Black Hills (BKH) 10-K 14 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Jan. 31, 2020	Jun. 30, 2019
Document and Entity Information [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-31303
Entity Registrant Name	BLACK HILLS CORPORATION
Entity Incorporation, State or Country Code	SD
Entity Tax Identification Number	46-0458824
Entity Address, Address Line One	7001 Mount Rushmore Road
Entity Address, City or Town	Rapid City
Entity Address, State or Province	SD
Entity Address, Postal Zip Code	57702
City Area Code	(605)
Local Phone Number	721-1700
Title of 12(b) Security	Common stock of $1.00 par value
Trading Symbol	BKH
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 4,727,278,183
Entity Common Stock, Shares Outstanding		61,475,403
Entity Central Index Key	0001130464
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue:
Revenue	$ 1,734,900	$ 1,754,268	$ 1,680,266
Operating expenses:
Fuel, purchased power and cost of natural gas sold	570,829	625,610	563,288
Operations and maintenance	495,994	481,706	454,605
Depreciation, depletion and amortization	209,120	196,328	188,246
Taxes - property and production	52,915	51,746	51,578
Other operating expenses	0	1,841	5,813
Total operating expenses	1,328,858	1,357,231	1,263,530
Operating income	406,042	397,037	416,736
Interest charges -
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(145,847)	(143,720)	(140,533)
Allowance for funds used during construction - borrowed	6,556	2,104	2,415
Interest income	1,632	1,641	1,016
Allowance for funds used during construction - equity	472	619	2,321
Impairment of investment	(19,741)	0	0
Other income (expense), net	(6,212)	(1,799)	(213)
Total other income (expense)	(163,140)	(141,155)	(134,994)
Income before income taxes	242,902	255,882	281,742
Income tax benefit (expense)	(29,580)	23,667	(73,367)
Income from continuing operations	213,322	279,549	208,375
Net (loss) from discontinued operations	0	(6,887)	(17,099)
Net income	213,322	272,662	191,276
Net income attributable to noncontrolling interest	(14,012)	(14,220)	(14,242)
Net income (loss) available for common stock	199,310	258,442	177,034
Amounts attributable to common shareholders:
Net income from continuing operations	199,310	265,329	194,133
Net (loss) from discontinued operations	0	(6,887)	(17,099)
Net income (loss) available for common stock	$ 199,310	$ 258,442	$ 177,034
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations, Basic (usd per share)	$ 3.29	$ 4.88	$ 3.65
(Loss) from discontinued operations per share, Basic (usd per share)	0	(0.13)	(0.32)
Total earnings (loss) per share of common stock, Basic (usd per share)	3.29	4.75	3.33
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations, Diluted (usd per share)	3.28	4.78	3.52
(Loss) from discontinued operations, Diluted (usd per share)	0	(0.12)	(0.31)
Total earnings (loss) per share of common stock, Diluted (usd per share)	$ 3.28	$ 4.66	$ 3.21
Weighted average common shares outstanding:
Basic	60,662	54,420	53,221
Diluted	60,798	55,486	55,120

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income (loss)	$ 213,322	$ 272,662	$ 191,276
Other Comprehensive (Income) Loss, Defined Benefit Plan, before Reclassification Adjustment, after Tax [Abstract]
Benefit plan liability adjustments - net gain (loss) (net of tax of $1,886, $(660) and $1,030, respectively)	(6,253)	2,155	(1,890)
Benefit plan liability adjustments - prior service costs (net of tax of $2, $0 and $0, respectively)	(8)	0	0
Reclassification adjustment of benefit plan liability - net loss (net of tax of $434, $(586) and $(585), respectively)	1,179	1,901	1,072
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $19, $43 and $69, respectively)	(58)	(135)	(128)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax [Abstract]
Other comprehensive income (loss), net of tax	(3,739)	7,027	681
Comprehensive income	209,583	279,689	191,957
Net income attributable to noncontrolling interest	(14,012)	(14,220)	(14,242)
Comprehensive income available for common stock	195,571	265,469	177,715
Interest rate swaps
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax [Abstract]
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax	2,185	2,252	1,912
Commodity derivatives
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax [Abstract]
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax	(362)	99	(516)
Net unrealized gains (losses) on commodity derivatives (net of tax of $126, $(228) and $(135), respectively)	$ (422)	$ 755	$ 231

