates approved by the state regulatory agencies and the FERC. Revenues related to the sale, transmission and distribution of energy, and delivery of service are generally recorded when service is rendered or energy is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, our utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. For long-term non-regulated power sales agreements, revenue is recognized either in accordance with accounting standards for revenue recognition, or in accordance with accounting standards for leases, as appropriate. Under accounting standards for revenue recognition, revenue is generally recognized as the lesser of the amount billed or the average rate expected over the life of the agreement. Natural gas and crude oil sales included in discontinued operations are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectibility of the revenue is reasonably assured. BHEP records its share of revenues based on production volumes and contracted sales prices. The sales price for natural gas, crude oil, condensate and NGLs is adjusted for transportation costs and other related deductions when applicable. The transportation costs and other deductions are based on contractual or historical data and do not require significant judgment.
Materials, Supplies and Fuel	Materials and supplies represent parts and supplies for all of our business segments. Fuel - Electric Utilities represents oil, gas and coal on hand used to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas.
Property, Plant and Equipment	Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our base or “cushion gas” as property, plant and equipment. Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. The cost of regulated utility property, plant and equipment retired, or otherwise disposed of in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs associated with non-legal retirement obligations related to our regulated properties are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets, except for crude oil and natural gas properties as described below, result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. Capitalized coal mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-utility power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run.
Goodwill and Intangible Assets	Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life continue to be amortized over their estimated useful lives. We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Beginning in 2016, we changed our annual goodwill impairment testing date from November 30 to October 1 to better align the testing date with our financial planning process. We believe that the change in the date of the annual goodwill impairment test from November 30 to October 1 is not a material change in the application of an accounting principle. The new and old testing dates are close in proximity and both are in the fourth quarter of the year. We would not expect a materially different outcome as a result of testing on October 1 as compared to November 30. The change in assessment date does not have a material effect on the financial statements. We estimated the fair value of the goodwill using discounted cash flow methodology, EBITDA multiple method and an analysis of comparable transactions. This analysis required the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital and long-term earnings and merger multiples for comparable companies. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available and for which segment management regularly reviews the operating results.
Asset Retirement Obligations	Asset Retirement Obligations Accounting standards for asset retirement obligations associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income (Loss). The accounting for the obligation for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-regulated operations. For oil and gas liabilities classified as held for sale, differences in the settlement of the liability and the recorded amount are generally reflected as adjustments to the capitalized cost of oil and gas properties and prior to held-for-sale classification were depleted pursuant to the use of the full cost method of accounting.
Fair Value Measurements	Fair Value Measurements Derivative Financial Instruments Assets and liabilities are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities or listed derivatives. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable such as the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.
Derivatives and Hedging Activities	Derivatives and Hedging Activities The accounting standards for derivatives and hedging require that derivative instruments be recorded on the balance sheet as either an asset or liability measured at its fair value and changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met and designated accordingly, if they qualify for certain exemptions, including the normal purchases and normal sales exemption, or if regulatory rulings require a different accounting treatment. Changes in the fair value for derivative instruments that do not meet any of these criteria are recognized in the income statement as they occur. Each Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Revenues and expenses on contracts that qualify as derivatives may be elected under the normal purchases and normal sales exception and are recognized when the underlying physical transaction is completed under the accrual basis of accounting. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time, and price is not tied to an unrelated underlying derivative. As part of our electric and gas utility operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy in the retail and wholesale markets with the intent and ability to deliver or take delivery. If it was determined that a transaction designated as a normal purchase or normal sale no longer met the exceptions, the fair value of the related contract would be reflected as either an asset or liability, under the accounting standards for derivatives and hedging.
Derivatives, Offsetting Fair Value Amounts	We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty.
Deferred Financing Costs	Deferred Financing Costs Deferred financing costs are amortized over the estimated useful life of the related debt. Deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities.
Regulatory Accounting	Regulatory Accounting Our Electric Utilities and Gas Utilities follow accounting standards for regulated operations and reflect the effects of the numerous rate-making principles followed by the various state and federal agencies regulating the utilities. The accounting policies followed are generally subject to the Uniform System of Accounts of the FERC. These accounting policies differ in some respects from those used by our non-regulated businesses. If rate recovery becomes unlikely or uncertain due to competition or regulatory action, these accounting standards may no longer apply which could require these net regulatory assets to be charged to current income or OCI. Our regulatory assets represent amounts for which we will recover the cost, but generally are not allowed a return, except as described below. In the event we determine that our regulated net assets no longer meet the criteria for accounting standards for regulated operations, the accounting impact to us could be an extraordinary non-cash charge to operations, which could be material.
Income Taxes	Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. As a result of the SourceGas transaction, certain subsidiaries acquired file as a separate consolidated group. Where applicable, each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA makes broad and complex changes to the U.S. tax code, including, but not limited to reducing the U.S. federal corporate tax rate from 35% to 21% . The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. As such, the Company has remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. It is our policy to apply the flow-through method of accounting for investment tax credits as allowed by our rate-regulated jurisdictions. Under the flow-through method, investment tax credits are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the investment tax credit being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) benefit on the Consolidated Statements of Income (Loss). We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets.
Earnings per Share of Common Stock	Earnings per Share of Common Stock Basic earnings per share from continuing and discontinued operations is computed by dividing Net income (loss) from continuing and discontinued operations by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, and outstanding stock options, restricted stock and performance shares under our equity compensation plans.
Business Combinations	Business Combinations We record acquisitions in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date. The excess of the purchase price over the estimated fair values of the net tangible and net intangible assets acquired is recorded as goodwill. The application of ASC 805, Business Combinations requires management to make significant estimates and assumptions in the determination of the fair value of assets acquired and liabilities assumed in order to properly allocate purchase price consideration between goodwill and assets that are depreciated and amortized. Our estimates are based on historical experience, information obtained from the management of the acquired companies and, when appropriate, include assistance from independent third-party appraisal firms. These estimates are inherently uncertain and unpredictable. In addition, unanticipated events or circumstances may occur which may affect the accuracy or validity of such estimates.
Noncontrolling Interest	Noncontrolling Interest We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that noncontrolling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the noncontrolling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income.
Share-Based Compensation	Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation , by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures.
Recently Issued and Adopted Accounting Standards	Recently Issued Accounting Standards Revenue from Contracts with Customers, ASU 2014-09 In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers . The standard provides companies with a single model for use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance, including industry-specific revenue guidance. The core principle of the model is to recognize revenue when control of the goods or services transfers to the customer. The new disclosure requirements will provide information about the nature, amount, timing and uncertainty of revenue and cash flows from revenue contracts with customers. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. Entities have the option of using either a full retrospective or modified retrospective approach to adopting this guidance. Under the modified approach, an entity would recognize the cumulative effect of initially applying the guidance with an adjustment to the opening balance of retained earnings in the period of adoption. We have implemented this standard effective January 1, 2018 on a modified retrospective basis. We have completed our assessment of all revenue from existing contracts with customers and there is no significant impact to our revenue recognition practices, financial position, results of operations or cash flows. A majority of our revenues are from regulated tariff offerings that provide natural gas or electricity with a defined contractual term, generally limited to the services requested and received to date for such arrangements. For such arrangements, the performance obligation transfer of control and revenue recognition occurs when the electricity or natural gas is delivered, consistent with the previous revenue recognition guidance. The same transfer of control and revenue recognition based on delivery principles also apply to our revenue contracts for wholesale and off-system power sales arrangements, coal supply agreements, and other non-regulated services. Therefore, we did not have a cumulative adjustment to Retained earnings or an impact on our revenue recognition policies as a result of the adoption of the new standard. The new standard will require us to provide more robust disclosures than required by previous guidance, including disclosures related to disaggregation of revenue into appropriate categories, performance obligations, and the judgments made in revenue recognition determinations. Compensation - Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost, ASU 2017-07 In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost . The changes to the standard require employers to report the service cost component in the same line item(s) as other compensation costs, and require the other components of net periodic pension and post-retirement benefit costs to be separately presented in the income statement outside of income from operations. Additionally, only the service cost component may be eligible for capitalization, when applicable. However, all cost components remain eligible for capitalization under FERC regulations. This ASU will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension and post-retirement benefit costs in the income statement. The capitalization of only the service cost component of net periodic pension and post-retirement benefit costs in assets will be applied on a prospective basis. This new guidance is effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. We have implemented this standard effective January 1, 2018. For our rate-regulated entities, we will 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 will result in offsetting changes to Operating income and Other income, which are not expected to be material. Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments, ASU 2016-15 In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). This ASU requires changes in the presentation of certain items, including but not limited to, debt prepayment or debt extinguishment costs; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies and distributions received from equity method investees. The ASU will be effective for fiscal years beginning after December 15, 2017. We have implemented this standard effective January 1, 2018 using the retrospective transition method. This standard will not have a material impact on our financial position, results of operations or cash flows. Leases, ASU 2016-02 In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which supersedes ASC 840, Leases . This ASU requires lessees to recognize a right-of-use asset and lease liability on the balance sheet for 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 the transition approach to not assess existing or expired land easements that were not previously accounted for as a lease. We continue to evaluate the impact of this new standard on our financial position, results of operations and cash flows as well as monitor emerging guidance on such topics as easements and rights of way, pipeline laterals, purchase power agreements, secondary use assets, and other industry-related areas. We continue the process of identifying and categorizing our lease contracts and evaluating our current business processes and systems. Derivatives and Hedging: Targeted Improvement to Accounting for Hedging Activities, 2017-12 In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvement to Accounting for Hedging Activities. This standard better aligns risk management activities and financial reporting for hedging relationships, simplifies hedge accounting requirements and improves disclosures of hedging arrangements. This ASU is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows. Simplifying the Test for Goodwill Impairment, 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment by eliminating step 2 from the goodwill impairment test. Under the new guidance, if the carrying amount of a reporting unit exceeds its fair value, an impairment loss will be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit. The new standard is effective for interim and annual reporting periods beginning after December 15, 2019, applied on a prospective basis with early adoption permitted. We do not anticipate the adoption of this guidance to have any impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, ASU 2018-02 In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This ASU was issued to address industry concerns regarding the application of current accounting guidance to certain provisions of the new tax reform legislation. This ASU permits entities to make a one-time reclassification from AOCI to retained earnings for stranded tax effects resulting from the newly enacted corporate tax rate. The amount of the reclassification is calculated on the basis of the difference between the historical and newly enacted tax rates for deferred tax liabilities and assets related to items within AOCI. The ASU is effective for fiscal years beginning after December 15, 2018, including interim periods therein, and early adoption is permitted. We have implemented this ASU effective December 22, 2017, the enactment date of the TCJA, which resulted in a reclassification of $7.0 million of stranded tax effects from AOCI to retained earnings. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows. Improvements to Employee Share-Based Payment Accounting, ASU 2016-09 In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting . This ASU simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for forfeitures, income taxes, and statutory tax withholding requirements. The ASU was effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early adoption permitted. Certain amendments of this guidance are to be applied retrospectively and others prospectively. We implemented this ASU effective January 1, 2017, recording a cumulative-effect adjustment of $3.2 million to Retained earnings in the Consolidated Balance Sheets as of the date of adoption, representing previously recorded forfeitures and excess tax benefits generated in years prior to 2017 that were previously not recognized in stockholders’ equity due to NOLs in those years. Adoption of this ASU did not have a material impact on our consolidated financial position, results of operations or cash flows.

Business Description (Tables)

Business Description (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accounts Receivable and Allowance for Doubtful Accounts	Following is a summary of accounts receivable as of December 31 (in thousands): 2017 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 39,347 $ 36,384 $ (586 ) $ 75,145 Gas Utilities 81,256 88,967 (2,495 ) 167,728 Power Generation 1,196 — — 1,196 Mining 2,804 — — 2,804 Corporate 1,457 — — 1,457 Total $ 126,060 $ 125,351 $ (3,081 ) $ 248,330 2016 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 41,730 $ 36,463 $ (353 ) $ 77,840 Gas Utilities 88,168 88,329 (2,026 ) 174,471 Power Generation 1,420 — — 1,420 Mining 3,352 — — 3,352 Corporate 2,228 — — 2,228 Total $ 136,898 $ 124,792 $ (2,379 ) $ 259,311
Materials, Supplies and Fuel	The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2017 2016 Materials and supplies $ 69,732 $ 64,852 Fuel - Electric Utilities 2,962 3,667 Natural gas in storage 40,589 35,087 Total materials, supplies and fuel $ 113,283 $ 103,606
Schedule of Accrued Liabilities	The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): 2017 2016 Accrued employee compensation, benefits and withholdings $ 52,467 $ 54,553 Accrued property taxes 42,029 37,379 Customer deposits and prepayments 44,420 55,191 Accrued interest 33,822 33,982 CIAC current portion 1,552 1,575 Other (none of which is individually significant) 45,172 52,868 Total accrued liabilities $ 219,462 $ 235,548
Goodwill	Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Ending balance at December 31, 2015 $ 248,479 $ 102,515 $ 8,765 $ 359,759 Additions (a) — 939,695 — 939,695 Ending balance at December 31, 2016 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 Additions — — — — Ending balance at December 31, 2017 $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 _________________ (a) Represents goodwill recorded with the acquisition of SourceGas. See Note 2 for more information.
Intangible Assets	Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2017 2016 2015 Intangible assets, net, beginning balance $ 8,392 $ 3,380 $ 3,176 Additions — 5,522 434 Amortization expense (a) (833 ) (510 ) (230 ) Intangible assets, net, ending balance $ 7,559 $ 8,392 $ 3,380 _________________ (a) Amortization expense for existing intangible assets is expected to be $0.8 million for each year of the next five years.
Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities as of December 31 (in thousands): Maximum Amortization (in years) 2017 2016 Regulatory assets Deferred energy and fuel cost adjustments - current (a) 1 $ 20,187 $ 17,491 Deferred gas cost adjustments (a) 1 31,844 15,329 Gas price derivatives (a) 3 11,935 8,843 Deferred taxes on AFUDC (b) 45 7,847 15,227 Employee benefit plans (c) 12 109,235 108,556 Environmental (a) subject to approval 1,031 1,108 Asset retirement obligations (a) 44 517 505 Loss on reacquired debt (a) 30 20,667 22,266 Renewable energy standard adjustment (a) 5 1,088 1,605 Deferred taxes on flow through accounting (c) 54 26,978 37,498 Decommissioning costs 10 13,287 16,859 Gas supply contract termination (a) 4 20,001 26,666 Other regulatory assets (a) 30 32,837 24,189 $ 297,454 $ 296,142 Regulatory liabilities Deferred energy and gas costs (a) 1 $ 3,427 $ 10,368 Employee benefit plan costs and related deferred taxes (c) 12 40,629 68,654 Cost of removal (a) 44 130,932 118,410 Excess deferred income taxes (c) (d) 40 301,553 62 Revenue subject to refund 1 1,488 2,485 Other regulatory liabilities (c) 25 7,097 6,777 $ 485,126 $ 206,756 __________ (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) The increase in the regulatory tax liability is primarily related to the revaluation of deferred income tax balances at the lower income tax rate. As of December 31, 2017, all of the liability has been classified as non-current due to uncertainties around the timing and other regulatory decisions that will affect the amount of regulatory tax liability amortized and returned to customers through rate reductions or other revenue offsets in 2018.
Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute earnings (loss) per share is as follows for the years ended December 31 (in thousands): 2017 2016 2015 Net income (loss) available for common stock $ 177,034 $ 72,970 $ (32,111 ) Weighted average shares - basic 53,221 51,922 45,288 Dilutive effect of: Equity Units 1,783 1,222 — Equity compensation 116 127 — Weighted average shares - diluted 55,120 53,271 45,288 Net income (loss) available for common stock, per share - Diluted $ 3.21 $ 1.37 $ (0.71 )
Antidilutive Securities	The following outstanding securities were not included in the computation of diluted earnings per share as their effect would have been anti-dilutive for the years ended December 31 (in thousands): 2017 2016 2015 Equity compensation 11 3 112 Equity units — — 6,440 Anti-dilutive shares excluded from computation of earnings (loss) per share 11 3 6,552

Acquisition (Tables)

Acquisition (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Final Purchase Price Allocation of Fair Value of Assets Acquired and Liabilities Assumed	(in thousands) Purchase Price $ 1,894,882 Less: Long-term debt assumed (760,000 ) Less: Working capital adjustment received (10,644 ) Consideration paid, net of working capital adjustment received $ 1,124,238 Allocation of Purchase Price: Current Assets $ 112,983 Property, plant & equipment, net 1,058,093 Goodwill 939,695 Deferred charges and other assets, excluding goodwill 133,299 Current liabilities (172,454 ) Long-term debt (758,874 ) Deferred credits and other liabilities (188,504 ) Total consideration paid, net of working-capital adjustment received $ 1,124,238
Schedule of Pro Forma Results	The following pro forma results give effect to the acquisition, assuming the transaction closed on January 1, 2015: Pro Forma Results December 31, 2016 2015 (in thousands, except per share amounts) Revenue $ 1,617,878 $ 1,720,618 Income from continuing operations $ 177,040 $ 160,290 Net income (loss) $ 112,878 $ (13,369 ) Earnings from continuing operations per share, Basic $ 3.41 $ 3.15 Earnings from continuing operations per share, Diluted $ 3.32 $ 3.15

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2017 2016 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,315,044 39 $ 1,303,101 41 30 55 Electric transmission 407,203 51 354,801 52 40 70 Electric distribution 755,213 48 712,575 48 15 75 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 232,842 31 164,761 25 3 65 Capital lease - plant in service (b) 261,441 20 261,441 20 20 20 Total electric plant in service 2,976,613 2,801,549 Construction work in progress 13,595 74,045 Total electric plant 2,990,208 2,875,594 Less accumulated depreciation and amortization 644,022 578,162 Electric plant net of accumulated depreciation and amortization $ 2,346,186 $ 2,297,432 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 13 years remaining. (b) Capital lease - plant in service represents the assets accounted for as a capital lease under the PPA between Colorado Electric and Black Hills Colorado IPP. The capital lease ends in conjunction with the expiration of the PPA on December 31, 2031. 2017 2016 Lives (in years) Gas Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Gas plant: Production $ 10,495 35 $ 10,821 35 17 71 Gas transmission 366,433 48 338,729 48 22 70 Gas distribution 1,413,431 42 1,303,366 42 33 47 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciated (a) 47,466 0 47,055 0 0 0 Storage 28,520 31 27,686 31 15 48 General 336,869 19 339,382 19 3 44 Total gas plant in service 2,206,753 2,070,578 Construction work in progress 44,440 28,446 Total gas plant 2,251,193 2,099,024 Less accumulated depreciation and amortization 229,170 194,585 Gas plant net of accumulated depreciation and amortization $ 2,022,023 $ 1,904,439 _____________ (a) Cushion gas is the portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Depreciation of cushion gas is determined by the respective regulatory jurisdiction in which the cushion gas resides. 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 155,569 $ 224 $ 155,793 $ 57,813 $ 97,980 33 2 40 Mining 158,370 — 158,370 108,844 49,526 14 2 59 2016 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 161,430 $ 1,298 $ 162,728 $ 55,157 $ 107,571 33 2 40 Mining 151,709 4,642 156,351 105,219 51,132 13 2 59 2017 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,580 $ 6,374 $ 11,954 $ 309 $ 14,070 $ 25,715 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $14 million . 2016 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation, Depletion and Amortization Add Accumulated Depreciation - Capital Lease Elimination (a) Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 9,625 $ 11,974 $ 21,599 $ 2,106 $ 6,110 $ 25,603 8 3 30 ___________ (a) Reflects the elimination of the capital lease accumulated depreciation difference between Colorado Electric and Black Hills Colorado IPP of $6.1 million .