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Benefit plan liability adjustments - net gain (loss), Tax	$ 1,886	$ (660)	$ 1,030
Benefit plan liability adjustments - prior service (costs), Tax	2	0	0
Reclassification adjustment of benefit plan liability - net gain (loss) tax	434	(586)	(585)
Reclassification adjustment of benefit plan liability - prior service cost, tax	19	43	69
Interest Rate Swap
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax	(666)	(599)	(1,029)
Commodity Contract
Fair value adjustment on derivatives (interest rate swaps) designated as cash flow hedges, Tax	126	(228)	(135)
Reclassification adjustment of cash flow hedges settled (interest rate swaps) and included in net income (loss), Tax	$ 55	$ (31)	$ 154

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 9,777	$ 20,776
Restricted cash and equivalents	3,881	3,369
Accounts receivable, net	255,805	269,153
Materials, supplies and fuel	117,172	117,299
Derivative assets, current	342	1,500
Income tax receivable, net	16,446	12,978
Regulatory assets, current	43,282	48,776
Other current assets	26,479	29,982
Total current assets	473,184	503,833
Investments	21,929	41,013
Property, plant and equipment	6,784,679	6,000,015
Less accumulated depreciation and depletion	(1,281,493)	(1,145,136)
Total property, plant and equipment, net	5,503,186	4,854,879
Other assets:
Goodwill	1,299,454	1,299,454
Intangible assets, net	13,266	14,337
Regulatory assets, non-current	228,062	235,459
Other assets, non-current	19,376	14,352
Total other assets, non-current	1,560,158	1,563,602
TOTAL ASSETS	7,558,457	6,963,327
Current liabilities:
Accounts payable	193,523	210,609
Accrued liabilities	226,767	215,501
Derivative liabilities, current	2,254	947
Regulatory liabilities, current	33,507	29,810
Notes payable	349,500	185,620
Current maturities of long-term debt	5,743	5,743
Total current liabilities	811,294	648,230
Long-term debt, net of current maturities	3,140,096	2,950,835
Deferred credits and other liabilities:
Deferred income tax liabilities, net	360,719	311,331
Regulatory liabilities, non-current	503,145	510,984
Benefit plan liabilities	154,472	145,147
Other deferred credits and other liabilities	124,662	109,377
Total deferred credits and other liabilities	1,142,998	1,076,839
Commitments and contingencies (See Notes 6, 7, 8, 9, 14, 18, 19, and 20)
Stockholders’ equity -
Common stock $1 par value; 100,000,000 shares authorized; issued: 61,480,658 and 60,048,567, respectively	61,481	60,049
Additional paid-in capital	1,552,788	1,450,569
Retained earnings	778,776	700,396
Treasury stock at cost - 3,956 and 44,253, respectively	(267)	(2,510)
Accumulated other comprehensive income (loss)	(30,655)	(26,916)
Total stockholders’ equity	2,362,123	2,181,588
Noncontrolling interest	101,946	105,835
Total equity	2,464,069	2,287,423
TOTAL LIABILITIES AND TOTAL EQUITY	$ 7,558,457	$ 6,963,327

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common Stock, Par Value (usd per share)	$ 1	$ 1
Treasury Stock, Shares	3,956.1	44,253
Common Stock, Shares Authorized	100,000,000	100,000,000
Common Stock, Shares, Issued	61,480,658.32	60,048,567

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities:
Net income	$ 213,322	$ 272,662	$ 191,276
Loss from discontinued operations, net of tax	0	6,887	17,099
Income from continuing operations	213,322	279,549	208,375
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	209,120	196,328	188,246
Deferred financing cost amortization	7,838	7,845	8,261
Impairment of investment	19,741	0	0
Stock compensation	12,095	12,390	7,626
Deferred income taxes	38,020	(24,239)	80,992
Employee benefit plans	12,406	14,068	10,141
Other adjustments, net	16,485	5,836	(4,773)
Change in certain operating assets and liabilities:
Materials, supplies and fuel	2,052	(2,919)	(10,089)
Accounts receivable and other current assets	7,578	(45,966)	4,534
Accounts payable and other current liabilities	(34,906)	5,305	(28,222)
Regulatory assets - current	23,619	33,608	(15,407)
Regulatory liabilities - current	(15,158)	18,533	(4,536)
Contributions to defined benefit pension plans	(12,700)	(12,700)	(27,700)
Other operating activities, net	6,001	6,689	(8,418)
Net cash provided by operating activities of continuing operations	505,513	494,327	409,030
Net cash provided by (used in) operating activities of discontinued operations	0	(5,516)	19,231
Net cash provided by operating activities	505,513	488,811	428,261
Investing activities:
Property, plant and equipment additions	(818,376)	(457,524)	(326,010)
Purchase of investment	0	(24,429)	0
Other investing activities	2,166	(4,281)	1,011
Net cash (used in) investing activities of continuing operations	(816,210)	(486,234)	(324,999)
Net cash provided by investing activities of discontinued operations	0	20,385	7,881
Net cash (used in) investing activities	(816,210)	(465,849)	(317,118)
Financing activities:
Dividends paid on common stock	(124,647)	(106,591)	(96,744)
Common stock issued	101,358	300,834	4,408
Net (payments) borrowings of short-term debt	163,880	(25,680)	114,700
Long-term debt - issuance	1,100,000	700,000	0
Long-term debt - repayments	(905,743)	(854,743)	(105,743)
Distributions to noncontrolling interests	(17,901)	(19,617)	(18,397)
Other financing activities	(16,737)	(11,260)	(6,919)
Net cash provided by (used in) financing activities	300,210	(17,057)	(108,695)
Net change in cash, restricted cash and cash equivalents	(10,487)	5,905	2,448
Cash and cash equivalents:
Cash, restricted cash and cash equivalents beginning of year	24,145	18,240	15,792
Cash, restricted cash and cash equivalents end of year	$ 13,658	$ 24,145	$ 18,240

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, 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	15,258
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	191,276				177,034		14,242
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, shares		134,266	23,806
Share-based compensation	7,567	$ 134	$ (1,515)	8,948
Tax effect of share-based compensation	3,717			533	3,184
Issuance costs	(189)			(189)
Dividend reinvestment and stock purchase plan, shares		48,253
Dividend reinvestment and stock purchase plan	3,156	$ 49		3,107
Minority interest decrease from redemptions				(1,096)	209
Distributions to noncontrolling interest	(19,392)						(18,505)
Common Stock, Shares, Outstanding at Dec. 31, 2017		53,579,986	39,064
Total equity at Dec. 31, 2017	$ 1,820,206	$ 53,580	$ (2,306)	1,150,285	548,617	(41,202)	111,232
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.81
Net income (loss)	$ 272,662				258,442		14,220
Other comprehensive income (loss), net of tax	7,027					7,027
Reclassification of certain tax effects from AOCI	740				0	740
Reclassification to regulatory asset	6,519					6,519
Dividends on common stock	(106,591)				(106,591)
Share-based compensation, shares		92,830	5,189
Share-based compensation	7,190	$ 93	$ (204)	7,301
Issuance of common stock, shares		6,371,690
Issuance of common stock	299,000	$ 6,372		292,628
Issuance costs	(15)			(15)
Dividend reinvestment and stock purchase plan, shares		4,061
Dividend reinvestment and stock purchase plan	220	$ 4		216
Other stock transactions	82			154	(72)
Minority interest decrease from redemptions				0	0
Distributions to noncontrolling interest	(19,617)						(19,617)
Common Stock, Shares, Outstanding at Dec. 31, 2018		60,048,567	44,253
Total equity at Dec. 31, 2018	$ 2,287,423	$ 60,049	$ (2,510)	1,450,569	700,396	(26,916)	105,835
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 1.93
Net income (loss)	$ 213,322				199,310		14,012
Other comprehensive income (loss), net of tax	(3,739)					(3,739)
Dividends on common stock	(124,647)				(124,647)
Share-based compensation, shares		103,759	(40,297)
Share-based compensation	7,076	$ 104	$ 2,243	4,729
Issuance of common stock, shares		1,328,332
Issuance of common stock	100,000	$ 1,328		98,672
Issuance costs	(1,182)			(1,182)
Other stock transactions	327			0	327
Minority interest decrease from redemptions				0	0
Distributions to noncontrolling interest	(17,901)						(17,901)
Common Stock, Shares, Outstanding at Dec. 31, 2019		61,480,658	3,956
Total equity at Dec. 31, 2019	$ 2,464,069	$ 61,481	$ (267)	$ 1,552,788	778,776	$ (30,655)	$ 101,946
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Dividends per share paid (usd per share)	$ 2.05
Implementation of ASU 2016-02 Leases	$ 3,390				$ 3,390