Jointly Owned Facilities (Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Jointly Owned Utility Plants	At December 31, 2017 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Accumulated Depreciation Wyodak Plant $ 114,405 $ 727 $ 58,955 Transmission Tie $ 20,037 $ 242 $ 6,215 Wygen I $ 109,552 $ 209 $ 40,465 Wygen III $ 138,688 $ 406 $ 19,239 Busch Ranch Wind Farm $ 18,899 $ — $ 3,858

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting Information, Additional Information [Abstract]
Segment information included in Consolidated Balance Sheets	Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2017 2016 Electric (a) $ 2,906,275 $ 2,859,559 Gas 3,426,466 3,307,967 Power Generation (a) 60,852 73,445 Mining 65,455 67,347 Corporate and Other 115,612 112,760 Discontinued operations (b) 84,242 120,695 Total assets $ 6,658,902 $ 6,541,773 __________________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease. (b) On November 1, 2017, the BHC Board of Directors approved a complete divestiture of our Oil and Gas segment. See Note 21 for additional information. Capital Expenditures and Asset Acquisitions (a) for the years ended December 31, 2017 2016 Capital expenditures Electric Utilities $ 138,060 $ 258,739 Gas Utilities 184,389 173,930 Power Generation 1,864 4,719 Mining 6,708 5,709 Corporate and Other 6,668 17,353 Total capital expenditures 337,689 460,450 Asset acquisitions Gas Utilities (b) — 1,124,238 Total capital expenditures and asset acquisitions of continuing operations 337,689 1,584,688 Total capital expenditures of discontinued operations 23,222 6,669 Total capital expenditures and asset acquisitions $ 360,911 $ 1,591,357 _________________ (a) Includes accruals for property, plant and equipment. (b) SourceGas was acquired on February 12, 2016. Net cash paid of $1.124 billion was net of long-term debt assumed and working capital adjustments received. See Note 2 . Property, Plant and Equipment as of December 31, 2017 2016 Electric Utilities (a) $ 2,990,208 $ 2,875,594 Gas Utilities 2,251,193 2,099,024 Power Generation (a) 155,793 162,728 Mining 158,370 156,351 Corporate and Other 11,954 21,599 Total property, plant and equipment $ 5,567,518 $ 5,315,296 _______________ (a) The PPA under which Black Hills Colorado IPP provides generation to support Colorado Electric customers from the Pueblo Airport Generation station is accounted for as a capital lease. As such, assets owned by our Power Generation segment are recorded at Colorado Electric under accounting for a capital lease.
Segment information included in Consolidated Statements of Income	Consolidating Income Statement Year ended December 31, 2017 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 689,945 $ 947,595 $ 7,263 $ 35,463 $ — $ — $ — $ 1,680,266 Intercompany revenue 14,705 35 84,283 31,158 344,685 (474,866 ) — — Total revenue 704,650 947,630 91,546 66,621 344,685 (474,866 ) — 1,680,266 Fuel, purchased power and cost of natural gas sold 268,405 409,603 — — 151 (114,871 ) — 563,288 Operations and maintenance 172,307 269,190 32,382 44,882 296,067 (302,832 ) — 511,996 Depreciation, depletion and amortization 93,315 83,732 5,993 8,239 21,031 (24,064 ) — 188,246 Operating income (loss) 170,623 185,105 53,171 13,500 27,436 (33,099 ) — 416,736 Interest expense (55,229 ) (80,829 ) (3,959 ) (228 ) (152,416 ) 154,543 — (138,118 ) Interest income 2,955 2,254 1,123 23 115,382 (120,721 ) — 1,016 Other income (expense), net 1,730 (829 ) (54 ) 2,191 330,373 (331,303 ) — 2,108 Income tax benefit (expense) (a) (9,997 ) (39,799 ) 10,333 (1,100 ) (32,433 ) (371 ) — (73,367 ) Income (loss) from continuing operations 110,082 65,902 60,614 14,386 288,342 (330,951 ) — 208,375 Income (loss) from discontinued operations, net of tax (b) — — — — — — (17,099 ) (17,099 ) Net income (loss) 110,082 65,902 60,614 14,386 288,342 (330,951 ) (17,099 ) 191,276 Net income attributable to noncontrolling interest — (107 ) (14,135 ) — — — — (14,242 ) Net income (loss) available for common stock $ 110,082 $ 65,795 $ 46,479 $ 14,386 $ 288,342 $ (330,951 ) $ (17,099 ) $ 177,034 ________________ (a) The effective tax rate is lower in 2017 resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. (b) Discontinued operations includes oil and gas property impairments (see Note 21 ). Consolidating Income Statement Year ended December 31, 2016 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 664,330 $ 838,343 $ 7,176 $ 29,067 $ — $ — $ — $ 1,538,916 Intercompany revenue 12,951 — 83,955 31,213 347,500 (475,619 ) — — Total revenue 677,281 838,343 91,131 60,280 347,500 (475,619 ) — 1,538,916 Fuel, purchased power and cost of natural gas sold 261,349 352,165 — — 456 (114,838 ) — 499,132 Operations and maintenance 158,134 245,826 32,636 39,576 378,744 (326,846 ) — 528,070 Depreciation, depletion and amortization 84,645 78,335 4,104 9,346 22,930 (23,827 ) — 175,533 Operating income (loss) 173,153 162,017 54,391 11,358 (54,630 ) (10,108 ) — 336,181 Interest expense (56,237 ) (76,586 ) (3,758 ) (401 ) (114,597 ) 115,469 — (136,110 ) Interest income 5,946 1,573 1,983 24 97,147 (105,244 ) — 1,429 Other income (expense), net 3,193 184 2 2,209 179,838 (181,032 ) — 4,394 Income tax benefit (expense) (40,228 ) (27,462 ) (17,129 ) (3,137 ) 28,398 457 — (59,101 ) Income (loss) from continuing operations 85,827 59,726 35,489 10,053 136,156 (180,458 ) — 146,793 (Loss) from discontinued operations, net of tax (a) — — — — — — (64,162 ) (64,162 ) Net income (loss) 85,827 59,726 35,489 10,053 136,156 (180,458 ) (64,162 ) 82,631 Net income attributable to noncontrolling interest — (102 ) (9,559 ) — — — — (9,661 ) Net income (loss) available for common stock $ 85,827 $ 59,624 $ 25,930 $ 10,053 $ 136,156 $ (180,458 ) $ (64,162 ) $ 72,970 ________________ (a) Discontinued operations includes oil and gas property impairments (see Note 21 ). Consolidating Income Statement Year ended December 31, 2015 Electric Utilities Gas Utilities Power Generation Mining Corporate Intercompany Eliminations Discontinued Operations Total Revenue $ 668,226 $ 551,300 $ 7,483 $ 34,313 $ — $ — $ — $ 1,261,322 Intercompany revenue 11,617 — 83,307 30,753 227,708 (353,385 ) — — Total revenue 679,843 551,300 90,790 65,066 227,708 (353,385 ) — 1,261,322 Fuel, purchased power and cost of natural gas sold 269,409 299,645 — — 122 (112,289 ) — 456,887 Operations and maintenance 160,924 140,723 32,140 41,630 231,855 (229,790 ) — 377,482 Depreciation, depletion and amortization 80,929 32,326 4,329 9,806 9,723 (10,580 ) — 126,533 Operating income (loss) 168,581 78,606 54,321 13,630 (13,992 ) (726 ) — 300,420 Interest expense (55,159 ) (17,912 ) (4,218 ) (433 ) (61,496 ) 54,568 — (84,650 ) Interest income 4,114 601 1,015 34 48,799 (52,942 ) — 1,621 Other income (expense), net 1,216 315 71 2,247 70,929 (71,964 ) — 2,814 Income tax benefit (expense) (41,173 ) (22,304 ) (18,539 ) (3,608 ) 6,606 361 — (78,657 ) Income (loss) from continuing operations 77,579 39,306 32,650 11,870 50,846 (70,703 ) — 141,548 Income (loss) from discontinued operations, net of tax (a) — — — — — — (173,659 ) (173,659 ) Net income (loss) 77,579 39,306 32,650 11,870 50,846 (70,703 ) (173,659 ) (32,111 ) Net income attributable to noncontrolling interest — — — — — — — — Net income (loss) available for common stock $ 77,579 $ 39,306 $ 32,650 $ 11,870 $ 50,846 $ (70,703 ) $ (173,659 ) $ (32,111 ) ________________ (a) Discontinued operations includes oil and gas property impairments (see Note 21 ).
Disposal Groups, Including Discontinued Operations	The reallocation of these costs to our operating segments in 2017 and an estimate of how these costs could have been allocated to segments other than Corporate and Other in 2016 and 2015 is as follows (in thousands): Year Ended Business Segment December 31, 2017 December 31, 2016 December 31, 2015 Electric Utilities $ 1,323 $ 2,079 $ 3,344 Gas Utilities 1,571 2,292 1,815 Power Generation 177 320 543 Mining 101 196 321 Total reportable segments 3,172 4,887 6,023 Corporate and Other (a) 6,405 6,037 3,957 Total $ 9,577 $ 10,924 $ 9,980 ________________________ (a) Includes interest allocations in 2017, 2016 and 2015 of approximately $4.9 million , $5.6 million and $3.4 million , respectively.

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments	Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2017 December 31, 2017 December 31, 2016 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2020 July 15, 2020 5.88% 200,000 200,000 Remarketable junior subordinated notes (b) November 1, 2028 3.50% 299,000 299,000 Senior unsecured notes due 2019 January 11, 2019 2.50% 250,000 250,000 Senior unsecured notes due 2026 January 15, 2026 3.95% 300,000 300,000 Senior unsecured notes due 2027 January 15, 2027 3.15% 400,000 400,000 Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Corporate term loan due 2019 (a) August 9, 2019 2.55% 300,000 400,000 Corporate term loan due 2021 June 7, 2021 2.32% 18,664 24,406 Total Corporate debt 2,592,664 2,698,406 Less unamortized debt discount (3,808 ) (4,413 ) Total Corporate debt, net 2,588,856 2,693,993 Electric Utilities First Mortgage Bonds due 2044 October 20, 2044 4.43% 85,000 85,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 First Mortgage Bonds due 2032 August 15, 2032 7.23% 75,000 75,000 First Mortgage Bonds due 2039 November 1, 2039 6.13% 180,000 180,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 Industrial development revenue bonds due 2021 (c) September 1, 2021 1.78% 7,000 7,000 Industrial development revenue bonds due 2027 (c) March 1, 2027 1.78% 10,000 10,000 Series 94A Debt, variable rate (c) June 1, 2024 1.83% 2,855 2,855 Total Electric Utilities debt 544,855 544,855 Less unamortized debt discount (90 ) (94 ) Total Electric Utilities debt, net 544,765 544,761 Total long-term debt 3,133,621 3,238,754 Less current maturities 5,743 5,743 Less deferred financing costs (d) 18,478 21,822 Long-term debt, net of current maturities and deferred financing costs $ 3,109,400 $ 3,211,189 _______________ (a) Variable interest rate, based on LIBOR plus a spread. (b) See Note 12 for RSN details. (c) Variable interest rate. (d) Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2017 and December 31, 2016 , respectively.
Schedule of Maturities of Long-term Debt	Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2018 $ 5,743 2019 $ 555,742 2020 $ 205,743 2021 $ 8,436 2022 $ — Thereafter $ 2,361,855
Deferred Financing Costs	Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income (Loss) were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2017 2017 2016 2015 Revolving Credit Facility $ 1,703 $ 638 $ 537 $ 504 Senior unsecured notes due 2023 2,427 494 494 494 Senior unsecured notes due 2019 59 704 643 — Senior unsecured notes due 2020 425 167 167 167 Senior unsecured notes due 2026 2,031 287 262 — Senior unsecured notes due 2027 2,918 363 121 — Senior unsecured notes due 2046 3,082 111 37 — Corporate term loan due 2019 86 201 144 — Bridge Term Loan — — 843 4,213 RSNs due 2028 1,326 122 122 10 First mortgage bonds due 2044 (South Dakota Electric) 639 24 24 24 First mortgage bonds due 2044 (Wyoming Electric) 591 22 23 22 First mortgage bonds due 2032 485 33 33 33 First mortgage bonds due 2039 1,657 76 76 76 First mortgage bonds due 2037 613 31 31 31 Other 436 76 304 43 Total $ 18,478 $ 3,349 $ 3,861 $ 5,617

Notes Payable (Tables)

Notes Payable (Tables)	12 Months Ended
	Dec. 31, 2017
Notes Payable [Abstract]
Schedule of Short-term Debt	We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands): Balance Outstanding at December 31, 2017 December 31, 2016 Revolving Credit Facility $ — $ 96,600 CP Program 211,300 — Total $ 211,300 $ 96,600
Schedule of Credit Facility Covenants	Our Revolving Credit Facility and our Term Loans require compliance with the following financial covenant at the end of each quarter: At December 31, 2017 Covenant Requirement at December 31, 2017 Consolidated Indebtedness to Capitalization Ratio 61 % Less than 65 %

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation	The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): December 31, 2016 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired Revisions to Prior Estimates (b) December 31, 2017 Electric Utilities $ 4,661 $ — $ (4 ) $ 268 $ — $ 1,362 $ 6,287 Gas Utilities 29,775 — — 1,142 — 2,321 33,238 Mining 12,440 — (107 ) 651 — (485 ) 12,499 Total $ 46,876 $ — $ (111 ) $ 2,061 $ — $ 3,198 $ 52,024 December 31, 2015 Liabilities Incurred Liabilities Settled Accretion Liabilities Acquired (a) Revisions to Prior Estimates (b)(c) December 31, 2016 Electric Utilities $ 4,462 $ — $ — $ 191 $ — $ 8 $ 4,661 Gas Utilities 136 — — 791 22,412 6,436 29,775 Mining 18,633 — (105 ) 822 — (6,910 ) 12,440 Total $ 23,231 $ — $ (105 ) $ 1,804 $ 22,412 $ (466 ) $ 46,876 _____________________ (a) Represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. Approximately $22 million was recorded with the purchase price allocation of SourceGas. (b) The Gas Utilities Revision to Prior Estimates represents our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The 2016 Mining Revision to Prior Estimates reflects an approximately 33% reduction in equipment costs as promulgated by the State of Wyoming.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Contract or notional amounts and terms of marketing activities and derivative commodity instruments	The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our Utilities are comprised of both short and long positions. We had the following net long positions as of: December 31, 2017 December 31, 2016 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 8,330,000 36 14,770,000 48 Natural gas options purchased, net (b) 3,540,000 14 3,020,000 5 Natural gas basis swaps purchased 8,060,000 36 12,250,000 48 Natural gas over-the-counter swaps, net (c) 3,820,000 29 4,622,302 28 Natural gas physical commitments, net (d) 12,826,605 35 21,504,378 10 __________ (a) Term reflects the maximum forward period hedged. (b) Volumes purchased as of December 31, 2016 is net of 2,133,000 MMBtus of collar options (call purchase and put sale) transactions. (c) As of December 31, 2017 , 1,650,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (d) Volumes exclude contracts that qualify for normal purchase, normal sales exception. Based on December 31, 2017 prices, a $0.7 million loss would be realized, reported in pre-tax earnings and reclassified from AOCI during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.
Schedule of Derivative Instruments	The contract or notional amounts, terms of our interest rate swaps and the interest rate swaps balances reflected on the Consolidated Balance Sheets were as follows (dollars in thousands) as of: December 31, 2016 Interest Rate Swaps (a) Notional $ 50,000 Weighted average fixed interest rate 4.94 % Maximum terms in months 1 Derivative assets, non-current $ — Derivative liabilities, current $ 90 Derivative liabilities, non-current $ — ___________________ (a) The $50 million in swaps expired in January 2017. These swaps were designated to borrowings on our Revolving Credit Facility and were priced using three-month LIBOR, matching the floating portion of the related borrowings.
Derivative Instruments, Gain (Loss)	The impact of cash flow hedges on our Consolidated Statements of Income (Loss) is presented below for the years ended December 31, 2017 , 2016 and 2015 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. December 31, 2017 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (2,941 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 913 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (243 ) Fuel, purchased power and cost of natural gas sold (75 ) Total impact from cash flow hedges $ (2,271 ) $ (75 ) December 31, 2016 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (3,899 ) Interest expense $ (953 ) Commodity derivatives Net (loss) from discontinued operations 11,019 Net (loss) from discontinued operations — Commodity derivatives Fuel, purchased power and cost of natural gas sold (14 ) Fuel, purchased power and cost of natural gas sold — Total $ 7,106 $ (953 ) December 31, 2015 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income (Settlements) Location of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Amount of Gain/(Loss) Recognized in Income on Derivative (Ineffective Portion) Interest rate swaps Interest expense $ (3,647 ) Interest expense $ — Commodity derivatives Net (loss) from discontinued operations 14,460 Net (loss) from discontinued operations — Total $ 10,813 $ — The following table summarizes the gains and losses arising from hedging transactions that were recognized as a component of other comprehensive income (loss) for the years ended December 31, 2017 , 2016 and 2015 . The amounts included in the table below exclude gains and losses arising from ineffectiveness because these amounts are immediately recognized in the Consolidated Statements of Net Income (Loss) as incurred. December 31, 2017 December 31, 2016 December 31, 2015 (In thousands) Increase (decrease) in fair value: Interest rate swaps $ — $ (31,222 ) $ 2,888 Forward commodity contracts 366 (573 ) 9,782 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,941 3,899 3,647 Forward commodity contracts (670 ) (11,005 ) (14,460 ) Total other comprehensive income (loss) from hedging $ 2,637 $ (38,901 ) $ 1,857 Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income (Loss) for the years ended December 31, 2017 , 2016 and 2015 (in thousands). Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. 2017 2016 2015 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income Commodity derivatives Net (loss) from discontinued operations $ — $ (50 ) $ — Commodity derivatives Fuel, purchased power and cost of natural gas sold (2,207 ) 940 — $ (2,207 ) $ 890 $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments (in thousands): As of December 31, 2017 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 1,586 $ — $ (1,282 ) $ 304 Total $ — $ 1,586 $ — $ (1,282 ) $ 304 Liabilities: Commodity derivatives - Utilities $ — $ 13,756 $ — $ (11,497 ) $ 2,259 Total $ — $ 13,756 $ — $ (11,497 ) $ 2,259 As of December 31, 2016 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 7,469 $ — $ (3,262 ) $ 4,207 Total — 7,469 — (3,262 ) 4,207 Liabilities: Commodity derivatives - Utilities $ — $ 12,201 $ — $ (11,144 ) $ 1,057 Interest rate swaps — 90 — — 90 Total $ — $ 12,291 $ — $ (11,144 ) $ 1,147
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands): 2017 2016 Balance Sheet Location Fair Value of Asset Derivatives Fair Value of Liability Derivatives Fair Value of Asset Derivatives Fair Value of Liability Derivatives Derivatives designated as hedges: Commodity derivatives Derivative assets - current $ — $ — $ 1,007 $ — Commodity derivatives Derivative assets - non-current — — 124 — Commodity derivatives Current assets held for sale — — 154 — Commodity derivatives Derivative liabilities - current — 817 — — Commodity derivatives Other deferred credits and other liabilities — 67 — 7 Commodity derivatives Current liabilities held for sale — — — 1,090 Commodity derivatives Noncurrent liabilities held for sale — — — 231 Interest rate swaps Derivative liabilities - current — — — 90 Total derivatives designated as hedges $ — $ 884 $ 1,285 $ 1,418 Derivatives not designated as hedges: Commodity derivatives Derivative assets - current $ 304 $ — $ 2,977 $ — Commodity derivatives Derivative assets - non-current — — 98 — Commodity derivatives Derivative liabilities - current — 1,264 — 1,014 Commodity derivatives Other deferred credits and other liabilities — 111 — 36 Commodity derivatives Current liabilities held for sale — — — 265 Total derivatives not designated as hedges $ 304 $ 1,375 $ 3,075 $ 1,315
Schedule of Derivative Offsetting on Balance Sheet	Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2017 was as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Subject to master netting agreement or similar arrangement: Commodity derivative: Utilities $ 1,282 $ (1,282 ) $ — Total derivative assets subject to a master netting agreement or similar arrangement 1,282 (1,282 ) — Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 304 — 304 Total derivative assets not subject to a master netting agreement or similar arrangement 304 — 304 Total derivative assets $ 1,586 $ (1,282 ) $ 304 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities $ 11,497 $ (11,497 ) $ — Total derivative liabilities subject to a master netting agreement or similar arrangement 11,497 (11,497 ) — Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 2,259 — 2,259 Total derivative liabilities not subject to a master netting agreement or similar arrangement 2,259 — 2,259 Total derivative liabilities $ 13,756 $ (11,497 ) $ 2,259 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2016 were as follows (in thousands): Derivative Assets Gross Amounts of Derivative Assets Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Assets on Consolidated Balance Sheets Subject to master netting agreement or similar arrangement: Commodity derivative: Utilities $ 4,269 $ (3,262 ) $ 1,007 Total derivative assets subject to a master netting agreement or similar arrangement 4,269 (3,262 ) 1,007 Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 3,200 — 3,200 Total derivative assets not subject to a master netting agreement or similar arrangement 3,200 — 3,200 Total derivative assets $ 7,469 $ (3,262 ) $ 4,207 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities $ 11,144 $ (11,144 ) $ — Total derivative liabilities subject to a master netting agreement or similar arrangement 11,144 (11,144 ) — Not subject to a master netting agreement or similar arrangement: Commodity derivative: Utilities 1,057 — 1,057 Interest Rate Swaps 90 — 90 Total derivative liabilities not subject to a master netting agreement or similar arrangement 1,147 — 1,147 Total derivative liabilities $ 12,291 $ (11,144 ) $ 1,147

Fair Value of Financial Instr44

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair value of financial instruments	The estimated fair values of our financial instruments, excluding derivatives which are presented in Note 10 , were as follows at December 31 (in thousands): 2017 2016 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 15,420 $ 15,420 $ 13,518 $ 13,518 Restricted cash and equivalents (a) $ 2,820 $ 2,820 $ 2,274 $ 2,274 Notes payable (b) $ 211,300 $ 211,300 $ 96,600 $ 96,600 Long-term debt, including current maturities (c) (d) $ 3,115,143 $ 3,350,544 $ 3,216,932 $ 3,351,305 _______________ (a) Carrying value approximates fair value. Cash and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings in 2017 and borrowings on our Revolving Credit Facility in 2016. Carrying value approximates fair value due to the short-term length of maturity; since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. (c) 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. (d) Carrying amount of long-term debt is net of deferred financing costs.

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Schedule of Company's equity units	Selected information about our equity units is presented below (in thousands except for percentages): Issuance Date Units Issued Total Net Proceeds Total Long-term Debt (RSNs) RSN Interest Rate (annual) Stock Purchase Contract Rate (annual) Stock Purchase Contract Liability as of December 31, 2017 11/23/2015 5,980 $ 290,030 $ 299,000 3.50 % 4.25 % $ 12,115
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income (Loss) was as follows for the years ended December 31 (in thousands): 2017 2016 2015 Stock-based compensation expense $ 7,626 $ 10,885 $ 4,076
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Compensation, Employee Stock Purchase Plan, Activity	A summary of the DRSPP for the years ended December 31 is as follows (shares in thousands): 2017 2016 Shares Issued 48 51 Weighted Average Price $ 65.40 $ 58.24 Unissued Shares Available 308 356
Schedule of Variable Interest Entities	We have recorded the following assets and liabilities on our consolidated balance sheets related to the VIE described above as of December 31: 2017 2016 (in thousands) Assets Current assets $ 14,837 $ 12,627 Property, plant and equipment of variable interest entities, net $ 208,595 $ 218,798 Liabilities Current liabilities $ 4,565 $ 4,342
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	A summary of the status of the restricted stock and restricted stock units at December 31, 2017 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 295 $ 52.15 Granted 111 60.63 Vested (128 ) 51.44 Forfeited (11 ) 53.80 Balance at end of period 267 $ 55.94 The weighted-average grant-date fair value of restricted stock granted and the total fair value of shares vested during the years ended December 31, was as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2017 $ 60.63 $ 7,909 2016 $ 53.55 $ 4,602 2015 $ 50.01 $ 6,009
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	Outstanding performance periods at December 31 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2015 January 1, 2015 - December 31, 2017 43 0% 200% January 1, 2016 January 1, 2016 - December 31, 2018 53 0% 200% January 1, 2017 January 1, 2017 - December 31, 2019 51 0% 200% A summary of the status of the Performance Share Plan at December 31 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2017 (in thousands) (in thousands) Performance Shares balance at beginning of period 71 $ 52.29 71 Granted 26 63.52 26 Forfeited (1 ) 55.01 (1 ) Vested (22 ) 55.18 (22 ) Performance Shares balance at end of period 74 $ 55.31 74 $ 22.31 _____________________ (a) The grant date fair values for the performance shares granted in 2017 , 2016 and 2015 were determined by Monte Carlo simulation using a blended volatility of 23% , 24% and 21% , respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2017 $ 63.52 December 31, 2016 $ 47.76 December 31, 2015 $ 54.92 Performance plan payouts have been as follows (dollars and shares in thousands): Performance Period Year of Payment Shares Issued Cash Paid Total Intrinsic Value January 1, 2014 to December 31, 2016 2017 — $ — $ — January 1, 2013 to December 31, 2015 2016 — $ — $ — January 1, 2012 to December 31, 2014 2015 69 $ 3,657 $ 7,314

Operating Leases (Tables)

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2017
Leases, Operating [Abstract]
Operating Leases of Lessor Disclosure	Rental expense incurred under these operating leases, including month to month leases, for the years ended December 31 was as follows (in thousands): 2017 2016 2015 Rent expense $ 10,325 $ 9,568 $ 7,177
Schedule of Future Minimum Rental Payments for Operating Leases	The following is a schedule of future minimum payments required under the operating lease agreements (in thousands): 2018 $ 5,030 2019 $ 3,840 2020 $ 1,957 2021 $ 918 2022 $ 808 Thereafter $ 3,085