Business Description And Signif

Business Description And Significant Accounting Policies:	12 Months Ended
	Dec. 31, 2019
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 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 Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Most 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 Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in 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. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued operations in 2018 or 2017. 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. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5 . Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account 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 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 and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified 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 Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal. 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): 2019 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 41,428 $ 33,886 $ (592 ) $ 74,722 Gas Utilities 97,607 79,616 (1,683 ) 175,540 Power Generation 2,164 — — 2,164 Mining 2,277 — — 2,277 Corporate 1,271 — (169 ) 1,102 Total $ 144,747 $ 113,502 $ (2,444 ) $ 255,805 2018 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 39,721 $ 35,125 $ (448 ) $ 74,398 Gas Utilities 96,123 90,521 (2,592 ) 184,052 Power Generation 1,876 — — 1,876 Mining 3,988 — — 3,988 Corporate 5,008 — (169 ) 4,839 Total $ 146,716 $ 125,646 $ (3,209 ) $ 269,153 Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands): Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year 2019 $ 3,209 $ 5,795 $ 3,942 $ (10,502 ) $ 2,444 2018 $ 3,081 $ 6,859 $ 4,092 $ (10,823 ) $ 3,209 2017 $ 2,392 $ 4,926 $ 8,262 $ (12,499 ) $ 3,081 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): 2019 2018 Materials and supplies $ 82,809 $ 75,081 Fuel - Electric Utilities 2,425 2,850 Natural gas in storage 31,938 39,368 Total materials, supplies and fuel $ 117,172 $ 117,299 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. Investments In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10% . Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million , which was the difference between the carrying amount and the fair value of the investment. The following table presents the carrying value of our investments (in thousands) as of December 31: 2019 2018 Investment in privately held oil and gas company $ 8,359 $ 28,100 Cash surrender value of life insurance contracts 13,056 12,812 Other investments 514 101 Total investments $ 21,929 $ 41,013 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. 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 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 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. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. 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. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. 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, long-term earnings and merger multiples for comparable companies. 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 amounts have not changed since 2016. As of December 31, 2019, 2018 and 2017, Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Goodwill $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454 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): 2019 2018 2017 Intangible assets, net, beginning balance $ 14,337 $ 7,559 $ 8,392 Additions (a) — 7,602 — Amortization expense (b) (1,071 ) (824 ) (833 ) Intangible assets, net, ending balance $ 13,266 $ 14,337 $ 7,559 _________________ (a) The 2018 addition is related to the Busch Ranch 1 contract intangible asset. See Note 4 for further information. (b) Amortization expense for existing intangible assets is expected to be $1.1 million for each year of the next five years. 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): 2019 2018 Accrued employee compensation, benefits and withholdings $ 62,837 $ 63,742 Accrued property taxes 44,547 42,510 Customer deposits and prepayments 54,728 43,574 Accrued interest 31,868 31,759 CIAC current portion 1,952 1,485 Other (none of which is individually significant) 30,835 32,431 Total accrued liabilities $ 226,767 $ 215,501 Asset Retirement Obligations Accounting standards for AROs 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. 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. Additional information is included in Note 8 . Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments 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. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, 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 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 when 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 The commodity contracts for our Electric and Gas Utilities are valued using the market approach and include Level 2 exchange-traded futures, options, basis swaps and over-the-counter swaps for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable instrument. For over-the-counter instruments, fair value was obtained by utilizing a nationally recognized service that obtains observable inputs to compute fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Additional information on fair value measurements is included in Notes 10 , 11 and 18 . Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. 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. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utilities’ operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980. We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings. 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. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterpart when a legal right of offset exists. Deferred Financing Costs Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities. Regulatory Accounting Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates. • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings. If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows. As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million respectively, and total regulatory liabilities of $537 million and $541 million respectively. See Note 13 for further information. Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense 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. It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs 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 ITC 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. 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 or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information. 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, outstanding stock options, restricted stock and performance shares under our equity compensation plans. A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands): 2019 2018 2017 Net income available for common stock $ 199,310 $ 258,442 $ 177,034 Weighted average shares - basic 60,662 54,420 53,221 Dilutive effect of: Equity Units — 898 1,783 Equity compensation 136 168 116 Weighted average shares - diluted 60,798 55,486 55,120 Net income available for common stock, per share - Diluted $ 3.28 $ 4.66 $ 3.21 The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands): 2019 2018 2017 Equity compensation 1 16 11 Anti-dilutive shares excluded from computation of earnings per share 1 16 11 Noncontrolling Interests 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. See Note 12 for additional detail on Noncontrolling Interests. 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 Accounting Standards Simplifying the Accounting for Income Taxes, ASU 2019-12 In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740 , Income Taxes , and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows. Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15 In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract , which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, ASU 2017-04 In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill

Revenue_

Revenue:	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUE Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under tariff rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. • Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered. • Other non-regulated services - Our Electric and Gas Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the years ended December 31, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 605,756 $ 817,840 $ — $ 59,233 $ (32,053 ) $ 1,450,776 Transportation — 143,390 — — (1,042 ) 142,348 Wholesale 20,884 — 99,157 — (91,577 ) 28,464 Market - off-system sales 23,817 691 — — (7,736 ) 16,772 Transmission/Other 57,104 47,725 — — (16,797 ) 88,032 Revenue from contracts with customers 707,561 1,009,646 99,157 59,233 (149,205 ) 1,726,392 Other revenues 5,191 384 2,101 2,396 (1,564 ) 8,508 Total revenues $ 712,752 $ 1,010,030 $ 101,258 $ 61,629 $ (150,769 ) $ 1,734,900 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 59,233 $ (32,053 ) $ 27,180 Services transferred over time 707,561 1,009,646 99,157 — (117,152 ) 1,699,212 Revenue from contracts with customers $ 707,561 $ 1,009,646 $ 99,157 $ 59,233 $ (149,205 ) $ 1,726,392 Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation (a) Mining Inter-company Revenues (a) Total Customer types: (in thousands) Retail $ 594,329 $ 833,379 $ — $ 65,803 $ (32,194 ) $ 1,461,317 Transportation — 140,705 — — (1,348 ) 139,357 Wholesale 33,687 — 90,791 — (84,957 ) 39,521 Market - off-system sales 24,799 866 — — (8,102 ) 17,563 Transmission/Other 56,209 49,402 — — (14,827 ) 90,784 Revenue from contracts with customers 709,024 1,024,352 90,791 65,803 (141,428 ) 1,748,542 Other revenues 2,427 955 1,660 2,230 (1,546 ) 5,726 Total revenues $ 711,451 $ 1,025,307 $ 92,451 $ 68,033 $ (142,974 ) $ 1,754,268 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 65,803 $ (32,194 ) $ 33,609 Services transferred over time 709,024 1,024,352 90,791 — (109,234 ) 1,714,933 Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 90,791 $ 65,803 $ (141,428 ) $ 1,748,542 (a) Due to the changes in our segment disclosures discussed in Note 5 , Power Generation Wholesale revenue was revised for the year ended December 31, 2018 , which resulted in an increase of $38 million . The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million . There was no impact to our consolidated Total Revenues. The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. Effective January 1, 2019, we changed how we account for the PPA between Black Hills Colorado IPP and Colorado Electric at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information. Significant Judgments and Estimates Unbilled Revenue 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. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 1