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2017 2016 2015 Current: Federal $ (6,193 ) $ (21,806 ) $ 2,624 State (1,432 ) (1,797 ) 1,329 (7,625 ) (23,603 ) 3,953 Deferred: Federal 76,567 78,997 71,332 State 4,470 3,759 3,485 Tax credit amortization (45 ) (52 ) (113 ) 80,992 82,704 74,704 $ 73,367 $ 59,101 $ 78,657
Schedule of Deferred Tax Assets and Liabilities	The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2017 2016 Deferred tax assets: Regulatory liabilities $ 90,742 $ 58,200 Employee benefits 18,724 28,873 Federal net operating loss 155,276 252,780 Other deferred tax assets (a) 74,561 83,675 Less: Valuation allowance (9,121 ) (9,263 ) Total deferred tax assets 330,182 414,265 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (b) (510,774 ) (782,674 ) Regulatory assets (26,245 ) (49,471 ) Goodwill (46,392 ) (60,544 ) State deferred tax liability (58,930 ) (50,258 ) Deferred costs (16,063 ) (18,551 ) Other deferred tax liabilities (8,298 ) (14,702 ) Total deferred tax liabilities (666,702 ) (976,200 ) Net deferred tax liability $ (336,520 ) $ (561,935 ) _______________ (a) Other deferred tax assets consist primarily of alternative minimum tax credit and federal research and development credits. No single item exceeds 5% of the total net deferred tax liability. (b) The net deferred tax liabilities were revalued for the change in federal tax rate to 21% under the TCJA. The revaluation resulted in a reduction to net deferred tax liabilities of approximately $309 million . Due to the regulatory construct, approximately $301 million of the revaluation was reclassified to a regulatory liability.
Schedule of Effective Income Tax Rate Reconciliation	The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2017 2016 2015 Federal statutory rate 35.0 % 35.0 % 35.0 % State income tax (net of federal tax effect) 0.9 1.2 1.5 Percentage depletion (0.6 ) (0.8 ) (0.7 ) Non-controlling interest (a) (1.8 ) (1.6 ) — Equity AFUDC (0.2 ) (0.5 ) (0.1 ) Tax credits (1.7 ) (0.4 ) (0.1 ) Transaction costs — 0.5 — Accounting for uncertain tax positions adjustment (0.2 ) (2.7 ) 0.8 Flow-through adjustments (b) (1.1 ) (2.1 ) (1.0 ) Other tax differences (0.9 ) 0.1 0.3 IRC 172(f) carryback claim (0.7 ) — — Tax Cuts & Jobs Act corporate rate reduction (c) (2.7 ) — — 26.0 % 28.7 % 35.7 % _________________________ (a) The effective tax rate reflects the income attributable to the noncontrolling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (b) Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. (c) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. The 2017 effective tax rate reduction reflects the revaluation of deferred income taxes associated with non-regulated operations required by the change.
Summary of Operating Loss Carryforwards	At December 31, 2017 , we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal Net Operating Loss Carryforward $ 739,184 2019 to 2037 State Net Operating Loss Carryforward $ 688,335 2017 to 2038
Summary of Income Tax Contingencies	The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands): Changes in Uncertain Tax Positions Beginning balance at January 1, 2015 $ 32,192 Additions for prior year tax positions 3,285 Reductions for prior year tax positions (3,491 ) Additions for current year tax positions — Settlements — Ending balance at December 31, 2015 31,986 Additions for prior year tax positions 2,423 Reductions for prior year tax positions (19,174 ) Additions for current year tax positions — Settlements (11,643 ) Ending balance at December 31, 2016 3,592 Additions for prior year tax positions 358 Reductions for prior year tax positions (5,713 ) Additions for current year tax positions 5,026 Settlements — Ending balance at December 31, 2017 $ 3,263
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Summary of State Tax Carryforwards	State tax credits have been generated and are available to offset future state income taxes. At December 31, 2017 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year Investment tax credit $ 20,285 2023 to 2036 Research and development $ 179 No expiration

Comprehensive Income (Loss) (Ta

Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Reclassification out of Accumulated Other Comprehensive Income	The amounts in parentheses below indicate decreases to net income in the Consolidated Statements of Income (Loss) for the period, net of tax (in thousands): Location on the Consolidated Statements of Income (Loss) Amount Reclassified from AOCI December 31, 2017 December 31, 2016 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,941 ) $ (3,899 ) Commodity contracts (Loss) from discontinued operations 913 11,019 Commodity contracts Fuel, purchased power and cost of natural gas sold (243 ) (14 ) (2,271 ) 7,106 Income tax Income tax benefit (expense) 875 (2,702 ) Total reclassification adjustments related to cash flow hedges, net of tax $ (1,396 ) $ 4,404 Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 168 $ 194 Prior service cost (Loss) from discontinued operations 29 27 Actuarial gain (loss) Operations and maintenance (1,599 ) (1,881 ) Actuarial gain (loss) (Loss) from discontinued operations (58 ) (97 ) (1,460 ) (1,757 ) Income tax Income tax benefit (expense) (516 ) 533 Total reclassification adjustments related to defined benefit plans, net of tax $ (1,976 ) $ (1,224 ) Total reclassifications $ (3,372 ) $ 3,180
Schedule of Accumulated Other Comprehensive Income (Loss)	Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands): Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 ) Other comprehensive income (loss) before reclassifications — 231 (1,890 ) (1,659 ) Amounts reclassified from AOCI 1,912 (516 ) 944 2,340 Reclassification of certain tax effects from AOCI (3,384 ) — (3,616 ) (7,000 ) As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2015 $ (341 ) $ 7,066 $ (15,780 ) $ (9,055 ) Other comprehensive income (loss) before reclassifications (20,302 ) (361 ) (1,985 ) (22,648 ) Amounts reclassified from AOCI 2,534 (6,938 ) 1,224 (3,180 ) As of December 31, 2016 $ (18,109 ) $ (233 ) $ (16,541 ) $ (34,883 )

Supplemental Cash Flow Informat

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Years ended December 31, 2017 2016 2015 (in thousands) Non-cash investing activities and financing from continuing operations - Property, plant and equipment acquired with accrued liabilities $ 28,191 $ 27,034 $ 25,039 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 3,198 $ 8,577 $ (1,498 ) Cash (paid) refunded during the period for continuing operations- Interest (net of amount capitalized) $ (132,428 ) $ (113,627 ) $ (78,744 ) Income taxes (paid) refunded $ 1,775 $ (1,156 ) $ (1,202 )

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Schedule of Allocation of Plan Assets	The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows: 2017 2016 Equity 26% 28% Real estate 4 5 Fixed income 63 57 Cash 1 2 Hedge funds 6 8 Total 100% 100%
Schedule of Defined Contribution Plans Contributions	Contributions for the years ended December 31 were as follows (in thousands): 2017 2016 Defined Contribution Plan Company retirement contribution $ 10,223 $ 9,632 Matching contributions $ 9,811 $ 9,645 2017 2016 Defined Benefit Plans Defined Benefit Pension Plan $ 27,700 $ 14,200 Non-Pension Defined Benefit Postretirement Healthcare Plans $ 4,332 $ 4,965 Supplemental Non-Qualified Defined Benefit Plans $ 3,217 $ 1,565
Schedule of Changes in Projected Benefit Obligations	The following tables provide a reconciliation of the employee benefit plan obligations, fair value of assets and amounts recognized in the Consolidated Balance Sheets, components of the net periodic expense and elements of AOCI (in thousands): Benefit Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans As of December 31, 2017 2016 2017 2016 2017 2016 Change in benefit obligation: Projected benefit obligation at beginning of year $ 440,179 $ 356,575 $ 43,869 $ 40,219 $ 68,023 $ 48,077 Transfer from SourceGas Acquisition — 75,254 — — — 15,091 Service cost 7,034 7,619 2,937 2,099 2,300 1,757 Interest cost 15,520 15,743 1,276 1,257 2,141 1,942 Actuarial (gain) loss (a) 36,661 7,001 247 2,049 (396 ) 2,808 Amendments — — — — 265 2,203 Benefits paid (24,669 ) (22,013 ) (3,217 ) (1,755 ) (4,332 ) (4,965 ) Plan participants’ contributions — — — — 1,338 1,110 Projected benefit obligation at end of year $ 474,725 $ 440,179 $ 45,112 $ 43,869 $ 69,339 $ 68,023
Schedule of Changes in Fair Value of Plan Assets	Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans (a) As of December 31, 2017 2016 2017 2016 2017 2016 Change in fair value of plan assets: Beginning fair value of plan assets $ 364,695 $ 288,622 $ — $ — $ 8,470 $ 4,681 Transfer from SourceGas Acquisition — 53,067 — — — 3,340 Investment income (loss) 48,617 30,819 — — 120 256 Employer contributions 27,700 14,200 3,217 1,755 3,025 4,048 Retiree contributions — — — — 1,338 1,110 Benefits paid (24,669 ) (22,013 ) (3,217 ) (1,755 ) (4,332 ) (4,965 ) Ending fair value of plan assets $ 416,343 $ 364,695 $ — $ — $ 8,621 $ 8,470 ____________________ (a) Assets of VEBAs and Grantor Trust.
Schedule of Amounts Recognized in Balance Sheet	The funded status of the plans and the amounts recognized in the Consolidated Balance Sheets at December 31 consist of (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Regulatory assets $ 72,756 $ 66,640 $ — $ — $ 11,507 $ 11,401 Current liabilities $ — $ — $ 1,372 $ 1,583 $ 4,423 $ 4,360 Non-current assets $ — $ — $ — $ — $ 69 $ 21 Non-current liabilities $ 58,381 $ 75,484 $ 43,739 $ 42,286 $ 56,365 $ 55,214 Regulatory liabilities $ 5,232 $ 5,195 $ — $ — $ 3,334 $ 3,419
Schedule of Accumulated and Projected Benefit Obligations	Accumulated Benefit Obligation As of December 31 (in thousands) Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Accumulated Benefit Obligation (a) $ 450,394 $ 416,786 $ 41,243 $ 32,090 $ 69,339 $ 68,023 ____________________ (a) The Defined Benefit Pension Plan Accumulated Benefit Obligation for 2017 and 2016 represents the obligation for the merged Black Hills Retirement Plan. The Non-pension Defined Benefit Retirement Healthcare Plans Accumulated Benefit Obligation for 2017 and 2016 represents that obligation for the five postretirement plans maintained by BHC.
Components of net periodic benefit cost	Components of Net Periodic Expense Net periodic expense consisted of the following for the year ended December 31 (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2015 2017 2016 2015 2017 2016 2015 Service cost $ 7,034 $ 7,619 $ 6,093 $ 1,546 $ 1,335 $ 1,380 $ 2,300 $ 1,757 $ 1,808 Interest cost 15,520 15,743 15,522 1,276 1,257 1,455 2,141 1,942 1,801 Expected return on assets (24,517 ) (23,062 ) (19,470 ) — — — (315 ) (279 ) (131 ) Net amortization of prior service cost 58 58 58 2 2 2 (411 ) (428 ) (428 ) Recognized net actuarial loss (gain) 4,007 7,173 11,037 1,001 829 1,081 499 335 408 Settlement expense (a) — 10 — — — — — — — Net periodic expense $ 2,102 $ 7,541 $ 13,240 $ 3,825 $ 3,423 $ 3,918 $ 4,214 $ 3,327 $ 3,458 ____________________ (a) Settlement expense is the result of lump-sum payments on the SourceGas Retirement Plan in excess of interest and service costs for the year.
Schedule of Net Periodic Benefit Cost Not yet Recognized	For defined benefit plans, amounts included in AOCI, after-tax, that have not yet been recognized as components of net periodic benefit cost at December 31 were as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans 2017 2016 2017 2016 2017 2016 Net (gain) loss $ 10,056 $ 8,472 $ 6,639 $ 7,132 $ 1,309 $ 1,595 Prior service cost (gain) 21 31 4 5 (542 ) (694 ) Reclassification of certain tax effects from AOCI 2,087 — 1,371 — 158 — Total AOCI $ 12,164 $ 8,503 $ 8,014 $ 7,137 $ 925 $ 901
Schedule of Amounts in Accumulated Other Comprehensive Income (Loss) to be Recognized over Next Fiscal Year	The amounts in AOCI, Regulatory assets or Regulatory liabilities, after-tax, expected to be recognized as a component of net periodic benefit cost during calendar year 2018 are as follows (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Net loss $ 5,610 $ 650 $ 141 Prior service cost (credit) 38 1 (258 ) Total net periodic benefit cost expected to be recognized during calendar year 2018 $ 5,648 $ 651 $ (117 )
Schedule of Assumptions Used	Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine benefit obligations: 2017 2016 2015 2017 2016 2015 2017 2016 2015 Discount rate 3.71 % 4.27 % 4.58 % 3.56 % 4.02 % 4.28 % 3.60 % 3.96 % 4.17 % Rate of increase in compensation levels 3.43 % 3.47 % 3.51 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plans Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2017 2016 2015 2017 2016 2015 2017 2016 2015 Discount rate (a) 4.27 % 4.50 % 4.19 % 4.02 % 4.28 % 4.19 % 4.05 % 4.18 % 3.82 % Expected long-term rate of return on assets (b) 6.75 % 6.87 % 6.75 % N/A N/A N/A 3.88 % 3.83 % 3.00 % Rate of increase in compensation levels 3.47 % 3.42 % 3.76 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the merged Black Hills Retirement Plan is 3.71% for the calculation of the 2018 net periodic pension costs. (b) The expected rate of return on plan assets is 6.25% for the calculation of the 2018 net periodic pension cost.
Schedule of Health Care Cost Trend Rates	The healthcare benefit obligation was determined at December 31 as follows: 2017 2016 (a) Trend Rate - Medical Pre-65 for next year - All Plans 7.00% 6.10% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2024 Post-65 for next year - All Plans 5.00% 5.10% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2026 2023 _____________________________ (a) The 2016 Medical Trend Rates include the two additional non-pension defined benefit postretirement plans from SourceGas.
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	The table below shows the expected impacts of an increase or decrease to our healthcare trend rate for our Healthcare Plans (in thousands): Change in Assumed Trend Rate Impact on December 31, 2017 Accumulated Postretirement Benefit Obligation Impact on 2018 Service and Interest Cost Increase 1% $ 2,968 $ 148 Decrease 1% $ (2,534 ) $ (126 )
Schedule of Expected Benefit Payments	The following benefit payments, which reflect future service, are expected to be paid (in thousands): Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-Pension Defined Benefit Postretirement Healthcare Plans 2018 $ 21,495 $ 1,372 $ 5,633 2019 $ 23,238 $ 1,617 $ 6,231 2020 $ 27,203 $ 1,558 $ 6,328 2021 $ 26,990 $ 1,773 $ 6,072 2022 $ 27,427 $ 1,872 $ 5,920 2023-2027 $ 154,771 $ 11,304 $ 26,365
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Schedule of Allocation of Plan Assets	The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,280 $ — $ 1,280 $ — $ 1,280 Common Collective Trust - Cash and Cash Equivalents — 2,184 — 2,184 — 2,184 Common Collective Trust - Equity — 109,496 — 109,496 — 109,496 Common Collective Trust - Fixed Income — 262,329 — 262,329 — 262,329 Common Collective Trust - Real Estate — 1,728 — 1,728 15,701 17,429 Hedge Funds — — — — 23,625 23,625 Total investments measured at fair value $ — $ 377,017 $ — $ 377,017 $ 39,326 $ 416,343 Pension Plan December 31, 2016 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,325 $ — $ 1,325 $ — $ 1,325 Common Collective Trust - Cash and Cash Equivalents — 5,307 — 5,307 — 5,307 Common Collective Trust - Equity — 101,020 — 101,020 — 101,020 Common Collective Trust - Fixed Income — 209,815 — 209,815 — 209,815 Common Collective Trust - Real Estate — 2,349 — 2,349 15,563 17,912 Hedge Funds — — — — 29,316 29,316 Total investments measured at fair value $ — $ 319,816 $ — $ 319,816 $ 44,879 $ 364,695 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above.
Postretirement Health Coverage
Defined Benefit Plan Disclosure [Line Items]
Schedule of Allocation of Plan Assets	Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2017 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 4,671 $ — $ — $ 4,671 $ — $ 4,671 Equity Securities 1,374 — — 1,374 — 1,374 Intermediate-term Bond — 2,576 — 2,576 — 2,576 Total investments measured at fair value $ 6,045 $ 2,576 $ — $ 8,621 $ — $ 8,621 Non-pension Defined Benefit Postretirement Healthcare Plans December 31, 2016 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Cash and Cash Equivalents $ 111 $ — — $ 111 — $ 111 Equity Securities 1,154 — — $ 1,154 — 1,154 Registered Investment Company Trust - Money Market Mutual Fund — 4,732 — $ 4,732 — 4,732 Intermediate-term Bond — 2,473 — $ 2,473 — 2,473 Total investments measured at fair value $ 1,265 $ 7,205 $ — $ 8,470 $ — $ 8,470 _____________ (a) Certain investments that are measured at fair value using Net Asset Value “NAV” per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plans’ benefit obligations and fair value of plan assets above.

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligations Disclosure	The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services, coal and natural gas transportation and storage agreements (in thousands): Power Purchase Agreements Transportation, storage and coal agreements 2018 $ 28,041 $ 121,485 2019 $ 6,837 $ 122,351 2020 $ 6,837 $ 117,332 2021 $ 6,203 $ 107,918 2022 $ 6,203 $ 87,393 Thereafter $ 6,204 $ 202,831
Power purchased
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment	Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands): 2017 2016 2015 PPA with PacifiCorp $ 13,218 $ 12,221 $ 13,990 Transmission services agreement with PacifiCorp $ 1,671 $ 1,428 $ 1,213 PPA with Happy Jack $ 3,846 $ 3,836 $ 3,155 PPA with Silver Sage $ 4,934 $ 4,949 $ 4,107 Busch Ranch Wind Farm $ 1,966 $ 2,071 $ 1,734 PPAs with Cargill (a) $ — $ 10,995 $ 16,112 ________________ (a) PPAs with Cargill expired on December 31, 2016.
Purchased Gas Cost Obligation
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment	At December 31, 2017 , the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): CIG Rockies NNG-Ventura NWPL-Wyoming EP-San Juan Basin Other 2018 5,784,827 3,759,500 1,298,970 278,600 30,562 2019 5,776,125 3,704,300 786,470 287,000 — 2020 75,075 3,660,000 — 206,600 — 2021 — 3,650,000 — — — 2022 — 1,810,000 — — —

Guarantees (Tables)

Guarantees (Tables)	12 Months Ended
	Dec. 31, 2017
Guarantees [Abstract]
Schedule of Guarantor Obligations	We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2017 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 58,221 Ongoing $ 58,221 _______________________ (a) We have guarantees in place for reclamation and surety bonds for our subsidiaries. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by the surety bonds, such liabilities are included in our Consolidated Balance Sheets.

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Balance Sheet Accounts	Held for sale assets and liabilities at December 31, 2016 are classified as current and non-current. As of (in thousands) December 31, 2017 December 31, 2016 Other current assets $ 10,360 $ 11,401 Derivative assets, current and noncurrent — 153 Deferred income tax assets, noncurrent, net 16,966 26,329 Property, plant and equipment, net 56,916 82,812 Other current liabilities (18,966 ) (9,834 ) Derivative liabilities, current and noncurrent — (1,586 ) Other noncurrent liabilities (22,808 ) (22,803 ) Net assets $ 42,468 $ 86,472
Disposal Groups, Including Discontinued Operations, Income Statement	Operating results of the Oil and Gas segment included in Discontinued operations on the accompanying Consolidated Statements of Income were as follows (in thousands): For the Years Ended December 31, 2017 December 31, 2016 December 31, 2015 Revenue $ 25,382 $ 34,058 $ 43,283 Operations and maintenance 22,872 27,187 35,461 Depreciation, depletion and amortization 7,521 13,510 28,838 Impairment of long-lived assets 20,385 106,957 249,608 Total operating expenses 50,778 147,654 313,907 Operating (loss) (25,396 ) (113,596 ) (270,624 ) Interest income (expense), net 181 698 931 Other income (expense), net (297 ) 110 (378 ) Impairment of equity investments — — (4,405 ) Income tax benefit (expense) 8,413 48,626 100,817 (Loss) from discontinued operations $ (17,099 ) $ (64,162 ) $ (173,659 )

Oil and Gas Exploration and Pro

Oil and Gas Exploration and Production Industries Disclosure (Tables)	12 Months Ended
	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure	Following is a summary of costs incurred in oil and gas property acquisition, exploration and development during the years ended December 31 (in thousands): 2016 2015 Acquisition of properties: Proved $ — $ 1,407 Unproved 910 669 Exploration costs 1,102 35,434 Development costs 4,657 128,998 Asset retirement obligations incurred — 566 Total costs incurred $ 6,669 $ 167,074
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	The following table summarizes BHEP’s quantities of proved developed and undeveloped oil, natural gas and NGL reserves, estimated using SEC-defined product prices, as of December 31, 2016 and 2015 and a reconciliation of the changes between these dates. The summary information presented for our estimated proved developed and undeveloped crude oil, natural gas, and NGL reserves and the 10% discounted present value of estimated future net revenues is based on reports prepared by Cawley Gillespie & Associates (CG&A), an independent consulting and engineering firm located in Fort Worth, Texas. CG&A is a Texas Registered Engineering Firm. Our primary contact at CG&A is Mr. Zane Meekins. Mr. Meekins has been practicing consulting petroleum engineering since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas, a member of the Society of Petroleum Evaluation Engineers (SPEE), and has over 30 years of practical experience in petroleum engineering and over 28 years of experience in the estimation and evaluation of reserves. Reserves were determined consistent with SEC requirements using a 12-month average product price calculated using the first-day-of-the-month price for each of the 12 months in the reporting period held constant for the life of the properties. Reserves for crude oil, natural gas, and NGLs are reported separately and then combined for a total MMcfe (where oil and NGLs in Mbbl are converted to an MMcfe basis by multiplying Mbbl by six). Such reserve estimates were inherently imprecise and may be subject to revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Minor differences in amounts may result in the following tables relating to oil and gas reserves due to rounding. 2016 2015 Oil Gas NGL Oil Gas NGL (in Mbbls of oil and NGL, and MMcf of gas) Proved developed and undeveloped reserves: Balance at beginning of year 3,450 73,412 1,752 4,276 65,440 1,720 Production (a) (319 ) (9,430 ) (133 ) (371 ) (10,058 ) (102 ) Sales (570 ) (1,291 ) (17 ) (11 ) (828 ) — Additions - extensions and discoveries 3 52 — 199 24,462 232 Revisions to previous estimates (322 ) (8,173 ) 110 (643 ) (5,604 ) (98 ) Balance at end of year 2,242 54,570 1,712 3,450 73,412 1,752 Proved developed reserves at end of year included above 2,242 54,570 1,712 3,436 73,390 1,752 Proved undeveloped reserves at the end of year included in above — — — 14 22 — NYMEX prices $ 42.75 $ 2.48 $ — (b) $ 50.28 $ 2.59 $ — (b) Well-head reserve prices (c) $ 37.35 $ 2.25 $ 11.92 $ 44.72 $ 1.27 $ 18.96 ________________________ (a) Production for reserve calculations did not include volumes for natural gas liquids (NGLs) for historical periods. (b) A specific NYMEX price for NGL was not available. Market prices for NGL are broken down by various liquid components, including ethane, propane, isobutane, normal butane, and natural gasoline. Each of these components is traded as an index. Ethane was not being recovered at any of the facilities that process our natural gas production. (c) For reserves purposes, costs to gather gas previously netted from the gas price were reclassified into operating expenses in 2016, with approximate rates of $1.54 /Mcf for Piceance, $0.92 /Mcf for San Juan and $0.53 /Mcf for all others. The sales price for natural gas was adjusted for transportation costs and other related deductions when applicable.
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure	Following is information concerning capitalized costs for the years ended December 31 (in thousands): 2016 2015 Unproved oil and gas properties $ 18,547 $ 47,254 Proved oil and gas properties 1,043,558 1,008,466 Gross capitalized costs 1,062,105 1,055,720 Accumulated depreciation, depletion and amortization and valuation allowances (1,000,091 ) (888,775 ) Net capitalized costs $ 62,014 $ 166,945
Results of Operations for Oil and Gas Producing Activities Disclosure	Following is a summary of results of operations for producing activities for the years ended December 31 (in thousands): 2016 2015 Revenue $ 34,058 $ 43,283 Production costs 17,231 19,762 Depreciation, depletion and amortization 12,574 28,062 Impairment of long-lived assets 106,957 249,608 Total costs 136,762 297,432 Results of operations from producing activities before tax (102,704 ) (254,149 ) Income tax benefit (expense) 37,916 93,743 Results of operations from producing activities (excluding general and administrative costs and interest costs) $ (64,788 ) $ (160,406 )
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2016 and notes the year in which the associated costs were incurred (in thousands): 2016 2015 Prior Total Leasehold acquisition cost $ 963 $ — $ — $ 963 Exploration cost 532 441 — 973 Capitalized interest 50 23 — 73 Total $ 1,545 $ 464 $ — $ 2,009
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure	Following is a summary of the standardized measure of discounted future net cash flows and changes relating to proved oil and gas reserves for the years ended December 31 (in thousands): 2016 2015 Future cash inflows $ 246,221 $ 295,173 Future production costs (166,248 ) (146,552 ) Future development costs, including plugging and abandonment (18,333 ) (24,833 ) Future net cash flows 61,640 123,788 10% annual discount for estimated timing of cash flows (26,574 ) (44,760 ) Standardized measure of discounted future net cash flows $ 35,066 $ 79,028
Changes In Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserve Disclosures	The following are the principal sources of change in the standardized measure of discounted future net cash flows during the years ended December 31 (in thousands): 2016 2015 Standardized measure - beginning of year $ 79,028 $ 183,022 Sales and transfers of oil and gas produced, net of production costs (4,314 ) (29,948 ) Net changes in prices and production costs (32,698 ) (127,199 ) Extensions, discoveries and improved recovery, less related costs — 15,718 Changes in future development costs 1,825 (7,387 ) Development costs incurred during the period — 27,211 Revisions of previous quantity estimates (7,477 ) (6,941 ) Accretion of discount 7,903 18,870 Net change in income taxes — 5,682 Sales of reserves (9,201 ) — Standardized measure - end of year $ 35,066 $ 79,028

Quarterly Historical Data (Un55

Quarterly Historical Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Financial Information	The Company operates on a calendar year basis. The following tables set forth select unaudited historical operating results and market data for each quarter of 2017 and 2016 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2017 Revenue $ 547,528 $ 341,829 $ 335,611 $ 455,298 Operating income (loss) $ 150,186 $ 69,796 $ 79,559 $ 117,195 Income (loss) from continuing operations $ 81,715 $ 25,927 $ 32,898 $ 67,835 Income (loss) from discontinued operations $ (1,569 ) $ (616 ) $ (1,300 ) $ (13,614 ) Net income attributable to noncontrolling interest $ (3,623 ) $ (3,116 ) $ (3,935 ) $ (3,568 ) Net income (loss) available for common stock $ 76,523 $ 22,195 $ 27,663 $ 50,653 Amounts attributable to common shareholders: Net income (loss) from continuing operations $ 78,092 $ 22,811 $ 28,963 $ 64,267 Net income (loss) from discontinued operations $ (1,569 ) $ (616 ) $ (1,300 ) $ (13,614 ) Net income (loss) available for common stock $ 76,523 $ 22,195 $ 27,663 $ 50,653 Income (loss) per share for continuing operations - Basic $ 1.47 $ 0.43 $ 0.54 $ 1.21 Income (loss) per share for discontinued operations - Basic $ (0.03 ) $ (0.01 ) $ (0.02 ) $ (0.26 ) Earnings (loss) per share - Basic $ 1.44 $ 0.42 $ 0.52 $ 0.95 Income (loss) per share for continuing operations - Diluted $ 1.42 $ 0.41 $ 0.52 $ 1.17 Income (loss) per share for discontinued operations - Diluted $ (0.03 ) $ (0.01 ) $ (0.02 ) $ (0.25 ) Earnings (loss) per share - Diluted 1.39 0.40 0.50 0.92 Dividends paid per share $ 0.445 $ 0.445 $ 0.445 $ 0.475 Common stock prices - High $ 67.02 $ 72.02 $ 71.01 $ 69.79 Common stock prices - Low $ 60.02 $ 65.37 $ 67.08 $ 57.01 Income from continuing operations for each quarter of 2017 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $0.9 million during the first quarter, $0.3 million during the second quarter, $0.2 million during the third quarter and $1.3 million during the fourth quarter. Included within the Income (loss) from continuing operations in the fourth quarter of 2017 is a net tax benefit of $7.6 million from the impact of the TCJA, as well as a tax benefit of $4.1 million from a true-up to the filed 2016 SourceGas tax returns related to the SourceGas acquisition. Included within the Loss from discontinued operations in the fourth quarter of 2017 is an after-tax non-cash impairment of oil and gas properties of $13.0 million . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2016 Revenue $ 441,584 $ 317,795 $ 324,147 $ 455,390 Operating income (loss) $ 91,281 $ 63,725 $ 70,844 $ 110,330 Income (loss) from continuing operations $ 45,320 $ 21,128 $ 24,964 $ 55,381 Income (loss) from discontinued operations $ (5,270 ) $ (17,845 ) $ (7,080 ) $ (33,967 ) Net income attributable to noncontrolling interest $ (48 ) $ (2,614 ) $ (3,753 ) $ (3,246 ) Net income (loss) available for common stock $ 40,002 $ 669 $ 14,131 $ 18,168 Amounts attributable to common shareholders: Net income (loss) from continuing operations 45,272 18,514 21,211 52,135 Net income (loss) from discontinued operations (5,270 ) (17,845 ) (7,080 ) (33,967 ) Net income (loss) available for common stock 40,002 669 14,131 18,168 Income (loss) per share for continuing operations - Basic $ 0.88 $ 0.36 $ 0.41 $ 0.98 Income (loss) per share for discontinued operations - Basic (0.10 ) (0.35 ) (0.14 ) (0.64 ) Earnings (loss) per share - Basic $ 0.78 $ 0.01 $ 0.27 $ 0.34 Income (loss) per share for continuing operations - Diluted $ 0.87 $ 0.35 $ 0.39 $ 0.96 Income (loss) per share for discontinued operations - Diluted (0.10 ) (0.34 ) (0.13 ) (0.63 ) Earnings (loss) per share - Diluted $ 0.77 $ 0.01 $ 0.26 $ 0.33 Dividends paid per share $ 0.420 $ 0.420 $ 0.420 $ 0.420 Common stock prices - High $ 61.13 $ 63.53 $ 64.58 $ 62.83 Common stock prices - Low $ 44.65 $ 56.16 $ 56.86 $ 54.76 Income from continuing operations for each quarter of 2016 included external incremental acquisition and transaction costs. We incurred after-tax external incremental acquisition and transaction expenses of $15 million during the first quarter, $4.1 million during the second quarter, $4.1 million during the third quarter and $5.5 million during the fourth quarter. Included with loss from discontinued operations in each quarter of 2016 are non-cash impairments of oil and gas properties. We recorded after-tax impairments of oil and gas properties of $8.8 million during the first quarter, $16 million during the second quarter, $7.9 million during the third quarter and $34 million during the fourth quarter.

Business Description And Sign56

Business Description And Significant Accounting Policies: Segment Reporting (Details)	Feb. 23, 2018
Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Percent of Properties Having Either Closed Transactions or Signed Contracts to Sell	90.00%

Business Description And Sign57

Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (3,081)	$ (2,379)
Accounts receivable, net	248,330	259,311
Corporate, Non-Segment
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,457	2,228
Electric Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(586)	(353)
Accounts receivable, net	75,145	77,840
Gas Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(2,495)	(2,026)
Accounts receivable, net	167,728	174,471
Power Generation
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	1,196	1,420
Mining
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	2,804	3,352
Billed Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	126,060	136,898
Billed Revenues | Corporate, Non-Segment
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,457	2,228
Billed Revenues | Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	39,347	41,730
Billed Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	81,256	88,168
Billed Revenues | Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,196	1,420
Billed Revenues | Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,804	3,352
Unbilled Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	125,351	124,792
Unbilled Revenues | Corporate, Non-Segment
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues | Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	36,384	36,463
Unbilled Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	88,967	88,329
Unbilled Revenues | Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	0	0
Unbilled Revenues | Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	$ 0	$ 0

Business Description And Sign58

Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 69,732	$ 64,852
Fuel - Electric Utilities	2,962	3,667
Natural gas in storage	40,589	35,087
Total materials, supplies and fuel	$ 113,283	$ 103,606

Business Description And Sign59

Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued employee compensation, benefits and withholdings	$ 52,467	$ 54,553
Accrued property taxes	42,029	37,379
Customer deposits and prepayments	44,420	55,191
Accrued interest	33,822	33,982
CIAC current portion	1,552	1,575
Other (none of which is individually significant)	45,172	52,868
Total accrued liabilities	$ 219,462	$ 235,548

Business Description And Sign60

Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Roll Forward]
Goodwill, Beginning Balance	$ 1,299,454	$ 359,759
Goodwill	0	939,695
Goodwill, Ending Balance	1,299,454	1,299,454
Electric Utilities
Goodwill [Roll Forward]
Goodwill, Beginning Balance	248,479	248,479
Goodwill	0	0
Goodwill, Ending Balance	248,479	248,479
Gas Utilities
Goodwill [Roll Forward]
Goodwill, Beginning Balance	1,042,210	102,515
Goodwill	0	939,695
Goodwill, Ending Balance	1,042,210	1,042,210
Power Generation
Goodwill [Roll Forward]
Goodwill, Beginning Balance	8,765	8,765
Goodwill	0	0
Goodwill, Ending Balance	$ 8,765	$ 8,765
Aquila Transaction | Electric Utilities
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	72.00%
Goodwill [Roll Forward]
Goodwill, Ending Balance	$ 246,000
Aquila Transaction | Gas Utilities
Goodwill [Line Items]
Goodwill Allocation by Segment (percentage)	28.00%
Goodwill [Roll Forward]
Goodwill, Ending Balance	$ 94,000
SourceGas Transaction | Gas Utilities
Goodwill [Roll Forward]
Goodwill, Ending Balance	$ 940,000

Business Description And Sign61

Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 8,392	$ 3,380	$ 3,176
Intangible assets, additions	0	5,522	434
Intangible assets, amortization expense	(833)	(510)	(230)
Intangible assets, net, ending balance	7,559	$ 8,392	$ 3,380
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Future Amortization Expense, Year One	800
Future Amortization Expense, Year Two	800
Future Amortization Expense, Year Three	800
Future Amortization Expense, Year Four	800
Future Amortization Expense, Year Five	$ 800
Minimum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life	2 years
Maximum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life	40 years
Accumulated Other Comprehensive Income (Loss)
Finite-Lived Intangible Assets [Line Items]
Reclassification of certain tax effects from AOCI	$ (7,000)
Retained Earnings
Finite-Lived Intangible Assets [Line Items]
Reclassification of certain tax effects from AOCI	$ 7,000

Business Description And Sign62

Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) $ in Thousands	Apr. 29, 2016USD ($)$ / Btu	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets		$ 297,454	$ 296,142
Regulatory liabilities		$ 485,126	206,756
Deferred energy, fuel and gas cost adjustments - current
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		1 year
Regulatory liabilities		$ 3,427	10,368
Employee benefit plans
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		12 years
Regulatory liabilities		$ 40,629	68,654
Cost of removal
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		44 years
Regulatory liabilities		$ 130,932	118,410
Deferred Income Tax Charge
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		40 years
Regulatory liabilities		$ 301,553	62
Revenue Subject to Refund
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		1 year
Regulatory liabilities		$ 1,488	2,485
Other regulatory liabilities
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory liabilities maximum amortization period		25 years
Regulatory liabilities		$ 7,097	6,777
Deferred energy, fuel and gas cost adjustments - current
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		1 year
Regulatory assets		$ 20,187	17,491
Deferred gas cost adjustments
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		1 year
Regulatory assets		$ 31,844	15,329
Gas price derivatives
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		3 years
Regulatory assets		$ 11,935	8,843
Deferred taxes on AFUDC
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		45 years
Regulatory assets		$ 7,847	15,227
Employee benefit plans
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		12 years
Regulatory assets		$ 109,235	108,556
Environmental
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets			1,108
Asset retirement obligations
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		44 years
Regulatory assets		$ 517	505
Loss on reacquired debt
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		30 years
Regulatory assets		$ 20,667	22,266
Renewable energy standard adjustment
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		5 years
Regulatory assets		$ 1,088	1,605
Deferred taxes on flow through accounting
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		54 years
Regulatory assets		$ 26,978	37,498
Decommissioning costs
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		10 years
Regulatory assets		$ 13,287	16,859
Gas supply contract termination
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period	5 years	4 years
Regulatory assets	$ 30,000	$ 20,001	26,666
Other regulatory assets
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets maximum amortization period		30 years
Regulatory assets		$ 32,837	$ 24,189
Minimum
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu	6
Minimum | Gas supply contract termination
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu	6
Maximum
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu	8
Maximum | Gas supply contract termination
Settlement of Gas Supply Contract [Abstract]
Oil and Gas Delivery Commitments and Contracts, Fixed Price | $ / Btu	8
Manufactured Gas Plant | Environmental
Schedule of Regulatory Assets and Liabilities [line items]
Regulatory assets		$ 1,031

Business Description And Sign63

Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net Income (Loss) Available to Common Stockholders, Basic	$ 50,653	$ 27,663	$ 22,195	$ 76,523	$ 18,168	$ 14,131	$ 669	$ 40,002	$ 177,034	$ 72,970	$ (32,111)
Weighted average shares - Basic (in shares)									53,221,000	51,922,000	45,288,000
Dilutive effect of:
Equity Units (in shares)									1,783,000	1,222,000	0
Equity compensation (in shares)									116,000	127,000	0
Weighted average shares - diluted (in shares)									55,120,000	53,271,000	45,288,000
Total earnings (loss) per share of common stock, Diluted (usd per share)	$ 0.92	$ 0.50	$ 0.40	$ 1.39	$ 0.33	$ 0.26	$ 0.01	$ 0.77	$ 3.21	$ 1.37	$ (0.71)
Equity compensation shares excluded (in shares)									83,000

Business Description And Sign64

Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	11	3	6,552
Equity Compensation
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	11	3	112
Equity Unit Purchase Agreements
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	0	0	6,440

Business Description And Sign65

Business Description And Significant Accounting Policies: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Details) $ in Millions	Dec. 22, 2017USD ($)
Accounting Standards Update 2018-02
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 7

Business Description And Sign66

Business Description And Significant Accounting Policies: Improvement To Employee Share-Based Payment Accounting (Details) $ in Millions	Jan. 01, 2017USD ($)
Accounting Standards Update 2016-09
Retained Earnings Adjustments [Line Items]
Cumulative Effect on Retained Earnings, Net of Tax	$ 3.2

Acquisition (Details)

Acquisition (Details) $ / shares in Units, $ in Thousands	Apr. 29, 2016USD ($)$ / Btu	Feb. 12, 2016USD ($)utilitycustomermi	Jan. 13, 2016USD ($)	Nov. 23, 2015USD ($)shares	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / sharesshares
Acquisition Narrative [Abstract]
Ownership of subsidiary (percent)														100.00%
Cash consideration paid		$ 1,135,000
Proceeds from issuance of shares				$ 536,000
Long-term debt - issuance			$ 546,000										$ 0	$ 1,767,608	$ 300,000
Revenue					$ 455,298	$ 335,611	$ 341,829	$ 547,528	$ 455,390	$ 324,147	$ 317,795	$ 441,584	1,680,266	1,538,916	1,261,322
Net income (loss) available for common stock					50,653	$ 27,663	$ 22,195	$ 76,523	18,168	$ 14,131	$ 669	$ 40,002	177,034	72,970	(32,111)
Cash consideration paid		(1,124,238)											0	1,124,238	21,970
Acquisition Recap [Abstract]
Consideration paid, net of working capital adjustment received		(1,124,238)											0	1,124,238	21,970
Goodwill					1,299,454				1,299,454				1,299,454	1,299,454	359,759
Settlement of Gas Supply Contract [Abstract]
Settlement of gas supply contract	$ 40,000
Contract committed to distribution customers, percent	75.00%
Contract not subject to regulatory recovery, percent	25.00%
Regulatory assets					297,454				296,142				$ 297,454	296,142
Pro Forma Results
Estimated combined federal and state income tax rate (percent)													37.00%
Noncontrolling Interest [Abstract]
Sellers retention (percent)								0.50%
Payments for Repurchase of Redeemable Noncontrolling Interest								$ 5,600
Gas Supply Contract Termination
Settlement of Gas Supply Contract [Abstract]
Regulatory assets	$ 30,000				20,001				26,666				$ 20,001	26,666
Recovery period	5 years												4 years
Minimum
Settlement of Gas Supply Contract [Abstract]
Contract prices | $ / Btu	6
Minimum | Gas Supply Contract Termination
Settlement of Gas Supply Contract [Abstract]
Contract prices | $ / Btu	6
Maximum
Settlement of Gas Supply Contract [Abstract]
Contract prices | $ / Btu	8
Maximum | Gas Supply Contract Termination
Settlement of Gas Supply Contract [Abstract]
Contract prices | $ / Btu	8
Corporate, Non-Segment
Acquisition Narrative [Abstract]
Pre-tax, incremental acquisition costs														45,000	10,000
Revenue													$ 344,685	$ 347,500	$ 227,708
Remarketable Junior Subordinated Notes Due 2028
Acquisition Narrative [Abstract]
Issuance of equity units | shares				5,980,000
Common Stock
Acquisition Narrative [Abstract]
Issuance of common stock, shares | shares				6,325,000										1,968,738	6,325,000
Source Gas
Acquisition Narrative [Abstract]
Purchase Price		1,894,882
Assumed long-term debt		760,000
Less: Working capital adjustment received		$ (10,644)
Number of natural gas utilities acquired | utility		4
Number of customers served with acquisition | customer		429,000
Length of natural gas pipeline (miles) | mi		512
Revenue														$ 348,000
Net income (loss) available for common stock														15,000
Expected tax deductible goodwill					252,000								252,000
Acquisition Recap [Abstract]
Purchase Price		$ 1,894,882
Less: Long-term debt assumed		(760,000)
Less: Working capital adjustment received		(10,644)
Current Assets		112,983
Property, plant & equipment, net		1,058,093
Deferred charges and other assets, excluding goodwill		133,299
Current liabilities		(172,454)
Long-term debt		(758,874)
Deferred credits and other liabilities		(188,504)
Total consideration paid, net of working-capital adjustment received		$ 1,124,238
Pro Forma Results
Revenue														1,617,878	$ 1,720,618
Business Acquisition, Pro Forma Income (Loss) from Continuing Operations, Net of Tax														177,040	160,290
Net income (loss)														$ 112,878	$ (13,369)
Earnings (loss) per share, Basic (usd per share) | $ / shares														$ 3.41	$ 3.15
Earnings (loss) per share, Diluted (usd per share) | $ / shares														$ 3.32	$ 3.15
Source Gas | Black Hills Energy, Arkansas
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Base Rate Moratorium Imposed by ASPC		12 months
Annual Amount of Customer Credit													250
Source Gas | Black Hills Energy, Arkansas | Maximum
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Annual Customer Credit		5 years
Source Gas | Rocky Mountain Natural Gas
Public Utilities, Rate Matters, Approved [Abstract]
Duration of Base Rate Moratorium imposed by CPUC		2 years
Source Gas | Black Hills Gas Distribution, Colorado
Public Utilities, Rate Matters, Approved [Abstract]
Annual Amount of Customer Credit													200
Duration of Base Rate Moratorium imposed by CPUC		3 years
Source Gas | Black Hills Gas Distribution, Colorado | Maximum
Public Utilities, Rate Matters, Approved [Abstract]
Duration Of Annual Customer Credit		5 years
Source Gas | Black Hills Gas Distribution - Nebraska
Public Utilities, Rate Matters, Approved [Abstract]
Duration of Base Rate Moratorium imposed by NPSC		3 years
Continuation Period of Choice Gas Program		3 years
Source Gas | Black Hills Gas Distribution - Wyoming
Public Utilities, Rate Matters, Approved [Abstract]
Continuation Period of Choice Gas Program		3 years
Gas Utilities
Acquisition Narrative [Abstract]
Revenue													947,595	$ 838,343	$ 551,300
Acquisition Recap [Abstract]
Goodwill					1,042,210				$ 1,042,210				1,042,210	$ 1,042,210	$ 102,515
Gas Utilities | SourceGas Transaction
Acquisition Recap [Abstract]
Goodwill		$ 939,695			$ 940,000								$ 940,000