Property, Plant And Equipment_

Property, Plant And Equipment:	12 Months Ended
	Dec. 31, 2019
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): 2019 2018 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment (b) Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,348,049 41 $ 1,318,643 41 32 46 Electric transmission 483,640 51 437,082 51 43 54 Electric distribution 861,042 47 793,725 48 46 50 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 259,266 28 233,531 28 26 33 Total electric plant in service 2,956,867 2,787,851 Construction work in progress 102,268 60,480 Total electric plant 3,059,135 2,848,331 Less accumulated depreciation and amortization (670,861 ) (615,365 ) Electric plant net of accumulated depreciation and amortization $ 2,388,274 $ 2,232,966 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 11 years remaining. (b) Due to the changes in our segment disclosures discussed in Note 5 , Total electric plant in service, Accumulated depreciation and amortization, and Electric plant net of accumulated depreciation and amortization were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million , $91 million and ($170) million , respectively. There was no impact on our consolidated Plant, property and equipment. 2019 2018 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 $ 13,000 35 $ 13,580 35 24 71 Gas transmission 516,172 50 423,873 48 22 67 Gas distribution 1,857,233 43 1,595,644 42 30 56 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciable (a) 44,443 N/A 46,369 N/A N/A N/A Storage 46,977 31 29,335 30 27 49 General 437,054 20 355,920 19 10 24 Total gas plant in service 2,918,418 2,468,260 Construction work in progress 63,080 38,271 Total gas plant 2,981,498 2,506,531 Less accumulated depreciation and amortization (336,721 ) (279,580 ) Gas plant net of accumulated depreciation and amortization $ 2,644,777 $ 2,226,951 _____________ (a) Depreciation of Cushion gas is determined by the respective regulatory jurisdiction in which the Cushion gas resides. 2019 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 $ 532,397 $ 2,121 $ 534,518 $ (154,362 ) $ 380,156 31 2 40 Mining $ 179,198 $ 1,275 $ 180,473 $ (118,585 ) $ 61,888 13 2 59 2018 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 (a) $ 435,438 $ 11,796 $ 447,234 $ (137,832 ) $ 309,402 31 2 40 Mining $ 175,650 $ — $ 175,650 $ (111,689 ) $ 63,961 13 2 59 _____________ (a) Due to the changes in our segment disclosures discussed in Note 5 , Property, plant and equipment, Accumulated depreciation and amortization, and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of $261 million , ($73) million and $188 million , respectively. There was no impact on our consolidated Plant, property and equipment. 2019 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 Corporate $ 5,721 $ 23,334 $ 29,055 $ (964 ) $ 28,091 10 3 30 2018 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate (a) $ 5,721 $ 16,548 $ 22,269 $ (670 ) $ 21,599 8 3 30 ___________ (a) Due to the changes in our segment disclosures discussed in Note 5 , Corporate Accumulated depreciation and amortization and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($18) million and ($18) million respectively. There was no impact on our consolidated Plant, property and equipment.

Jointly Owned Facilities_

Jointly Owned Facilities:	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Jointly Owned Facilities	JOINTLY OWNED FACILITIES Our consolidated financial statements include our share of several jointly-owned utility and non-regulated 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. 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 and SPP regions. 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 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. South Dakota Electric retains responsibility for plant operations. Our Mining subsidiary supplies fuel to Wygen III for the life of the plant. • 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. Black Hills Wyoming retains responsibility for plant operations. At December 31, 2019 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation Wyodak Plant $ 116,074 $ 729 $ (64,413 ) $ 52,390 Transmission Tie $ 19,862 $ 4,161 $ (6,612 ) $ 17,411 Wygen I $ 120,824 $ 289 $ (48,703 ) $ 72,410 Wygen III $ 146,161 $ 400 $ (25,518 ) $ 121,043 Jointly Owned Facility - Related Party Colorado Electric owns 50% of Busch Ranch I while Black Hills Electric Generation owns the remaining 50% ownership interest. Each company is obligated to make payments for costs associated with their proportionate share of the costs of operating the wind farm over the life of the facility. On December 11, 2018, Black Hills Electric Generation purchased its 50% ownership interest in Busch Ranch I for $16 million . Colorado Electric retains responsibility for operations of the wind farm. We recorded this purchase as an asset acquisition at fair value with $8.7 million of the purchase price recorded as wind generation assets, and $7.6 million recorded as an intangible asset, reflective of the fair value of the PPA. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.

Business Segment Information_

Business Segment Information:	12 Months Ended
	Dec. 31, 2019
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. Accounting standards for presentation of segments require an approach based on the way we organize the segments for making operating decisions and how the chief operating decision maker (CODM) assesses performance. Effective January 1, 2019, we concluded that adjusted operating income, instead of net income available for common stock which was used previously, is the most relevant metric for measuring segment performance. The change to our segment performance measure resulted in a revision of the Company’s segment disclosures for all periods to report adjusted operating income as the measure of segment performance. Prior to January 1, 2019, operating income for the Electric Utilities and Power Generation segments and Corporate and Other included the impacts of finance lease accounting relating to Colorado Electric’s PPA with Black Hills Colorado IPP. This PPA provides 200 MW of energy and capacity to Colorado Electric from Black Hills Colorado IPP’s combined-cycle turbines and expires on December 31, 2031. Finance lease accounting required us to de-recognize the asset from Black Hills Colorado IPP (Power Generation segment), which legally owns the asset, and recognize it at Colorado Electric (Electric Utilities segment). The CODM assesses the performance of our segments using adjusted operating income, which recognizes intersegment revenues, costs, and assets for Colorado Electric’s PPA with Black Hills Colorado IPP on an accrual basis rather than as a finance lease. Effective January 1, 2019, we changed how we account for this PPA at the segment level, which impacts disclosures for all periods for revenues, fuel and purchased power cost, operating income and total assets for the Electric Utilities and Power Generation segments as well as Corporate and Other. There were no revisions to Gas Utilities and Mining segments and this change had no effect on our consolidated revenues, fuel and purchased power cost, operating income or total assets. Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2019 2018 Electric Utilities (a) $ 2,900,983 $ 2,707,695 Gas Utilities 4,032,339 3,623,475 Power Generation (a) 417,715 342,085 Mining 77,175 80,594 Corporate and Other 130,245 209,478 Total assets $ 7,558,457 $ 6,963,327 __________________ (a) Due to the changes in our segment disclosures, Electric Utilities and Power Generation Total assets were revised as of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million , respectively. There was no impact on our consolidated Total assets. Capital Expenditures (a) for the years ended December 31, 2019 2018 Capital expenditures Electric Utilities $ 222,911 $ 152,524 Gas Utilities 512,366 288,438 Power Generation 85,346 30,945 Mining 8,430 18,794 Corporate and Other 20,702 11,723 Total capital expenditures of continuing operations 849,755 502,424 Total capital expenditures of discontinued operations — 2,402 Total capital expenditures $ 849,755 $ 504,826 _________________ (a) Includes accruals for property, plant and equipment as disclosed in Note 17 . Property, Plant and Equipment as of December 31, 2019 2018 Electric Utilities (a) $ 3,059,135 $ 2,848,331 Gas Utilities 2,981,498 2,506,531 Power Generation (a) 534,518 447,234 Mining 180,473 175,650 Corporate and Other 29,055 22,269 Total property, plant and equipment $ 6,784,679 $ 6,000,015 _______________ (a) Due to the changes in our segment disclosures, Electric Utilities and Power Generation Property, Plant and Equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million and $261 million , respectively. There was no impact on our consolidated Property, Plant and Equipment. Consolidating Income Statement Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 684,445 $ 1,007,187 $ 7,580 $ 27,180 $ — $ — $ 1,726,392 Other revenues 5,191 384 1,859 1,074 — — 8,508 689,636 1,007,571 9,439 28,254 — — 1,734,900 Inter-company operating revenue - Contracts with customers 23,116 2,459 91,577 32,053 230 (149,435 ) — Other revenues — — 242 1,322 343,975 (345,539 ) — 23,116 2,459 91,819 33,375 344,205 (494,974 ) — Total revenue 712,752 1,010,030 101,258 61,629 344,205 (494,974 ) 1,734,900 Fuel, purchased power and cost of natural gas sold 268,297 425,898 9,059 — 268 (132,693 ) 570,829 Operations and maintenance 195,581 301,844 28,429 40,032 286,799 (303,776 ) 548,909 Depreciation, depletion and amortization 88,577 92,317 18,991 8,970 22,065 (21,800 ) 209,120 Adjusted operating income (loss) $ 160,297 $ 189,971 $ 44,779 $ 12,627 $ 35,073 $ (36,705 ) $ 