Property, Plant and Equipment68

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 5,567,518	$ 5,315,296
Less: accumulated depreciation, depletion and amortization	1,026,088	929,119
Total property, plant and equipment, net	4,541,430	4,386,177
Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	11,954	21,599
Less: accumulated depreciation, depletion and amortization	309	2,106
Total property, plant and equipment, net	25,715	25,603
Property, plant and equipment	5,580	9,625
Construction in progress, gross	6,374	11,974
Intercompany Eliminations
Property, Plant and Equipment [Line Items]
Accumulated Depreciation - Capital Lease Elimination	$ 14,070	$ 6,110
Weighted Average | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	8 years	8 years
Minimum | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years	3 years
Maximum | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	30 years	30 years
Electric Utilities
Property, Plant and Equipment [Line Items]
Total plant in service before construction work in progress	$ 2,976,613	$ 2,801,549
Construction work in progress	13,595	74,045
Property, plant and equipment, gross	2,990,208	2,875,594
Less: accumulated depreciation, depletion and amortization	644,022	578,162
Total property, plant and equipment, net	$ 2,346,186	2,297,432
Depreciation, depletion and amortization, remaining amortization period	13 years
Electric Utilities | Production, Electric
Property, Plant and Equipment [Line Items]
Production	$ 1,315,044	$ 1,303,101
Electric Utilities | Production, Electric | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	39 years	41 years
Electric Utilities | Production, Electric | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	30 years
Electric Utilities | Production, Electric | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	55 years
Electric Utilities | Electric transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 407,203	$ 354,801
Electric Utilities | Electric transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	51 years	52 years
Electric Utilities | Electric transmission | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 years
Electric Utilities | Electric transmission | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	70 years
Electric Utilities | Electric distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 755,213	$ 712,575
Electric Utilities | Electric distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	48 years	48 years
Electric Utilities | Electric distribution | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	15 years
Electric Utilities | Electric distribution | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	75 years
Electric Utilities | Plant acquisition adjustment
Property, Plant and Equipment [Line Items]
Plant acquisition adjustment	$ 4,870	$ 4,870
Electric Utilities | Plant acquisition adjustment | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years	32 years
Electric Utilities | Plant acquisition adjustment | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years
Electric Utilities | Plant acquisition adjustment | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years
Electric Utilities | General
Property, Plant and Equipment [Line Items]
General	$ 232,842	$ 164,761
Electric Utilities | General | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	31 years	25 years
Electric Utilities | General | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years
Electric Utilities | General | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	65 years
Electric Utilities | Capital lease - plant in service
Property, Plant and Equipment [Line Items]
Capital lease - plant in service	$ 261,441	$ 261,441
Electric Utilities | Capital lease - plant in service | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years	20 years
Electric Utilities | Capital lease - plant in service | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years
Electric Utilities | Capital lease - plant in service | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years
Gas Utilities
Property, Plant and Equipment [Line Items]
Production	$ 10,495	$ 10,821
Total plant in service before construction work in progress	2,206,753	2,070,578
Construction work in progress	44,440	28,446
Property, plant and equipment, gross	2,251,193	2,099,024
Less: accumulated depreciation, depletion and amortization	229,170	194,585
Total property, plant and equipment, net	$ 2,022,023	$ 1,904,439
Gas Utilities | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	35 years	35 years
Gas Utilities | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	17 years
Gas Utilities | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	71 years
Gas Utilities | General
Property, Plant and Equipment [Line Items]
General	$ 336,869	$ 339,382
Gas Utilities | General | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	19 years	19 years
Gas Utilities | General | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	3 years
Gas Utilities | General | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	44 years
Gas Utilities | Gas transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 366,433	$ 338,729
Gas Utilities | Gas transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	48 years	48 years
Gas Utilities | Gas transmission | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	22 years
Gas Utilities | Gas transmission | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	70 years
Gas Utilities | Gas distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 1,413,431	$ 1,303,366
Gas Utilities | Gas distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	42 years	42 years
Gas Utilities | Gas distribution | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	33 years
Gas Utilities | Gas distribution | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	47 years
Gas Utilities | Cushion Gas - Depreciable
Property, Plant and Equipment [Line Items]
Production	$ 3,539	$ 3,539
Gas Utilities | Cushion Gas - Depreciable | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	28 years	28 years
Gas Utilities | Cushion Gas - Depreciable | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	28 years
Gas Utilities | Cushion Gas - Depreciable | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	28 years
Gas Utilities | Cushion Gas - Not Depreciated
Property, Plant and Equipment [Line Items]
Production	$ 47,466	$ 47,055
Gas Utilities | Cushion Gas - Not Depreciated | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	0 years	0 years
Gas Utilities | Cushion Gas - Not Depreciated | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	0 years
Gas Utilities | Cushion Gas - Not Depreciated | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	0 years
Gas Utilities | Production, Gas
Property, Plant and Equipment [Line Items]
Production	$ 28,520	$ 27,686
Gas Utilities | Production, Gas | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	31 years	31 years
Gas Utilities | Production, Gas | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	15 years
Gas Utilities | Production, Gas | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	48 years
Power Generation
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 155,793	$ 162,728
Less: accumulated depreciation, depletion and amortization	57,813	55,157
Total property, plant and equipment, net	97,980	107,571
Property, plant and equipment	155,569	161,430
Construction in progress, gross	$ 224	$ 1,298
Power Generation | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	33 years	33 years
Power Generation | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years	2 years
Power Generation | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 years	40 years
Mining
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 158,370	$ 156,351
Less: accumulated depreciation, depletion and amortization	108,844	105,219
Total property, plant and equipment, net	49,526	51,132
Property, plant and equipment	158,370	151,709
Construction in progress, gross	$ 0	$ 4,642
Mining | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	14 years	13 years
Mining | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years	2 years
Mining | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	59 years	59 years

Jointly Owned Facilities (Detai

Jointly Owned Facilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MW
Wyodak Plant | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	20.00%
Plant in Service	$ 114,405
Construction Work in Progress	727
Accumulated Depreciation	$ 58,955
Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity | MW	400
Transmission Tie | West to East Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity | MW	200
Transmission Tie | East to West Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity | MW	200
Transmission Tie | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	35.00%
Plant in Service	$ 20,037
Construction Work in Progress	242
Accumulated Depreciation	$ 6,215
Wygen I Generating Facility | Power Generation
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	76.50%
Plant in Service	$ 109,552
Construction Work in Progress	209
Accumulated Depreciation	$ 40,465
Wygen I I I Generating Facility | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	52.00%
Plant in Service	$ 138,688
Construction Work in Progress	406
Accumulated Depreciation	$ 19,239
Busch Ranch Wind Farm | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	50.00%
Plant in Service	$ 18,899
Construction Work in Progress	0
Accumulated Depreciation	$ 3,858

Business Segment Information_ S

Business Segment Information: Segment Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting, Asset Reconciling Item
Total Assets	$ 6,658,902	$ 6,541,773
Discontinued Operations, Held-for-sale
Segment Reporting, Asset Reconciling Item
Total Assets	84,242	120,695
Corporate, Non-Segment
Segment Reporting, Asset Reconciling Item
Total Assets	115,612	112,760
Electric Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	2,906,275	2,859,559
Gas Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	3,426,466	3,307,967
Power Generation
Segment Reporting, Asset Reconciling Item
Total Assets	60,852	73,445
Mining
Segment Reporting, Asset Reconciling Item
Total Assets	$ 65,455	$ 67,347

Business Segment Information_ C

Business Segment Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands	Feb. 12, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		$ 337,689	$ 460,450
Acquisition of net assets, net of long-term debt assumed	$ 1,124,238	0	(1,124,238)	$ (21,970)
Total Capital Expenditures And Asset Acquisitions Of Continuing Operations		337,689	1,584,688
Capital Expenditure, Discontinued Operations		23,222	6,669
Property, Plant and Equipment Including New Asset Acquisitions, Gross Period Increase (Decrease)		360,911	1,591,357
Gas Utilities
Segment Reporting Information [Line Items]
Acquisition of net assets, net of long-term debt assumed		0	1,124,238
Source Gas
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions	$ 1,124,000
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		6,668	17,353
Electric Utilities
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		138,060	258,739
Gas Utilities
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		184,389	173,930
Power Generation
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		1,864	4,719
Mining
Segment Reporting Information [Line Items]
Capital Expenditures and Asset Acquisitions		$ 6,708	$ 5,709

Business Segment Information_ P

Business Segment Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Segment Reporting Information [Line Items]
Property, plant and equipment	$ 5,567,518	$ 5,315,296
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Property, plant and equipment	11,954	21,599
Electric Utilities
Segment Reporting Information [Line Items]
Property, plant and equipment	2,990,208	2,875,594
Gas Utilities
Segment Reporting Information [Line Items]
Property, plant and equipment	2,251,193	2,099,024
Power Generation
Segment Reporting Information [Line Items]
Property, plant and equipment	155,793	162,728
Mining
Segment Reporting Information [Line Items]
Property, plant and equipment	$ 158,370	$ 156,351

Business Segment Information_ I

Business Segment Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information
Revenue	$ 455,298	$ 335,611	$ 341,829	$ 547,528	$ 455,390	$ 324,147	$ 317,795	$ 441,584	$ 1,680,266	$ 1,538,916	$ 1,261,322
Fuel, purchased power and cost of natural gas sold									563,288	499,132	456,887
Operations and maintenance									511,996	528,070	377,482
Depreciation, depletion and amortization									188,246	175,533	126,533
Operating income	117,195	79,559	69,796	150,186	110,330	70,844	63,725	91,281	416,736	336,181	300,420
Interest expense									(138,118)	(136,110)	(84,650)
Interest income									1,016	1,429	1,621
Other income (expense), net									2,108	4,394	2,814
Income tax benefit (expense)									(73,367)	(59,101)	(78,657)
Income (loss) from continuing operations	67,835	32,898	25,927	81,715	55,381	24,964	21,128	45,320	208,375	146,793	141,548
(Income) loss from discontinued operations, net of tax	(13,614)	(1,300)	(616)	(1,569)	(33,967)	(7,080)	(17,845)	(5,270)	(17,099)	(64,162)	(173,659)
Net income (loss)									191,276	82,631	(32,111)
Net income attributable to noncontrolling interest	$ (3,568)	$ (3,935)	$ (3,116)	$ (3,623)	$ (3,246)	$ (3,753)	$ (2,614)	$ (48)	(14,242)	(9,661)	0
Net income (loss) available for common stock									177,034	72,970	(32,111)
Electric Utilities
Segment Reporting Information
Revenue									689,945	664,330	668,226
Fuel, purchased power and cost of natural gas sold									268,405	261,349	269,409
Operations and maintenance									172,307	158,134	160,924
Depreciation, depletion and amortization									93,315	84,645	80,929
Operating income									170,623	173,153	168,581
Interest expense									(55,229)	(56,237)	(55,159)
Interest income									2,955	5,946	4,114
Other income (expense), net									1,730	3,193	1,216
Income tax benefit (expense)									(9,997)	(40,228)	(41,173)
Income (loss) from continuing operations									110,082	85,827	77,579
Net income (loss)									110,082	85,827	77,579
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									110,082	85,827	77,579
Gas Utilities
Segment Reporting Information
Revenue									947,595	838,343	551,300
Fuel, purchased power and cost of natural gas sold									409,603	352,165	299,645
Operations and maintenance									269,190	245,826	140,723
Depreciation, depletion and amortization									83,732	78,335	32,326
Operating income									185,105	162,017	78,606
Interest expense									(80,829)	(76,586)	(17,912)
Interest income									2,254	1,573	601
Other income (expense), net									(829)	184	315
Income tax benefit (expense)									(39,799)	(27,462)	(22,304)
Income (loss) from continuing operations									65,902	59,726	39,306
Net income (loss)									65,902	59,726	39,306
Net income attributable to noncontrolling interest									(107)	(102)	0
Net income (loss) available for common stock									65,795	59,624	39,306
Power Generation
Segment Reporting Information
Revenue									7,263	7,176	7,483
Fuel, purchased power and cost of natural gas sold									0	0	0
Operations and maintenance									32,382	32,636	32,140
Depreciation, depletion and amortization									5,993	4,104	4,329
Operating income									53,171	54,391	54,321
Interest expense									(3,959)	(3,758)	(4,218)
Interest income									1,123	1,983	1,015
Other income (expense), net									(54)	2	71
Income tax benefit (expense)									10,333	(17,129)	(18,539)
Income (loss) from continuing operations									60,614	35,489	32,650
Net income (loss)									60,614	35,489	32,650
Net income attributable to noncontrolling interest									(14,135)	(9,559)	0
Net income (loss) available for common stock									46,479	25,930	32,650
Mining
Segment Reporting Information
Revenue									35,463	29,067	34,313
Fuel, purchased power and cost of natural gas sold									0	0	0
Operations and maintenance									44,882	39,576	41,630
Depreciation, depletion and amortization									8,239	9,346	9,806
Operating income									13,500	11,358	13,630
Interest expense									(228)	(401)	(433)
Interest income									23	24	34
Other income (expense), net									2,191	2,209	2,247
Income tax benefit (expense)									(1,100)	(3,137)	(3,608)
Income (loss) from continuing operations									14,386	10,053	11,870
Net income (loss)									14,386	10,053	11,870
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									14,386	10,053	11,870
Intercompany Eliminations
Segment Reporting Information
Revenue									(474,866)	(475,619)	(353,385)
Fuel, purchased power and cost of natural gas sold									(114,871)	(114,838)	(112,289)
Operations and maintenance									(302,832)	(326,846)	(229,790)
Depreciation, depletion and amortization									(24,064)	(23,827)	(10,580)
Operating income									(33,099)	(10,108)	(726)
Interest expense									154,543	115,469	54,568
Interest income									(120,721)	(105,244)	(52,942)
Other income (expense), net									(331,303)	(181,032)	(71,964)
Income tax benefit (expense)									(371)	457	361
Income (loss) from continuing operations									(330,951)	(180,458)	(70,703)
Net income (loss)									(330,951)	(180,458)	(70,703)
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									(330,951)	(180,458)	(70,703)
Intercompany Eliminations | Electric Utilities
Segment Reporting Information
Revenue									14,705	12,951	11,617
Intercompany Eliminations | Gas Utilities
Segment Reporting Information
Revenue									35	0	0
Intercompany Eliminations | Power Generation
Segment Reporting Information
Revenue									84,283	83,955	83,307
Intercompany Eliminations | Mining
Segment Reporting Information
Revenue									31,158	31,213	30,753
Operating Segments | Electric Utilities
Segment Reporting Information
Revenue									704,650	677,281	679,843
Operating Segments | Gas Utilities
Segment Reporting Information
Revenue									947,630	838,343	551,300
Operating Segments | Power Generation
Segment Reporting Information
Revenue									91,546	91,131	90,790
Operating Segments | Mining
Segment Reporting Information
Revenue									66,621	60,280	65,066
Corporate, Non-Segment
Segment Reporting Information
Revenue									344,685	347,500	227,708
Fuel, purchased power and cost of natural gas sold									151	456	122
Operations and maintenance									296,067	378,744	231,855
Depreciation, depletion and amortization									21,031	22,930	9,723
Operating income									27,436	(54,630)	(13,992)
Interest expense									(152,416)	(114,597)	(61,496)
Interest income									115,382	97,147	48,799
Other income (expense), net									330,373	179,838	70,929
Income tax benefit (expense)									(32,433)	28,398	6,606
Income (loss) from continuing operations									288,342	136,156	50,846
Net income (loss)									288,342	136,156	50,846
Net income attributable to noncontrolling interest									0	0	0
Net income (loss) available for common stock									288,342	136,156	50,846
Consolidation, Eliminations
Segment Reporting Information
Revenue									$ 0	$ 0	$ 0

Business Segment Information_74

Business Segment Information: Corporate Expense Reallocation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	$ 9,577	$ 10,924	$ 9,980
Segment Reconciling Items
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	3,172	4,887	6,023
Corporate, Non-Segment
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	6,405	6,037	3,957
Corporate, Non-Segment | Interest Expense
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	4,900	5,600	3,400
Expenses Allocated to Segments | Electric Utilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	1,323
Expenses Allocated to Segments | Gas Utilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	1,571
Expenses Allocated to Segments | Power Generation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	177
Expenses Allocated to Segments | Mining
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated	$ 101
Expenses Allocated to Corporate, Non-Segment | Electric Utilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated		2,079	3,344
Expenses Allocated to Corporate, Non-Segment | Gas Utilities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated		2,292	1,815
Expenses Allocated to Corporate, Non-Segment | Power Generation
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated		320	543
Expenses Allocated to Corporate, Non-Segment | Mining
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Corporate Expenses Reallocated		$ 196	$ 321

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016	Aug. 19, 2016	Aug. 10, 2016	Jun. 07, 2016	Jan. 13, 2016	Nov. 23, 2015
Debt Instrument [Line Items]
Total long-term debt	$ 3,133,621	$ 3,238,754
Less current maturities	(5,743)	(5,743)
Less deferred financing costs	(18,478)	(21,822)
Long-term debt, net of current maturities	3,109,400	3,211,189
Revolving Credit Facility
Debt Instrument [Line Items]
Less deferred financing costs	(1,700)	(2,300)
Electric Utilities
Debt Instrument [Line Items]
Long-term debt	544,855	544,855
Less unamortized debt discount	(90)	(94)
Total long-term debt	$ 544,765	544,761
Electric Utilities | First Mortgage Bonds Due 2032
Debt Instrument [Line Items]
Interest rate (percent)	7.23%
Long-term debt	$ 75,000	75,000
Electric Utilities | First Mortgage Bonds Due 2039
Debt Instrument [Line Items]
Interest rate (percent)	6.125%
Long-term debt	$ 180,000	180,000
Electric Utilities | First Mortgage Bonds Due 2037
Debt Instrument [Line Items]
Interest rate (percent)	6.67%
Long-term debt	$ 110,000	110,000
Electric Utilities | Industrial Development Revenue Bonds Due 2021
Debt Instrument [Line Items]
Long-term Debt, Variable Interest Rate	1.78%
Long-term debt	$ 7,000	7,000
Electric Utilities | Industrial Development Revenue Bonds Due 2027
Debt Instrument [Line Items]
Long-term Debt, Variable Interest Rate	1.78%
Long-term debt	$ 10,000	10,000
Electric Utilities | Series 94 A Debt, Due 2024
Debt Instrument [Line Items]
Long-term Debt, Variable Interest Rate	1.83%
Long-term debt	$ 2,855	2,855
Black Hills Corporation
Debt Instrument [Line Items]
Long-term debt	2,592,664	2,698,406
Less unamortized debt discount	(3,808)	(4,413)
Total long-term debt	$ 2,588,856	2,693,993
Black Hills Corporation | Senior Unsecured Notes Due 2023
Debt Instrument [Line Items]
Interest rate (percent)	4.25%
Long-term debt	$ 525,000	525,000
Black Hills Corporation | Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Interest rate (percent)	5.875%
Long-term debt	$ 200,000	200,000
Black Hills Corporation | Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Interest rate (percent)	3.50%						3.50%
Long-term debt	$ 299,000	299,000					$ 299,000
Black Hills Corporation | Corporate Term Loan Due August 2019
Debt Instrument [Line Items]
Long-term debt			$ 500,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Interest rate (percent)	2.50%					2.50%
Long-term debt	$ 250,000	250,000				$ 250,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026
Debt Instrument [Line Items]
Interest rate (percent)	3.95%					3.95%
Long-term debt	$ 300,000	300,000				$ 300,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Interest rate (percent)	3.15%		3.15%
Long-term debt		400,000	$ 400,000	$ 400,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046
Debt Instrument [Line Items]
Interest rate (percent)	4.20%		4.20%
Long-term debt	$ 300,000	300,000	$ 300,000
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Interest rate (percent)	2.32%				2.32%
Long-term debt	$ 18,664	24,406			$ 29,000
Black Hills Corporation | Corporate, Non-Segment | London Interbank Offered Rate (LIBOR) | Corporate Term Loan Due August 2019
Debt Instrument [Line Items]
Long-term Debt, Variable Interest Rate	2.55113%
Long-term debt	$ 300,000	400,000
South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Interest rate (percent)	4.43%
Long-term debt	$ 85,000	85,000
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Interest rate (percent)	4.53%
Long-term debt	$ 75,000	$ 75,000

Long-Term Debt_ Aggregate Matur

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Long-term Debt, Unclassified [Abstract]
2,018	$ 5,743	$ 5,743
2,019	555,742
2,020	205,743
2,021	8,436
2,022	0
Thereafter	$ 2,361,855

Long-Term Debt_ Assumption Of L

Long-Term Debt: Assumption Of Long-Term Debt (Details) - Source Gas - USD ($) $ in Thousands	Aug. 19, 2016	Aug. 09, 2016	Feb. 12, 2016
Debt Instrument [Line Items]
Assumed long-term debt			$ 760,000
Extinguishment of Debt, Amount	$ 760,000
Senior Unsecured Notes Due 2017
Debt Instrument [Line Items]
Assumed long-term debt			$ 325,000
Interest rate (percent)	5.90%		5.90%
Extinguishment of Debt, Amount	$ 325,000
Senior Secured Notes Due 2019
Debt Instrument [Line Items]
Assumed long-term debt			$ 95,000
Interest rate (percent)	3.98%		3.98%
Extinguishment of Debt, Amount	$ 95,000
Corporate Term Loan Due June 2017
Debt Instrument [Line Items]
Assumed long-term debt			$ 340,000
Extinguishment of Debt, Amount	$ 100,000	$ 240,000
Corporate Term Loan Due June 2017 | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Interest rate (percent)			0.875%

Long-Term Debt_ Debt Transactio

Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands

Jul. 17, 2017

May 16, 2017

Aug. 19, 2016

Aug. 10, 2016

Aug. 09, 2016

Jan. 13, 2016

Jun. 30, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Jun. 07, 2016

Feb. 12, 2016

Jan. 31, 2016

Debt Instrument [Line Items]

Interest rate swap settlement

$ 0

$ 28,820

$ 0

Net proceeds from the offering

$ 546,000

0

1,767,608

$ 300,000

Interest Rate Swap

Debt Instrument [Line Items]

Interest rate swap settlement

$ 29,000

Notional amount

400,000

$ 400,000

Source Gas

Debt Instrument [Line Items]

Repayment of debt

$ 760,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

$ 760,000

Senior Unsecured Notes Due 2017 | Source Gas

Debt Instrument [Line Items]

Interest rate (percent)

5.90%

5.90%

Repayment of debt

$ 325,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

$ 325,000

Senior Secured Notes Due 2019 | Source Gas

Debt Instrument [Line Items]

Interest rate (percent)

3.98%

3.98%

Repayment of debt

$ 95,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

$ 95,000

Corporate Term Loan Due June 2017 | Source Gas

Debt Instrument [Line Items]

Repayment of debt

100,000

$ 240,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

$ 340,000

Corporate, Non-Segment | Corporate Term Loan Due August 2019

Debt Instrument [Line Items]

Proceeds from senior unsecured notes

500,000

Debt Instrument, Term

3 years

Repayment of debt

100,000

Corporate, Non-Segment | Corporate Term Loan Due April 2017

Debt Instrument [Line Items]

Repayment of debt

$ 260,000

Black Hills Corporation

Debt Instrument [Line Items]

Proceeds from senior unsecured notes

700,000

550,000

Long-term debt

$ 2,592,664

2,698,406

Black Hills Corporation | Corporate Term Loan Due August 2019

Debt Instrument [Line Items]

Long-term debt

500,000

Debt Instrument, Term

3 years

Repayment of debt

$ 50,000

$ 50,000

Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027

Debt Instrument [Line Items]

Long-term debt

$ 400,000

$ 400,000

400,000

Interest rate (percent)

3.15%

3.15%

Debt Instrument, Term

10 years

10 years

Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046

Debt Instrument [Line Items]

Long-term debt

$ 300,000

$ 300,000

300,000

Interest rate (percent)

4.20%

4.20%

Debt Instrument, Term

30 years

Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021

Debt Instrument [Line Items]

Long-term debt

$ 18,664

24,406

$ 29,000

Interest rate (percent)

2.32%

2.32%

Frequency of periodic payment

quarterly

Periodic payment

$ 1,600

Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026

Debt Instrument [Line Items]

Long-term debt

$ 300,000

$ 300,000

300,000

Interest rate (percent)

3.95%

3.95%

Debt Instrument, Term

10 years

Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2019

Debt Instrument [Line Items]

Long-term debt

$ 250,000

$ 250,000

$ 250,000

Interest rate (percent)

2.50%

2.50%

Debt Instrument, Term

3 years

Long-Term Debt_ Deferred Financ

Long-Term Debt: Deferred Financing Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	$ 18,478
Amortization expense for deferred financing costs	3,349	$ 3,861	$ 5,617
Senior Unsecured Notes Due 2023
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,427
Amortization expense for deferred financing costs	494	494	494
Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	59
Amortization expense for deferred financing costs	704	643	0
Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	425
Amortization expense for deferred financing costs	167	167	167
Senior Unsecured Notes Due 2026
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,031
Amortization expense for deferred financing costs	287	262	0
Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	2,918
Amortization expense for deferred financing costs	363	121	0
Senior Unsecured Notes Due 2046
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	3,082
Amortization expense for deferred financing costs	111	37	0
Corporate Term Loan Due August 2019
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	86
Amortization expense for deferred financing costs	201	144	0
Bridge Term Loan
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	0
Amortization expense for deferred financing costs	0	843	4,213
Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,326
Amortization expense for deferred financing costs	122	122	10
First Mortgage Bonds Due 2044 | South Dakota Electric
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	639
Amortization expense for deferred financing costs	24	24	24
First Mortgage Bonds Due 2044 | Wyoming Electric
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	591
Amortization expense for deferred financing costs	22	23	22
First Mortgage Bonds Due 2032
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	485
Amortization expense for deferred financing costs	33	33	33
First Mortgage Bonds Due 2039
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,657
Amortization expense for deferred financing costs	76	76	76
First Mortgage Bonds Due 2037
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	613
Amortization expense for deferred financing costs	31	31	31
Deferred Financing Costs, Other
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	436
Amortization expense for deferred financing costs	76	304	43
Revolving Credit Facility
Debt Instrument [Line Items]
Deferred Finance Costs Remaining, Noncurrent	1,703
Amortization expense for deferred financing costs	$ 638	$ 537	$ 504

Long-Term Debt_ Dividend Restri

Long-Term Debt: Dividend Restrictions (Details) $ in Millions	Dec. 31, 2017USD ($)
Utilities Group
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$ 257

Notes Payable (Details)

Notes Payable (Details)	Aug. 09, 2016USD ($)credit_extension	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 22, 2016USD ($)	Jun. 30, 2016USD ($)
Short-term Debt [Line Items]
Notes payable		$ 211,300,000	$ 96,600,000
Maximum
Debt Covenants [Abstract]
Debt Instrument, Consolidated Indebtedness To Capitalization Ratio Requirement For The Next Fiscal Year		0.65
Commercial Paper
Short-term Debt [Line Items]
Notes payable		$ 211,300,000	0
Debt Instrument, Unused Borrowing Capacity, Amount		$ 750,000,000		$ 750,000,000
Debt, Weighted Average Interest Rate		1.76%
Commercial Paper | Maximum
Short-term Debt [Line Items]
Debt Instrument, Term		397 days
Revolving Credit Facility
Short-term Debt [Line Items]
Notes payable		$ 0	96,600,000
Line of Credit Facility, Current Borrowing Capacity	$ 750,000,000				$ 500,000,000
Number Of One-Year Extension Options | credit_extension	2
Debt Instrument, Term	1 year
Line of Credit Facility, Maximum Borrowing Capacity		$ 1,000,000,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.20%
Letters of Credit Outstanding, Amount		$ 27,000,000	$ 36,000,000
Debt Issuance Cost, Gross, Noncurrent		$ 5,400,000
Debt Covenants [Abstract]
Recourse Leverage Ratio		61.00%
Debt Instrument, Consolidated Indebtedness to Capitalization Ratio		0.65
Revolving Credit Facility | Base Rate
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End		0.25%
Revolving Credit Facility | Eurodollar
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End		1.25%
Revolving Credit Facility | Letter of Credit
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End		1.25%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 46,876	$ 23,231
Liabilities Incurred	0	0
Liabilities Settled	(111)	(105)
Accretion	2,061	1,804
Liabilities Acquired	0	22,412
Revisions to Prior Estimates	3,198	(466)
Ending Balance	52,024	46,876
Electric Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	4,661	4,462
Liabilities Incurred	0	0
Liabilities Settled	(4)	0
Accretion	268	191
Liabilities Acquired	0	0
Revisions to Prior Estimates	1,362	8
Ending Balance	6,287	4,661
Gas Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	29,775	136
Liabilities Incurred	0	0
Liabilities Settled	0	0
Accretion	1,142	791
Liabilities Acquired	0	22,412
Revisions to Prior Estimates	2,321	6,436
Ending Balance	33,238	29,775
Retirement of gas pipelines liability	22,000
Mining
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	12,440	18,633
Liabilities Incurred	0	0
Liabilities Settled	(107)	(105)
Accretion	651	822
Liabilities Acquired	0	0
Revisions to Prior Estimates	(485)	(6,910)
Ending Balance	$ 12,499	$ 12,440
Estimated change in equipment costs (percent)	33.00%

Risk Management Activities_ Uti

Risk Management Activities: Utilities (Details) - Natural Gas, Distribution $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MMBTU	Dec. 31, 2016MMBTU
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure		2,133,000
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ 0.7
Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,330,000	14,770,000
Derivative, Remaining Maturity	36 months	48 months
Commodity Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,540,000	3,020,000
Derivative, Remaining Maturity	14 months	5 months
Basis Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	8,060,000	12,250,000
Derivative, Remaining Maturity	36 months	48 months
Fixed for Float Swaps Purchased
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,820,000	4,622,302
Derivative, Remaining Maturity	29 months	28 months
Natural Gas Physical Purchases
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	12,826,605	21,504,378
Derivative, Remaining Maturity	35 months	10 months
Cash Flow Hedging
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	1,650,000

Risk Management Activities_ Fin

Risk Management Activities: Financing Activities (Details) - USD ($) $ in Thousands	Aug. 19, 2016	Aug. 10, 2016	Aug. 09, 2016	Jan. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 31, 2016
Derivative [Line Items]
Derivative Instruments, Loss Recognized in Other Comprehensive Income (Loss), Effective Portion		$ 28,000
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net					$ (75)	$ (953)	$ 0
Derivative assets, non-current					0	222
Derivative Liability, Current					2,081	1,104
Revolving Credit Facility
Derivative [Line Items]
Debt Instrument, Term			1 year
Black Hills Corporation
Derivative [Line Items]
Long-term debt					$ 2,592,664	2,698,406
Corporate Term Loan Due August 2019 | Black Hills Corporation
Derivative [Line Items]
Long-term debt	$ 500,000
Debt Instrument, Term			3 years
Corporate, Non-Segment
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net						1,000
Corporate, Non-Segment | Senior Unsecured Notes Due 2027 | Black Hills Corporation
Derivative [Line Items]
Long-term debt	$ 400,000	$ 400,000				400,000
Debt Instrument, Term	10 years	10 years
Corporate, Non-Segment | Corporate Term Loan Due August 2019
Derivative [Line Items]
Debt Instrument, Term			3 years
Interest Rate Swap
Derivative [Line Items]
Derivative, Notional Amount	$ 400,000							$ 400,000
Derivative, Loss on Derivative		$ 29,000
Interest Rate Swap | Revolving Credit Facility | Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Notional Amount						$ 50,000
Derivative, Average Fixed Interest Rate						4.94%
Derivative, Remaining Maturity						1 month
Derivative assets, non-current						$ 0
Derivative Liability, Current						90
Derivative liabilities, non-current						$ 0
Interest Rate Swap | Corporate Term Loan Due August 2019 | Designated as Hedging Instrument
Derivative [Line Items]
Derivative Expired During the Period				$ 50,000

Risk Management Activities_ Dis

Risk Management Activities: Discontinued Operations (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016bblMMBTU
Crude Oil | Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		108,000
Crude Oil | Options Held
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		36,000
Natural Gas | Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | MMBTU		2,700,000
Sales Revenue, Net
Derivative [Line Items]
Price Risk Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net | $	$ 0.3

Risk Management Activities_ Cas

Risk Management Activities: Cash Flow Hedges (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	$ (75)	$ (953)	$ 0
Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2,271)	7,106	10,813
Designated as Hedging Instrument | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	2,637	(38,901)	1,857
Interest Rate Swap | Designated as Hedging Instrument | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	0	(31,222)	2,888
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2,941	3,899	3,647
Interest Rate Swap | Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	(953)	0
Interest Rate Swap | Interest Expense | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2,941)	(3,899)	(3,647)
Commodity Contract | Designated as Hedging Instrument | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Other Comprehensive Income (Loss), Effective Portion, Net	366	(573)	9,782
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(670)	(11,005)	(14,460)
Commodity Contract | Discontinued Operations, Held-for-sale or Disposed of by Sale
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	0
Commodity Contract | Discontinued Operations, Held-for-sale or Disposed of by Sale | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	913	11,019	$ 14,460
Commodity Contract | Fuel, purchased power and cost of natural gas sold
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	(75)	0
Commodity Contract | Fuel, purchased power and cost of natural gas sold | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (243)	$ (14)

Risk Management Activities_ Der

Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory assets	$ 297,454	$ 296,142
Price Risk Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory assets	11,935	8,843
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(2,207)	890	$ 0
Discontinued Operations, Held-for-sale or Disposed of by Sale | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	(50)	0
Fuel, purchased power and cost of natural gas sold | Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (2,207)	$ 940	$ 0

Schedule of Fair Values (Detail

Schedule of Fair Values (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	$ 304	$ 4,207
Derivative, Liabilities, Fair Value Disclosure	2,259	1,147
Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,282)	(3,262)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,497)	(11,144)
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0
Derivative Liabilities, Total	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	1,586	7,469
Derivative Liabilities, Total	13,756	12,291
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	0	0
Derivative Liabilities, Total	0	0
Fair Value | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	304	4,207
Derivative Liabilities, Total	2,259	1,147
Commodity Contract | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Liability and Obligation to Return Cash, Offset	(1,282)	(3,262)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(11,497)	(11,144)
Commodity Contract | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Commodity Contract | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	1,586	7,469
Derivative, Liabilities, Fair Value Disclosure	13,756	12,201
Commodity Contract | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Commodity Contract | Fair Value | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	304	4,207
Derivative, Liabilities, Fair Value Disclosure	$ 2,259	1,057
Interest Rate Swap | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure		90
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset		0
Interest Rate Swap | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure		0
Interest Rate Swap | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure		90
Interest Rate Swap | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative, Liabilities, Fair Value Disclosure		$ 0

Fair Value Measurements_ Balanc

Fair Value Measurements: Balance Sheet Location (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 1,586	$ 7,469
Derivative Liability, Fair Value, Gross Liability	13,756	12,291
Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	0	1,285
Derivative Liability, Fair Value, Net	884	1,418
Not Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Net	304	3,075
Derivative Liability, Fair Value, Net	1,375	1,315
Commodity derivatives | Designated as Hedging Instrument | Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	1,007
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives | Designated as Hedging Instrument | Derivative Assets, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	124
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives | Designated as Hedging Instrument | Current Assets Held For Sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	154
Derivative Asset, Fair Value, Gross Liability	0
Commodity derivatives | Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	817	0
Commodity derivatives | Designated as Hedging Instrument | Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	67	7
Commodity derivatives | Designated as Hedging Instrument | Current Liabilities Held For Sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	1,090
Commodity derivatives | Designated as Hedging Instrument | Noncurrent Liabilities Held For Sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	231
Commodity derivatives | Not Designated as Hedging Instrument | Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	304	2,977
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives | Not Designated as Hedging Instrument | Derivative Assets, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	98
Derivative Asset, Fair Value, Gross Liability	0	0
Commodity derivatives | Not Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	1,264	1,014
Commodity derivatives | Not Designated as Hedging Instrument | Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	111	36
Commodity derivatives | Not Designated as Hedging Instrument | Current Liabilities Held For Sale
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	0	265
Interest Rate Swap | Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative Liability, Fair Value, Gross Liability	$ 0	$ 90

Fair Value Measurements_ Bala90

Fair Value Measurements: Balance Sheet Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 1,586	$ 7,469
Gross Amounts Offset In Statement Of Financial Position Assets	(1,282)	(3,262)
Derivative Asset	304	4,207
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	13,756	12,291
Gross Amounts Offset In Statement Of Financial Position Liabilities	(11,497)	(11,144)
Derivative Liability	2,259	1,147
Contract Subject to Master Netting Arrangement
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	1,282	4,269
Gross Amounts Offset In Statement Of Financial Position Assets	(1,282)	(3,262)
Derivative Asset	0	1,007
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	11,497	11,144
Gross Amounts Offset In Statement Of Financial Position Liabilities	(11,497)	(11,144)
Derivative Liability	0	0
Contract Not Subject to Master Netting Arrangement
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	304	3,200
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	304	3,200
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	2,259	1,147
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	2,259	1,147
Contract Not Subject to Master Netting Arrangement | Interest Rate Swap
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability		90
Gross Amounts Offset In Statement Of Financial Position Liabilities		0
Derivative Liability		90
Natural Gas, Distribution | Contract Subject to Master Netting Arrangement | Purchase Contract
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	1,282	4,269
Gross Amounts Offset In Statement Of Financial Position Assets	(1,282)	(3,262)
Derivative Asset	0	1,007
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	11,497	11,144
Gross Amounts Offset In Statement Of Financial Position Liabilities	(11,497)	(11,144)
Derivative Liability	0	0
Natural Gas, Distribution | Contract Not Subject to Master Netting Arrangement | Purchase Contract
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	304	3,200
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	304	3,200
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	2,259	1,057
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	$ 2,259	$ 1,057

Fair Value of Financial Instr91

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	$ 15,420	$ 13,518
Restricted cash - carrying amount	2,820	2,274
Notes payable	211,300	96,600
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	15,420	13,518
Restricted cash - carrying amount	2,820	2,274
Notes payable	211,300	96,600
Long-term debt, including current maturities - carrying amount	3,115,143	3,216,932
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - fair value	15,420	13,518
Restricted Cash - fair value	2,820	2,274
Notes payable - fair value	211,300	96,600
Long-term debt, including current maturities - fair value	$ 3,350,544	$ 3,351,305

Equity Units (Details)

Equity Units (Details) $ / shares in Units, shares in Thousands	Nov. 23, 2015USD ($)shares$ / shares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Proceeds from Sale of Interest in Corporate Unit	$ 299,000,000
Equity Unit Stated Amount (usd per share) | $ / shares	$ 50
Corporate Units Ownership Interest Percentage In Subordinated Notes	5.00%
Debt Instrument, Subordinated Notes, Stated Principal Amount	$ 1,000
Debt Instrument, Convertible, Threshold Consecutive Trading Days	20 days
Debt Instrument, Convertible, Reference Price (usd per share) | $ / shares	$ 40.25
Stock Purchase Contract Rate	4.25%
Equity Unit, Annual Dividend Amount (usd per share) | $ / shares	$ 2.125
Premium on Publicly-Traded Equity Units Known As Corporate Units	$ 33,000,000			$ 33,118,000
Equity units - issuance	290,030,000	$ 0	$ 0	$ 290,030,000
Stock Purchase Contract Liability	$ 12,115,000
Black Hills Corporation
Debt Instrument [Line Items]
Long-term debt		$ 2,592,664,000	2,698,406,000
Minimum
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio	1.0572
Maximum
Debt Instrument [Line Items]
Debt Instrument, Convertible, Conversion Ratio	1.2422
Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Issuance of equity units | shares	5,980
Debt Instrument, Convertible, Conversion Price (usd per share) | $ / shares	$ 47.2938
Remarketable Junior Subordinated Notes Due 2028 | Black Hills Corporation
Debt Instrument [Line Items]
RSN Interest Rate (percent)	3.50%	3.50%
Long-term debt	$ 299,000,000	$ 299,000,000	$ 299,000,000

Equity_ At-the-Market Equity Of

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Aug. 04, 2017	Jun. 30, 2016
At The Market Equity Offering Program Authorized Aggregate Value			$ 300	$ 200
Common Stock
At The Market Equity Offering Program Shares Issued	218,647	1,968,738
At The Market Equity Program Proceeds from Sale of Stock	$ 13	$ 119
Payments of Stock Issuance Costs	$ 0.1	$ 1.2

Equity_ Common Stock Offering (

Equity: Common Stock Offering (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 23, 2015	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Issuance of common stock		$ 119,990	$ 254,581
Common Stock
Class of Stock [Line Items]
Issuance of common stock, shares	6,325,000	1,968,738	6,325,000
Shares issued, price (usd per share)	$ 40.25
Issuance of common stock	$ 246,000	$ 1,969	$ 6,325

Equity_ Equity Compensation Pla

Equity: Equity Compensation Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stockholders' Equity Note [Abstract]
Shares available for grant	979,464
Unrecognized compensation expense	$ 12,000
Weighted-average recognition period	1 year 11 months
Stock-based compensation expense	$ 7,626	$ 10,885	$ 4,076

Equity_ Stock Options (Details)

Equity: Stock Options (Details)	Dec. 31, 2017shares
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares exercisable at end of period	96,749

Equity_ Restricted Stock (Detai

Equity: Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value
Unrecognized compensation expense	$ 12,000
Weighted-average recognition period	1 year 11 months
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award vesting period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested Number of Shares [Roll Forward]
Restricted Stock balance at beginning of period	295
Shares Granted	111
Shares Vested	(128)
Shares Forfeited	(11)
Restricted Stock at end of period	267	295
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value
Balance at beginning of period (usd per share)	$ 52.15
Granted (usd per share)	60.63	$ 53.55	$ 50.01
Vested (usd per share)	51.44
Forfeited (usd per share)	53.80
Balance at end of period (usd per share)	$ 55.94	$ 52.15
Restricted Stock and RSUs, total fair value of shares vested	$ 7,909	$ 4,602	$ 6,009
Unrecognized compensation expense	$ 9,900
Weighted-average recognition period	2 years

Equity_ Performance Share Plan

Equity: Performance Share Plan (Details) - USD ($) $ / shares in Units, shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense	$ 12,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Weighted-average recognition period	1 year 11 months
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award Payout, Cash Percentage	50.00%
Performance Share Award Payout, Shares of Common Stock Percentage	50.00%
Performance Share Award, Payout, Change Of Control	100.00%
Unrecognized compensation expense	$ 2,500,000
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	53	43
Performance Shares, Number of Shares Authorized, End of Period	51	53	43
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Granted (usd per share)		$ 47.76	$ 54.92
Blended volatility	23.00%	24.00%	21.00%
Historical volatility	50.00%
Implied volatility	50.00%
Performance Shares Issued During Period, Shares, Treasury Stock Reissued	0	0	69
Performance Shares, Total Share-based Liabilities Paid	$ 0	$ 0	$ 3,657,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Fair Value	0	$ 0	$ 7,314,000
Target shares, value	0
Unrecognized compensation expense	$ 2,100,000
Weighted-average recognition period	1 year 7 months
Performance Shares, Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	71
Performance Shares, Granted in Period	26
Performance Shares, Forfeited in Period	(1)
Performance Shares, Vested in Period	(22)
Performance Shares, Number of Shares Authorized, End of Period	74	71
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at beginning of period (usd per share)	$ 52.29
Granted (usd per share)	63.52
Forfeited (usd per share)	55.01
Vested (usd per share)	55.18
Balance at end of period (usd per share)	$ 55.31	$ 52.29
Performance Shares, Liability Awards
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outsanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	71
Performance Shares, Granted in Period	26
Performance Shares, Forfeited in Period	(1)
Performance Shares, Vested in Period	(22)
Performance Shares, Number of Shares Authorized, End of Period	74	71
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at end of period (usd per share)	$ 22.31
Minimum | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	0.00%	0.00%	0.00%
Maximum | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	200.00%	200.00%	200.00%

Equity_ Dividend Reinvestment a

Equity: Dividend Reinvestment and Stock Purchase Plan (Details) - Dividend Reinvestment Plan - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Percent of recent average market price	100.00%
Shares Issued	48	51
Weighted Average Price (usd per share)	$ 65.40	$ 58.24
Unissued Shares Available	308	356

Equity_ Preferred Stock (Detail

Equity: Preferred Stock (Details)	Dec. 31, 2017shares
Stockholders' Equity Note [Abstract]
Preferred Stock, Shares Authorized	25,000,000
Preferred Stock, Shares Outstanding	0

Equity_ Noncontrolling Interest

Equity: Noncontrolling Interest in Subsidiary (Details) $ in Thousands	Apr. 14, 2016USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Electric Generation Capacity, Megawatts | MW										200
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Proceeds from Noncontrolling Interests	$ 216,000									$ 0	$ 216,370	$ 0
Number of Days the Company has to Pay Distributions of Net Income Attributable to Noncontrolling Interests										30 days
Net income attributable to noncontrolling interest		$ (3,568)	$ (3,935)	$ (3,116)	$ (3,623)	$ (3,246)	$ (3,753)	$ (2,614)	$ (48)	$ (14,242)	(9,661)	0
Power Generation
Net income attributable to noncontrolling interest										(14,135)	(9,559)	$ 0
Current assets
Assets		14,837				12,627				14,837	12,627
Property, plant and equipment of variable interest entities, net
Assets		208,595				218,798				208,595	218,798
Current liabilities
Liabilities		$ 4,565				$ 4,342				$ 4,565	$ 4,342

Regulatory Matters_ Electric Ut

Regulatory Matters: Electric Utilities Rate Activity (Details) $ in Thousands	Jan. 01, 2018USD ($)	Jul. 01, 2017USD ($)	Jun. 16, 2017USD ($)	Dec. 19, 2016USD ($)MW	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 29, 2016	Dec. 31, 2016USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory assets						$ 297,454		$ 296,142
South Dakota Public Utilities Commission (SDPUC) | South Dakota Electric
Public Utilities, General Disclosures [Line Items]
Public Utilities, Suspension Of Rate Increase Due to a Moratorium by State Regulators			$ 1,000
Public Utilities, Increase in Amortization Expense Due to Change in Amortization Periods		$ 2,700
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 0
Colorado Public Utilities Commission (CPUC) | Colorado Electric
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Percentage							7.40%
Public Utilities, Approved Return on Equity, Percentage							9.37%
Public Utilities, Approved Debt Capital Structure, Percentage							47.60%
Public Utilities, Approved Equity Capital Structure, Percentage							52.40%
Environmental Restoration Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets						13,287		16,859
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC)
Public Utilities, General Disclosures [Line Items]
Public Utilities, Moratorium Period		6 years
Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC) | South Dakota Electric
Public Utilities, General Disclosures [Line Items]
Regulatory assets						13,000
Other regulatory assets
Public Utilities, General Disclosures [Line Items]
Regulatory assets						32,837		$ 24,189
Other regulatory assets | South Dakota Public Utilities Commission (SDPUC)
Public Utilities, General Disclosures [Line Items]
Public Utilities, Moratorium Period		6 years
Other regulatory assets | South Dakota Public Utilities Commission (SDPUC) | South Dakota Electric
Public Utilities, General Disclosures [Line Items]
Regulatory assets						$ 14,000
Scenario, Previously Reported | Environmental Restoration Costs | South Dakota Public Utilities Commission (SDPUC)
Public Utilities, General Disclosures [Line Items]
Regulatory Asset, Amortization Period						10 years
Scenario, Previously Reported | Other regulatory assets | South Dakota Public Utilities Commission (SDPUC)
Public Utilities, General Disclosures [Line Items]
Regulatory Asset, Amortization Period						10 years
40 MW Natural Gas-fired Combustion Turbine | Colorado Public Utilities Commission (CPUC) | Colorado Electric
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 1,200
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment				$ 63,000
Utility Plant, Megawatt Capacity | MW				40
Public Utilities, Approved Rate Increase (Decrease), Percentage							6.02%
Public Utilities, Approved Return on Equity, Percentage							9.37%
Public Utilities, Approved Debt Capital Structure, Percentage							67.34%
Public Utilities, Approved Equity Capital Structure, Percentage							32.66%
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 8,900
40 MW Natural Gas-fired Combustion Turbine | Clean Air Clean Jobs Act Construction Financing Rider | Colorado Public Utilities Commission (CPUC) | Colorado Electric
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 5,900
Subsequent Event | Federal Energy Regulatory Commission (FERC) Common Use System (CUS) | South Dakota Electric
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement, as Required by the FERC Joint-Access Transmission Tariff	$ 3,300
Capital Addition Requirements by the FERC Joint-Access Transmission Tariff	$ 45,000
Weighted Average | Federal Energy Regulatory Commission (FERC) Common Use System (CUS) | South Dakota Electric
Public Utilities, General Disclosures [Line Items]
Capital Addition Requirements by the FERC Joint-Access Transmission Tariff						$ 45,000
Weighted Average | Subsequent Event | Federal Energy Regulatory Commission (FERC) Common Use System (CUS) | South Dakota Electric
Public Utilities, General Disclosures [Line Items]
Capital Addition Requirements by the FERC Joint-Access Transmission Tariff					$ 45,000

Regulatory Matters_ Gas Utiliti

Regulatory Matters: Gas Utilities Rate Activity (Details) $ in Millions	Feb. 01, 2018USD ($)	Dec. 15, 2017USD ($)mi	Nov. 17, 2017USD ($)mi	Nov. 16, 2017USD ($)	Oct. 03, 2017USD ($)	Feb. 01, 2016USD ($)	Jan. 28, 2016	Dec. 31, 2017USD ($)
Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 30
Public Utilities, Approved Return on Equity, Percentage		10.20%
Public Utilities, Approved Debt Capital Structure, Percentage		45.30%					52.00%
Public Utilities, Approved Equity Capital Structure, Percentage		54.70%					48.00%
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment		$ 160
Length Of Natural Gas Pipeline Replace, Upgrade and Maintain | mi		5,500
Public Utilities, Approved Rate Increase (Decrease), Amount						$ 8
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Gas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 1.4
Public Utilities, Approved Return on Equity, Percentage			10.20%
Public Utilities, Approved Debt Capital Structure, Percentage			46.00%
Public Utilities, Approved Equity Capital Structure, Percentage			54.00%
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment			$ 6
Length Of Natural Gas Pipeline Replace, Upgrade and Maintain | mi			620
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Rocky Mountain Natural Gas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Return on Equity, Percentage					12.25%
Public Utilities, Approved Debt Capital Structure, Percentage					53.37%
Public Utilities, Approved Equity Capital Structure, Percentage					46.63%
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment								$ 3.1
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 2.2			$ 0.2
Stockton Storage Revenue Requirement | Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 3.3
Subsequent Event | Nebraska Public Service Commission (NPSC) | Black Hills Energy, Nebraska Gas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment	$ 6.8
Public Utilities, Approved Rate Increase (Decrease), Amount	0.3
Subsequent Event | Main Replacement Program (MRP) | Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	2.8
Subsequent Event | At-Risk Meter Relocation Program (ARMRP) | Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 0.5

Operating Leases (Details)

Operating Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Leases, Rent Expense, Net [Abstract]
Rent expense	$ 10,325	$ 9,568	$ 7,177
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	5,030
2,019	3,840
2,020	1,957
2,021	918
2,022	808
Thereafter	$ 3,085

Income Taxes_ Tax Cut and Jobs

Income Taxes: Tax Cut and Jobs Act (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit)	$ 309
Deferred Income Tax Charge
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Provisional Income Tax Expense (Benefit)	$ 301

Income Taxes_ Current and Defer

Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Current:
Federal	$ (6,193)	$ (21,806)	$ 2,624
State	(1,432)	(1,797)	1,329
Total Current	(7,625)	(23,603)	3,953
Deferred:
Federal	76,567	78,997	71,332
State	4,470	3,759	3,485
Tax credit amortization	(45)	(52)	(113)
Total Deferred	80,992	82,704	74,704
Total Current and Deferred	73,367	59,101	78,657
Discontinued Operation, Tax Effect of Discontinued Operation	$ (8,413)	$ (48,626)	$ (100,817)

Income Taxes_ Deferred Income T

Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Deferred Tax Assets, Net [Abstract]
Regulatory liabilities	$ 90,742	$ 58,200
Employee benefits	18,724	28,873
Federal net operating loss	155,276	252,780
Other deferred tax assets	74,561	83,675
Less: Valuation allowance	(9,121)	(9,263)
Total deferred tax assets	330,182	414,265
Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(510,774)	(782,674)
Regulatory assets	(26,245)	(49,471)
Deferred Tax Liabilities, Goodwill	(46,392)	(60,544)
State deferred tax liability	(58,930)	(50,258)
Deferred costs	(16,063)	(18,551)
Other deferred tax liabilities	(8,298)	(14,702)
Total deferred tax liabilities	(666,702)	(976,200)
Net deferred tax liability	336,520	$ 561,935
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Provisional Income Tax Expense (Benefit)	309,000
Deferred Income Tax Charge
Tax Cuts and Jobs Act of 2017, Incomplete Accounting, Change in Tax Rate, Provisional Income Tax Expense (Benefit)	$ 301,000

Income Taxes_ Effective Tax Rat

Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Federal Statutory Rate	35.00%	35.00%	35.00%
State income tax (net of federal tax effect)	0.90%	1.20%	1.50%
Percentage depletion	(0.60%)	(0.80%)	(0.70%)
Non-controlling interest	(1.80%)	(1.60%)	(0.00%)
Equity AFUDC	(0.20%)	(0.50%)	(0.10%)
Tax credits	(1.70%)	(0.40%)	(0.10%)
Transaction costs	0.00%	0.50%	0.00%
Accounting for uncertain tax positions adjustment	(0.20%)	(2.70%)	0.80%
Flow-through adjustments	(1.10%)	(2.10%)	(1.00%)
Other tax differences	(0.90%)	0.10%	0.30%
Effective Income Tax Reconciliation Net Operating Loss Carryback	(0.70%)	0.00%	0.00%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	(2.70%)	0.00%	0.00%
Effective Income Tax Rate, Continuing Operations	26.00%	28.70%	35.70%

Income Taxes_ Net Operating Los

Income Taxes: Net Operating Loss Carryforwards (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 739,184
Internal Revenue Service (IRS) | Minimum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2019
Internal Revenue Service (IRS) | Maximum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2037
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 688,335
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Valuation Allowance	1,300
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 400
State and Local Jurisdiction | Minimum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2017
State and Local Jurisdiction | Maximum
Operating Loss Carryforwards [Line Items]
Expiration Dates	Dec. 31, 2038

Income Taxes_ Reconciliation of

Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 3,592	$ 31,986	$ 32,192
Additions for prior year tax positions	358	2,423	3,285
Reductions for prior year tax positions	(5,713)	(19,174)	(3,491)
Additions for current year tax positions	5,026	0	0
Settlements	0	(11,643)	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	3,263	$ 3,592	$ 31,986
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 200

Income Taxes_ Interest, Penalti

Income Taxes: Interest, Penalties and Audits (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Examination [Line Items]
Unrecognized Tax Benefits - Interest Expense	$ 0	$ 0	$ 1,600,000
Accrued interest (before tax effect) associated with income taxes	0	0
Deferred Income Tax Expense (Benefit)	80,992,000	82,704,000	74,704,000
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	0	$ 11,643,000	$ 0
Like-Kind Exchange, Aquila and IPP Transactions
Income Tax Examination [Line Items]
Deferred Income Tax Expense (Benefit)	125,000,000
Unrecognized Tax Benefits, Decrease Resulting from Settlements with Taxing Authorities	29,000,000
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities, Affecting Accumulated Deferred Income Taxes	17,000,000
Unrecognized Tax Benefits, Decreases Resulting from Settlements with Taxing Authorities, Affecting Current Taxes Payable	$ 12,000,000

Income Taxes_ Carryforwards, St

Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Tax Credit Carryforward [Line Items]
Income Tax Expense (Benefit)	$ 73,367	$ 59,101	$ 78,657
State and Local Jurisdiction
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	7,800
State and Local Jurisdiction | Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	20,285
State and Local Jurisdiction | Research Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	179
State and Local Jurisdiction | Deferred Tax Asset [Domain]
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	1,200
Income Tax Expense (Benefit)	600
State and Local Jurisdiction | Deferred Tax Asset [Domain] | Utilities Group
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 600
State and Local Jurisdiction | Minimum | Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2023
State and Local Jurisdiction | Maximum | Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Expiration Date	Dec. 31, 2036
Valuation Allowance, Operating Loss Carryforwards | State and Local Jurisdiction
Tax Credit Carryforward [Line Items]
Valuation Allowance, Deferred Tax Asset, Change in Amount	$ 400

Comprehensive Income (Loss) (De

Comprehensive Income (Loss) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense									$ 140,756	$ 139,447	$ 86,226
Revenue	$ 455,298	$ 335,611	$ 341,829	$ 547,528	$ 455,390	$ 324,147	$ 317,795	$ 441,584	1,680,266	1,538,916	1,261,322
Fuel, purchased power and cost of natural gas sold									563,288	499,132	456,887
Income before income taxes									281,742	205,894	220,205
Income tax benefit (expense)									(73,367)	(59,101)	(78,657)
Net income (loss)									191,276	82,631	$ (32,111)
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income (loss)									(3,372)	3,180
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income before income taxes									(2,271)	7,106
Net income (loss)									(1,396)	4,404
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income before income taxes									(1,460)	(1,757)
Net income (loss)									(1,976)	(1,224)
Interest Expense | Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Contract
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense									(2,941)	(3,899)
Fuel, purchased power and cost of natural gas sold | Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Fuel, purchased power and cost of natural gas sold									(243)	(14)
Operating Expense | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance									168	194
Operating Expense | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance									(1,599)	(1,881)
Discontinued Operations | Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenue									913	11,019
Discontinued Operations | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost (Credit) | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance									29	27
Discontinued Operations | Accumulated Defined Benefit Plans Adjustment, Net Unamortized Gain (Loss) | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance									(58)	(97)
Income Tax Benefit (Expense) | Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income tax benefit (expense)									875	(2,702)
Income Tax Benefit (Expense) | Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income tax benefit (expense)									$ (516)	$ 533

Other Comprehensive Income_ Acc

Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (34,883)	$ (9,055)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(41,202)	(34,883)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(16,541)	(15,780)
before reclassifications	(1,890)	(1,985)
Reclassification of certain tax effects from AOCI	(3,616)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(21,103)	(16,541)
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Amounts reclassified from AOCI	944	1,224
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
before reclassifications	(1,659)	(22,648)
Reclassification of certain tax effects from AOCI	(7,000)
Accumulated Other Comprehensive Income (Loss) | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Amounts reclassified from AOCI	2,340	(3,180)
Interest Rate Swap | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(18,109)	(341)
before reclassifications	0	(20,302)
Reclassification of certain tax effects from AOCI	(3,384)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(19,581)	(18,109)
Interest Rate Swap | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Amounts reclassified from AOCI	1,912	2,534
Commodity Contract | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(233)	7,066
before reclassifications	231	(361)
Reclassification of certain tax effects from AOCI	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(518)	(233)
Commodity Contract | Accumulated Net Gain (Loss) fromDesignated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Amounts reclassified from AOCI	$ (516)	$ (6,938)

Supplemental Cash Flow Infor115

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Non-cash investing activities and financing from continuing operations -
Property, plant and equipment acquired with accrued liabilities	$ 28,191	$ 27,034	$ 25,039
Increase (decrease) in capitalized assets associated with asset retirement obligations	3,198	8,577	(1,498)
Cash (paid) refunded during the period for continuing operations-
Interest (net of amount capitalized)	(132,428)	(113,627)	(78,744)
Income taxes (paid) refunded	$ 1,775	$ (1,156)	$ (1,202)

Employee Benefit Plans_ Narrati

Employee Benefit Plans: Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Contribution Plan [Abstract]
Maximum Annual Contribution Per Employee, Percent	50.00%
Employers Matching Contribution, Annual Vesting Percentage	20.00%
Employee Vesting Period	5 years
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Equity Securities
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	26.00%	28.00%
Fixed Income Funds
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	63.00%	57.00%
Maximum
Defined Contribution Plan [Abstract]
Employers Matching Contribution, Annual Vesting Percentage	100.00%
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation, Business Combination	$ 0	$ 75,254
Defined Contribution Plan [Abstract]
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year	6.25%	6.75%
Pension Plans, Defined Benefit | Minimum | Equity Securities
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	37.00%
Pension Plans, Defined Benefit | Minimum | Fixed Income Funds
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	55.00%
Pension Plans, Defined Benefit | Maximum | Equity Securities
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	45.00%
Pension Plans, Defined Benefit | Maximum | Fixed Income Funds
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	63.00%
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Benefit Obligation, Business Combination	$ 0	$ 15,091
Other Postretirement Benefit Plans, Defined Benefit | Minimum | Equity Securities
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	15.00%
Other Postretirement Benefit Plans, Defined Benefit | Minimum | Fixed Income Funds
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	75.00%
Other Postretirement Benefit Plans, Defined Benefit | Maximum | Equity Securities
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	25.00%
Other Postretirement Benefit Plans, Defined Benefit | Maximum | Fixed Income Funds
Defined Contribution Plan [Abstract]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	85.00%

Employee Benefit Plans_ Target

Employee Benefit Plans: Target Plan Assets Allocation (Details)	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	100.00%	100.00%
Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	26.00%	28.00%
Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	4.00%	5.00%
Fixed Income Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	63.00%	57.00%
Cash and Cash Equivalents
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	1.00%	2.00%
Hedge Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	6.00%	8.00%

Employee Benefit Plans_ Plan Co

Employee Benefit Plans: Plan Contributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 13,000
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	27,700	$ 14,200
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	4,332	4,965
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	3,217	1,565
Defined Contribution Plan, Company Retirement
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	10,223	9,632
Defined Contribution Plan, 401K
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	$ 9,811	$ 9,645

Employee Benefit Plans_ Employe

Employee Benefit Plans: Employee Benefit Plans Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	65 days
Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 416,343	$ 364,695	$ 288,622
Other Postretirement Benefit Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	8,621	8,470	$ 4,681
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	416,343	364,695
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	377,017	319,816
Alternative Investment, Fair Value Disclosure	39,326	44,879
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,280	1,325
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	1,280	1,325
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,184	5,307
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	2,184	5,307
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	109,496	101,020
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	109,496	101,020
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	262,329	209,815
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	262,329	209,815
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	17,429	17,912
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	1,728	2,349
Alternative Investment, Fair Value Disclosure	15,701	15,563
Fair Value, Measurements, Recurring | Pension Plans, Defined Benefit | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	23,625	29,316
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	0	0
Alternative Investment, Fair Value Disclosure	23,625	29,316
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	8,621	8,470
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	8,621	8,470
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,671	111
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	4,671	111
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,374	1,154
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	1,374	1,154
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		4,732
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments		4,732
Alternative Investment, Fair Value Disclosure		0
Fair Value, Measurements, Recurring | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,576	2,473
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	2,576	2,473
Alternative Investment, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Pension Plans, Defined Benefit | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	6,045	1,265
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,671	111
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,374	1,154
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	377,017	319,816
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,280	1,325
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,184	5,307
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	109,496	101,020
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	262,329	209,815
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,728	2,349
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Pension Plans, Defined Benefit | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,576	7,205
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		4,732
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,576	2,473
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Pension Plans, Defined Benefit | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | Common Collective Trust, Money Market Fund
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets		0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Other Postretirement Benefit Plans, Defined Benefit | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 0	$ 0

Employee Benefit Plans_ Changes

Employee Benefit Plans: Changes in Benefit Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	$ 440,179	$ 356,575
Transfer from SourceGas Acquisition	0	75,254
Service cost	7,034	7,619	$ 6,093
Interest cost	15,520	15,743	15,522
Actuarial (gain) loss	36,661	7,001
Amendments	0	0
Benefits paid	(24,669)	(22,013)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	474,725	440,179	356,575
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	43,869	40,219
Transfer from SourceGas Acquisition	0	0
Service cost	2,937	2,099
Interest cost	1,276	1,257
Actuarial (gain) loss	247	2,049
Amendments	0	0
Benefits paid	(3,217)	(1,755)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	45,112	43,869	40,219
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	68,023	48,077
Transfer from SourceGas Acquisition	0	15,091
Service cost	2,300	1,757	1,808
Interest cost	2,141	1,942	1,801
Actuarial (gain) loss	(396)	2,808
Amendments	265	2,203
Benefits paid	(4,332)	(4,965)
Plan participants’ contributions	1,338	1,110
Projected benefit obligation at end of year	$ 69,339	$ 68,023	$ 48,077

Employee Benefit Plans_ Chan121

Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning fair value of plan assets	$ 364,695	$ 288,622
Transfer from SourceGas Acquisition	0	53,067
Investment income (loss)	48,617	30,819
Employer contributions	27,700	14,200
Retiree contributions	0	0
Benefits paid	(24,669)	(22,013)
Ending fair value of plan assets	416,343	364,695
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning fair value of plan assets	0	0
Transfer from SourceGas Acquisition	0	0
Investment income (loss)	0	0
Employer contributions	3,217	1,755
Retiree contributions	0	0
Benefits paid	(3,217)	(1,755)
Ending fair value of plan assets	0	0
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning fair value of plan assets	8,470	4,681
Transfer from SourceGas Acquisition	0	3,340
Investment income (loss)	120	256
Employer contributions	3,025	4,048
Retiree contributions	1,338	1,110
Benefits paid	(4,332)	(4,965)
Ending fair value of plan assets	$ 8,621	$ 8,470

Employee Benefit Plans_ Amounts

Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	$ 297,454	$ 296,142
Non-current liabilities	159,646	173,682
Regulatory liabilities	485,126	206,756
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	72,756	66,640
Current liabilities	0	0
Non-current assets	0	0
Non-current liabilities	58,381	75,484
Regulatory liabilities	5,232	5,195
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	0	0
Current liabilities	1,372	1,583
Non-current assets	0	0
Non-current liabilities	43,739	42,286
Regulatory liabilities	0	0
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	11,507	11,401
Current liabilities	4,423	4,360
Non-current assets	69	21
Non-current liabilities	56,365	55,214
Regulatory liabilities	$ 3,334	$ 3,419

Employee Benefit Plans_ Accumul

Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$ 450,394	$ 416,786
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	41,243	32,090
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$ 69,339	$ 68,023

Employee Benefit Plans_ Compone

Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 7,034	$ 7,619	$ 6,093
Interest cost	15,520	15,743	15,522
Expected return on assets	(24,517)	(23,062)	(19,470)
Net amortization of prior service cost	58	58	58
Recognized net actuarial loss (gain)	4,007	7,173	11,037
Settlement Expense	0	10	0
Net periodic benefit expense	2,102	7,541	13,240
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,546	1,335	1,380
Interest cost	1,276	1,257	1,455
Expected return on assets	0	0	0
Net amortization of prior service cost	2	2	2
Recognized net actuarial loss (gain)	1,001	829	1,081
Settlement Expense	0	0	0
Net periodic benefit expense	3,825	3,423	3,918
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	2,300	1,757	1,808
Interest cost	2,141	1,942	1,801
Expected return on assets	(315)	(279)	(131)
Net amortization of prior service cost	(411)	(428)	(428)
Recognized net actuarial loss (gain)	499	335	408
Settlement Expense	0	0	0
Net periodic benefit expense	$ 4,214	$ 3,327	$ 3,458

Employee Benefit Plans_ Accu125

Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Pension Plans, Defined Benefit
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net (gain) loss	$ 10,056	$ 8,472
Prior service cost (gain)	21	31
Reclassification of certain tax effects from AOCI	2,087	0
Total AOCI	12,164	8,503
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	5,610
Prior service cost (credit)	38
Total net periodic benefit cost expected to be recognized during calendar year 2018	5,648
Supplemental Employee Retirement Plans, Defined Benefit
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net (gain) loss	6,639	7,132
Prior service cost (gain)	4	5
Reclassification of certain tax effects from AOCI	1,371	0
Total AOCI	8,014	7,137
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	650
Prior service cost (credit)	1
Total net periodic benefit cost expected to be recognized during calendar year 2018	651
Other Postretirement Benefit Plans, Defined Benefit
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net (gain) loss	1,309	1,595
Prior service cost (gain)	(542)	(694)
Reclassification of certain tax effects from AOCI	158	0
Total AOCI	925	$ 901
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Net loss	141
Prior service cost (credit)	(258)
Total net periodic benefit cost expected to be recognized during calendar year 2018	$ (117)

Employee Benefit Plans_ Defined

Employee Benefit Plans: Defined Benefit Plans Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rate [Abstract]
Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	$ 2,968
Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	(2,534)
Effect of One Percentage Point Increase on Service and Interest Cost Components	148
Effect of One Percentage Point Decrease on Service and Interest Cost Components	$ (126)
Healthcare trend rate pre-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Year Ultimate Trend Reached	2,027	2,024
Healthcare trend rate pre-65 | Black Hills Corporation - All Plans
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	7.00%	6.10%
Healthcare trend rate pre-65 | Black Hills Service Company
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Ultimate trend rate	4.50%	4.50%
Healthcare trend rate post-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Year Ultimate Trend Reached	2,026	2,023
Healthcare trend rate post-65 | Black Hills Corporation - All Plans
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	5.00%	5.10%
Healthcare trend rate post-65 | Black Hills Service Company
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Ultimate trend rate	4.50%	4.50%
Pension Plans, Defined Benefit
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.71%	4.27%	4.58%
Rate of Increase in Compensation Levels	3.43%	3.47%	3.51%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	6.75%	6.87%	6.75%
Rate of Compensation Increase	3.47%	3.42%	3.76%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year	6.25%	6.75%
Pension Plans, Defined Benefit | Black Hills Corporation Pension Plan
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	3.71%
Pension Plans, Defined Benefit | Black Hills Corporation - All Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.27%	4.50%	4.19%
Supplemental Employee Retirement Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.56%	4.02%	4.28%
Rate of Increase in Compensation Levels	5.00%	5.00%	5.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Rate of Compensation Increase	5.00%	5.00%	5.00%
Supplemental Employee Retirement Plan | Black Hills Corporation - All Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.02%	4.28%	4.19%
Other Postretirement Benefit Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.60%	3.96%	4.17%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	3.88%	3.83%	3.00%
Other Postretirement Benefit Plan | Black Hills Corporation - All Plans
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.05%	4.18%	3.82%

Employee Benefit Plans_ Project

Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2017USD ($)
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 21,495
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	23,238
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	27,203
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	26,990
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	27,427
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	154,771
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	1,372
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	1,617
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	1,558
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	1,773
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	1,872
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	11,304
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	5,633
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	6,231
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	6,328
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	6,072
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	5,920
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 26,365

Commitments and Contingencie128

Commitments and Contingencies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Sold	40
Purchase Commitment
Long-term Purchase Commitment [Line Items]
Long Term Contract For Purchase of Fuel, Date of Contract Expiration	Dec. 31, 2044
Busch Ranch Wind Farm | Electric Utilities
Long-term Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share Percentage	50.00%
Sharing Arrangement with the City of Gillette, Wyoming
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Period	20 years
PacifiCorp Purchase Power Agreement
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Megawatts of Capacity Purchased	50
Cost of Purchased Power | $	$ 13,218	$ 12,221	$ 13,990
PacifiCorp Transmission
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2023
Megawatts of Capacity Purchased	50
Cost of Purchased Power | $	$ 1,671	1,428	1,213
Happy Jack Wind Purchase Power Agreement
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Sep. 3, 2028
Megawatts of Capacity Purchased	30
Happy Jack Wind Purchase Power Agreement | Subsidiary of Common Parent
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased	50.00%
Happy Jack Wind Purchase Power Agreement | Renewable Wind Energy, Wyoming Electric
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $	$ 3,846	3,836	3,155
Silver Sage Wind Power Purchase Agreement
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Sep. 30, 2029
Megawatts of Capacity Purchased	30
Silver Sage Wind Power Purchase Agreement | Renewable Wind Energy, Wyoming Electric
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	20
Cost of Purchased Power | $	$ 4,934	4,949	4,107
Busch Ranch Wind Farm
Long-term Purchase Commitment [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Oct. 16, 2037
Megawatts of Capacity Purchased	14.5
Cost of Purchased Power | $	$ 1,966	2,071	1,734
Cargill Power Purchase Agreement
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $	$ 0	$ 10,995	$ 16,112

Commitments And Contingencies_

Commitments And Contingencies: Long-term Purchase Commitment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Natural Gas
Long-term Purchase Commitment [Line Items]
Cost of Natural Gas Purchases	$ 65,000	$ 31,000	$ 48,000
CIG Rockies
Long-term Purchase Commitment [Line Items]
2,018	5,784,827
2,019	5,776,125
2,020	75,075
2,021	0
2,022	0
NNG-Ventura
Long-term Purchase Commitment [Line Items]
2,018	3,759,500
2,019	3,704,300
2,020	3,660,000
2,021	3,650,000
2,022	1,810,000
NWPL-Wyoming
Long-term Purchase Commitment [Line Items]
2,018	1,298,970
2,019	786,470
2,020	0
2,021	0
2,022	0
EP-San Juan Basin
Long-term Purchase Commitment [Line Items]
2,018	278,600
2,019	287,000
2,020	206,600
2,021	0
2,022	0
Other Natural Gas Indices
Long-term Purchase Commitment [Line Items]
2,018	30,562
2,019	0
2,020	0
2,021	0
2,022	$ 0

Commitments And Contingencie130

Commitments And Contingencies: Unconditional Purchase Obligations (Details) $ in Thousands	Dec. 31, 2017USD ($)
Power Purchase Agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2,018	$ 28,041
2,019	6,837
2,020	6,837
2,021	6,203
2,022	6,203
Thereafter	6,204
Transportation, Storage, Gathering And Coal Agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2,018	121,485
2,019	122,351
2,020	117,332
2,021	107,918
2,022	87,393
Thereafter	$ 202,831

Commitments And Contingencie131

Commitments And Contingencies: Future Purchase Agreement - Related Party (Details) - Wygen I Generating Facility - Purchase Option, Property $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MW
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of Megawatts Capacity Purchased | MW	60
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2022
Asset Purchase Option | $	$ 2.6
Property, Plant and Equipment, Useful Life	35 years

Commitments And Contingencie132

Commitments And Contingencies: Power Sales Agreements (Details) - MW	Jan. 01, 2017	Dec. 31, 2017
M D U, Montana Dakota Utilities
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract		25
M D U, Montana Dakota Utilities | Maximum
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract		50
City Of Gillette
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract		23
Purchase Power Contract, MEAN, 10 Megawatts
Long-term Purchase Commitment [Line Items]
Long-term Contract To Sell Electric Power, Date of Contract Expiration		May 31, 2023
Purchase Power Contract, MEAN, 10 Megawatts | Neil Simpson I I
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract		10
Purchase Power Contract, MEAN, 10 Megawatts | Wygen I I I Generating Facility
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract		10
Cargill Power Purchase Agreement | Maximum
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	50

Commitments And Contingencie133

Commitments And Contingencies: Related Party Lease (Details) - Power purchased - Pueblo Airport Generation	12 Months Ended
	Dec. 31, 2017MW
Unrecorded Unconditional Purchase Obligation [Line Items]
Lease Expiration Date	Dec. 31, 2031
Number of Megawatts Capacity Purchased	200

Commitments And Contingencie134

Commitments And Contingencies: Reimbursement Agreement (Details) - Electric Utilities - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 544,855	$ 544,855
Industrial Development Revenue Bonds Due 2027
Debt Instrument [Line Items]
Long-term debt	$ 10,000	10,000
Long-term Debt, Maturity Date	Mar. 1, 2027
Industrial Development Revenue Bonds Due 2021
Debt Instrument [Line Items]
Long-term debt	$ 7,000	$ 7,000
Long-term Debt, Maturity Date	Sep. 1, 2021

Commitments And Contingencie135

Commitments And Contingencies: Environmental Contingencies (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Loss Contingencies [Line Items]
Regulatory assets	$ 297,454	$ 296,142
Electric Utilities
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	4,100
Gas Utilities | Manufactured Gas Plant
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1,500
Accrual for Environmental Loss Contingencies, Gross	2,600
Gas Utilities | Manufactured Gas Plant | Minimum
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss	2,600
Gas Utilities | Manufactured Gas Plant | Maximum
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss	6,100
Environmental
Loss Contingencies [Line Items]
Regulatory assets		$ 1,108
Environmental | Manufactured Gas Plant
Loss Contingencies [Line Items]
Regulatory assets	$ 1,031
Osage Plant Ash Impoundment
Loss Contingencies [Line Items]
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period	30 years
Osage Plant, Industrial Rubble Landfill
Loss Contingencies [Line Items]
Commitment and Contingencies, Environmental Matters, Post Closure Monitoring, Period	30 years

Guarantees (Details)

Guarantees (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 58,221
Mining | Surety Bond
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 58,221
Guarantor Obligations, Term	Ongoing

Discontinued Operations (Detail

Discontinued Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 23, 2018
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Other current assets	$ 10,360				$ 11,401				$ 10,360	$ 11,401
Derivative assets, current and noncurrent	0				153				0	153
Deferred income tax assets, noncurrent, net	16,966				26,329				16,966	26,329
Property, plant and equipment, net	56,916				82,812				56,916	82,812
Other current liabilities	(18,966)				(9,834)				(18,966)	(9,834)
Derivative liabilities, current and noncurrent	0				(1,586)				0	(1,586)
Other noncurrent liabilities	(22,808)				(22,803)				(22,808)	(22,803)
Net assets	42,468				86,472				42,468	86,472
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue									25,382	34,058	$ 43,283
Operations and maintenance									22,872	27,187	35,461
Depreciation, depletion and amortization									7,521	13,510	28,838
Impairment of long-lived assets									20,385	106,957	249,608
Total operating expenses									50,778	147,654	313,907
Operating (loss)									(25,396)	(113,596)	(270,624)
Interest income (expense), net									181	698	931
Other income (expense), net									(297)	110	(378)
Impairment of equity investments									0	0	(4,405)
Income tax benefit (expense)									8,413	48,626	100,817
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ (13,614)	$ (1,300)	$ (616)	$ (1,569)	$ (33,967)	$ (7,080)	$ (17,845)	$ (5,270)	$ (17,099)	$ (64,162)	$ (173,659)
Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Percent of Properties Having Either Closed Transactions or Signed Contracts to Sell												90.00%

Discontinued Operations_ Impair

Discontinued Operations: Impairment of Long-Lived Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)$ / bbl$ / MMcf	Dec. 31, 2015USD ($)$ / bbl$ / MMcf
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of long-lived assets	$ 20,385	$ 106,957	$ 249,608
Discontinued Operations, Held-for-sale or Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operations, Impairment Of Long-lived Assets (Net of Tax)	13,000
Impairment of long-lived assets	$ 20,000	$ 92,000	$ 250,000
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf		2.48	2.59
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf		2.25	1.27
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl		42.75	50.28
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl		37.35	44.72
Results of Operations, Impairment of Oil and Gas Properties		$ 106,957	$ 249,608
Assets Not Expected To Be Utilized In Cost Of Service Gas Program | Discontinued Operations, Held-for-sale or Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Results of Operations, Impairment of Oil and Gas Properties		$ 14,000

Discontinued Operations_ Equity

Discontinued Operations: Equity Investments in Unconsolidated Subsidiaries (Details) - Willow Creek / Lodge Creek Pipeline And Gathering System - Discontinued Operations, Held-for-sale or Disposed of by Sale $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity Method Investment, Ownership Percentage	25.00%
Equity Method Investment, Other than Temporary Impairment	$ 4.4
Equity Method Investment, Ownership Percentage Sold	25.00%

Oil and Gas Reserves (Unaudi140

Oil and Gas Reserves (Unaudited): Costs Incurred Oil and Gas (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Costs Incurred, Acquisition of Oil and Gas Properties [Abstract]
Proved Reserves	$ 0	$ 1,407
Unproved Reserves	910	669
Exploration Costs	1,102	35,434
Development Costs	4,657	128,998
Asset Retirement Obligation Incurred	0	566
Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 6,669	$ 167,074

Oil and Gas Reserves (Unaudi141

Oil and Gas Reserves (Unaudited): Proved Developed and Undeveloped Oil and Gas Reserve (Details)	12 Months Ended
	Dec. 31, 2016$ / bbl$ / MMcfMBblsMMcf	Dec. 31, 2015$ / bbl$ / MMcfMBblsMMcf
Reserve Quantities [Line Items]
Discounted Present Value Rate Used in Estimating Future Net Revenues - Oil and Gas Industry	10.00%
Discontinued Operations, Held-for-sale or Disposed of by Sale
Proved Developed And Undevleoped Reserves [Roll Forward]
Average Crude Oil Price, Per Barrel, NYMEX | $ / bbl	42.75	50.28
Average Natural Gas Price Per MCF, NYMEX | $ / MMcf	2.48	2.59
Average Natural Gas Liquids Price Per MCF, NYMEX | $ / MMcf	0	0
Average Crude Oil Price Per Barrel, Wellhead | $ / bbl	37.35	44.72
Average Natural Gas Price Per MCF, Wellhead | $ / MMcf	2.25	1.27
Average Natural Gas Liquids Price Per MCF, Wellhead | $ / MMcf	11.92	18.96
Discontinued Operations, Held-for-sale or Disposed of by Sale | Piceance Basin
Proved Developed And Undevleoped Reserves [Roll Forward]
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf	1.54
Discontinued Operations, Held-for-sale or Disposed of by Sale | San Juan Basin
Proved Developed And Undevleoped Reserves [Roll Forward]
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf	0.92
Discontinued Operations, Held-for-sale or Disposed of by Sale | Other Basin's
Proved Developed And Undevleoped Reserves [Roll Forward]
Reserve Calculation - Costs To Gather And Process Natural Gas Previously Netted From The Gas Price Were Reclassified Into Operating Expenses | $ / MMcf	0.53
Discontinued Operations, Held-for-sale or Disposed of by Sale | Oil
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year | MBbls	3,450	4,276
Production | MBbls	(319)	(371)
Additions, Acquisitions (Sales) | MBbls	(570)	(11)
Additions, Extensions, Discoveries (bcfe) | MBbls	3	199
Reserves, Revisions of Previous Estimates | MBbls	(322)	(643)
Balance at End of Year | MBbls	2,242	3,450
Proved Developed Reserves (Volume) | MBbls	2,242	3,436
Proved Undeveloped Reserve (Volume) | MBbls	0	14
Discontinued Operations, Held-for-sale or Disposed of by Sale | Natural Gas
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year	73,412	65,440
Production	(9,430)	(10,058)
Additions, Acquisitions (Sales)	(1,291)	(828)
Additions, Extensions, Discoveries (bcfe)	52	24,462
Reserves, Revisions of Previous Estimates	(8,173)	(5,604)
Balance at End of Year	54,570	73,412
Proved Developed Reserves (Volume)	54,570	73,390
Proved Undeveloped Reserve (Volume)	0	22
Discontinued Operations, Held-for-sale or Disposed of by Sale | Natural Gas Liquids
Proved Developed And Undevleoped Reserves [Roll Forward]
Balance at Beginning of Year	1,752	1,720
Production	(133)	(102)
Additions, Acquisitions (Sales)	(17)	0
Additions, Extensions, Discoveries (bcfe)	0	232
Reserves, Revisions of Previous Estimates	110	(98)
Balance at End of Year	1,712	1,752
Proved Developed Reserves (Volume)	1,712	1,752
Proved Undeveloped Reserve (Volume)	0	0
Cawley Gillespie & Associates - Mr. Zane Meekins
Reserve Quantities [Line Items]
Practical Experience In Petroleum Engineering	30 years
Experience In Estimation and Evaluation of Reserves	28 years

Oil and Gas Reserves (Unaudi142

Oil and Gas Reserves (Unaudited): Capitalized Costs (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Unproved oil and gas properties	$ 18,547	$ 47,254
Proved oil and gas properties	1,043,558	1,008,466
Gross capitalized costs	1,062,105	1,055,720
Accumulated depreciation, depletion and amortization and valuation allowances	(1,000,091)	(888,775)
Net capitalized costs	$ 62,014	$ 166,945

Oil and Gas Reserves (Unaudi143

Oil and Gas Reserves (Unaudited): Results of Operations Oil and Gas (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Revenue	$ 34,058	$ 43,283
Production costs	17,231	19,762
Depreciation, depletion and amortization and valuation provisions	12,574	28,062
Impairment of Oil and Gas Properties	106,957	249,608
Total costs	136,762	297,432
Results of operations from producing activities before tax	(102,704)	(254,149)
Income tax benefit (expense)	37,916	93,743
Results of operations from producing activities (excluding general and administrative costs and interest costs)	$ (64,788)	$ (160,406)

Oil and Gas Reserves (Unaudi144

Oil and Gas Reserves (Unaudited): Unproved Properties Excluded from Amortization (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Interest Costs, Capitalized During Period	$ 900	$ 1,000
Leasehold acquisition cost	963
Exploration cost	973
Capitalized interest	73
Total	2,009
Prior Year
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	963
Exploration cost	532
Capitalized interest	50
Total	1,545
More Than One Year, Less Than Two Years Prior
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	0
Exploration cost	441
Capitalized interest	23
Total	464
More Than Two Years Prior
Capitalized Costs of Unproved Properties Excluded from Amortization [Line Items]
Leasehold acquisition cost	0
Exploration cost	0
Capitalized interest	0
Total	$ 0

Oil and Gas Reserves (Unaudi145

Oil and Gas Reserves (Unaudited): Standard Measure of Discounted Future Net Cash Flows (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Future cash inflows	$ 246,221	$ 295,173
Future production costs	(166,248)	(146,552)
Future development costs, including plugging and abandonment	(18,333)	(24,833)
Future net cash flows	61,640	123,788
10% annual discount for estimated timing of cash flows	(26,574)	(44,760)
Standardized measure of discounted future net cash flows	$ 35,066	$ 79,028	$ 183,022

Oil and Gas Reserves (Unaudi146

Oil and Gas Reserves (Unaudited): Change in Standard Measure of Discounted Future Cash Net Flows (Details) - Discontinued Operations, Held-for-sale or Disposed of by Sale - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure - beginning of year	$ 79,028	$ 183,022
Sales and transfers of oil and gas produced, net of production costs	(4,314)	(29,948)
Net changes in prices and production costs	(32,698)	(127,199)
Extensions, discoveries and improved recovery, less related costs	0	15,718
Changes in future development costs	1,825	(7,387)
Development costs incurred during the period	0	27,211
Revisions of previous quantity estimates	(7,477)	(6,941)
Accretion of discount	7,903	18,870
Net change in income taxes	0	5,682
Sales of reserves	(9,201)	0
Standardized measure - end of year	$ 35,066	$ 79,028

Quarterly Historical Data (U147

Quarterly Historical Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Selected Quarterly Financial Information [Line Items]
Revenue	$ 455,298	$ 335,611	$ 341,829	$ 547,528	$ 455,390	$ 324,147	$ 317,795	$ 441,584	$ 1,680,266	$ 1,538,916	$ 1,261,322
Operating income (loss)	117,195	79,559	69,796	150,186	110,330	70,844	63,725	91,281	416,736	336,181	300,420
Income (loss) from continuing operations	67,835	32,898	25,927	81,715	55,381	24,964	21,128	45,320	208,375	146,793	141,548
Net (loss) from discontinued operations	(13,614)	(1,300)	(616)	(1,569)	(33,967)	(7,080)	(17,845)	(5,270)	(17,099)	(64,162)	(173,659)
Net income attributable to noncontrolling interest	(3,568)	(3,935)	(3,116)	(3,623)	(3,246)	(3,753)	(2,614)	(48)	(14,242)	(9,661)	0
Net income (loss) available for common stock	50,653	27,663	22,195	76,523	18,168	14,131	669	40,002	177,034	72,970	(32,111)
Amounts attributable to common shareholders:
Net income from continuing operations	64,267	28,963	22,811	78,092	52,135	21,211	18,514	45,272	194,133	137,132	141,548
Net (loss) from discontinued operations	(13,614)	(1,300)	(616)	(1,569)	(33,967)	(7,080)	(17,845)	(5,270)	(17,099)	(64,162)	(173,659)
Net income (loss) available for common stock	$ 50,653	$ 27,663	$ 22,195	$ 76,523	$ 18,168	$ 14,131	$ 669	$ 40,002	$ 177,034	$ 72,970	$ (32,111)
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations, Basic (usd per share)	$ 1.21	$ 0.54	$ 0.43	$ 1.47	$ 0.98	$ 0.41	$ 0.36	$ 0.88	$ 3.65	$ 2.64	$ 3.12
(Loss) from discontinued operations per share, Basic (usd per share)	(0.26)	(0.02)	(0.01)	(0.03)	(0.64)	(0.14)	(0.35)	(0.10)	(0.32)	(1.23)	(3.83)
Total earnings (loss) per share of common stock, Basic (usd per share)	0.95	0.52	0.42	1.44	0.34	0.27	0.01	0.78	3.33	1.41	(0.71)
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations, Diluted (usd per share)	1.17	0.52	0.41	1.42	0.96	0.39	0.35	0.87	3.52	2.57	3.12
(Loss) from discontinued operations, Diluted (usd per share)	(0.25)	(0.02)	(0.01)	(0.03)	(0.63)	(0.13)	(0.34)	(0.10)	(0.31)	(1.20)	(3.83)
Total earnings (loss) per share of common stock, Diluted (usd per share)	0.92	0.50	0.40	1.39	0.33	0.26	0.01	0.77	3.21	1.37	(0.71)
Dividends per share paid (usd per share)	$ 0.475	$ 0.445	$ 0.445	$ 0.445	$ 0.420	$ 0.420	$ 0.420	$ 0.420	$ 1.81	$ 1.68	$ 1.62
Business Combination, Acquisition Related Costs, Net Of Tax	$ 1,300	$ 200	$ 300	$ 900	$ 5,500	$ 4,100	$ 4,100	$ 15,000
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Income Tax Expense (Benefit)									$ (7,600)
Income Tax Expense (Benefit)									73,367	$ 59,101	$ 78,657
Common Stock | Maximum
Earnings (loss) per share of common stock, Diluted -
Share Price (usd per share)	$ 69.79	$ 71.01	$ 72.02	$ 67.02	$ 62.83	$ 64.58	$ 63.53	$ 61.13
Common Stock | Minimum
Earnings (loss) per share of common stock, Diluted -
Share Price (usd per share)	$ 57.01	$ 67.08	$ 65.37	$ 60.02	$ 54.76	$ 56.86	$ 56.16	$ 44.65
Discontinued Operations, Held-for-sale or Disposed of by Sale
Earnings (loss) per share of common stock, Diluted -
Impairment Of Oil And Gas Properties, Net Of Tax	$ 13,000				$ 34,000	$ 7,900	$ 16,000	$ 8,800
True-up from SourceGas Tax Returns
Earnings (loss) per share of common stock, Diluted -
Income Tax Expense (Benefit)									$ (4,100)

Schedule II Consolidated Val148

Schedule II Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Allowance for Doubtful Accounts, Balance at Beginning of Year	$ 2,392	$ 1,741	$ 1,516
Allowance for Doubtful Accounts, Adjustments	0	2,158	0
Allowance for Doubtful Accounts, Charged to Cost and Expense	4,926	2,704	3,860
Allowance for Doubtful Accounts, Recoveries and Other Additions	8,262	4,915	4,132
Allowance for Doubtful Accounts, Write-Offs and Other Deductions	(12,499)	(9,126)	(7,767)
Allowance for Doubtful Accounts, Balance at End of Year	$ 3,081	$ 2,392	$ 1,741