406,042 Interest expense, net (137,659 ) Impairment of investment (a) (19,741 ) Other income (expense), net (5,740 ) Income tax benefit (expense) (29,580 ) Income from continuing operations 213,322 (Loss) from discontinued operations, net of tax — Net income 213,322 Net income attributable to noncontrolling interest (14,012 ) Net income available for common stock $ 199,310 ________________ (a) In 2019 we recorded an impairment of our investment in equity securities of a privately held oil and gas company. See Note 1 for additional information. Consolidating Income Statement Year ended December 31, 2018 Electric Utilities (b) Gas Utilities Power Generation (b) Mining Corporate Inter-Company Eliminations (b) Total Revenue - Contracts with customers $ 686,272 $ 1,022,828 $ 5,833 $ 33,609 $ — $ — $ 1,748,542 Other revenues 2,427 955 1,413 931 — $ — 5,726 688,699 1,023,783 7,246 34,540 — — 1,754,268 Inter-company operating revenue - Contracts with customers 22,752 1,524 84,959 32,194 148 (141,577 ) — Other revenues — — 246 1,299 379,775 (381,320 ) — 22,752 1,524 85,205 33,493 379,923 (522,897 ) — Total revenue 711,451 1,025,307 92,451 68,033 379,923 (522,897 ) 1,754,268 Fuel, purchased power and cost of natural gas sold 283,840 462,153 8,592 — 44 (129,019 ) 625,610 Operations and maintenance 186,175 291,481 25,135 43,728 324,916 (336,142 ) 535,293 Depreciation, depletion and amortization 85,567 86,434 16,110 7,965 21,161 (20,909 ) 196,328 Adjusted operating income (loss) 155,869 185,239 42,614 16,340 33,802 (36,827 ) 397,037 Interest expense, net (139,975 ) Other income (expense), net (1,180 ) Income tax benefit (expense) (a) 23,667 Income from continuing operations 279,549 (Loss) from discontinued operations, net of tax (6,887 ) Net income 272,662 Net income attributable to noncontrolling interest (14,220 ) Net income available for common stock $ 258,442 ________________ (a) Income tax benefit (expense) includes a tax benefit of $73 million resulting from legal entity restructuring. See Note 15 . (b) Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2018, which resulted in an increase (decrease) as follows (in millions): Year ended December 31, 2018 Electric Utilities Power Generation Inter-Company Eliminations Total Inter-company operating revenue - Contracts with customers $ — $ 3.5 $ (3.5 ) $ — Fuel, purchased power and cost of natural gas sold 6.7 — (6.7 ) — Depreciation, depletion and amortization (13.1 ) 9.2 3.9 — Adjusted operating income (loss) $ 6.4 $ (5.7 ) $ (0.7 ) $ — Consolidating Income Statement Year ended December 31, 2017 Electric Utilities (b) Gas Utilities Power Generation (b) Mining Corporate Inter-Company Eliminations (b) Total Revenue $ 689,945 $ 947,595 $ 7,263 $ 35,463 $ — $ — $ 1,680,266 Inter-company revenue 14,705 35 87,357 31,158 344,685 (477,940 ) — Total revenue 704,650 947,630 94,620 66,621 344,685 (477,940 ) 1,680,266 Fuel, purchased power and cost of natural gas sold 274,363 409,603 9,340 — 151 (130,169 ) 563,288 Operations and maintenance 172,307 269,190 23,042 44,882 296,067 (293,492 ) 511,996 Depreciation, depletion and amortization 80,243 83,732 15,548 8,239 21,031 (20,547 ) 188,246 Adjusted operating income (loss) 177,737 185,105 46,690 13,500 27,436 (33,732 ) 416,736 Interest expense, net (137,102 ) Other income (expense), net 2,108 Income tax benefit (expense) (73,367 ) Income from continuing operations 208,375 (Loss) from discontinued operations, net of tax (a) (17,099 ) Net income 191,276 Net income attributable to noncontrolling interest (14,242 ) Net income available for common stock $ 177,034 ________________ (a) Discontinued operations includes oil and gas property impairments. See Note 21 . (b) Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2017, which resulted in an increase (decrease) as follows (in millions): Year ended December 31, 2017 Electric Utilities Power Generation Inter-Company Eliminations Total Inter-company revenue $ — $ 3.1 $ (3.1 ) $ — Fuel, purchased power and cost of natural gas sold 6.0 — (6.0 ) — Depreciation, depletion and amortization (13.1 ) 9.6 3.5 — Adjusted operating income (loss) $ 7.1 $ (6.5 ) $ (0.6 ) $ —

Long-Term Debt_

Long-Term Debt:	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2019 December 31, 2018 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2020 July 15, 2020 N/A — 200,000 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 2033 May 1, 2033 4.35% 400,000 400,000 Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Senior unsecured notes, due 2029 October 15, 2029 3.05% 400,000 — Senior unsecured notes, due 2049 October 15, 2049 3.88% 300,000 — Corporate term loan due 2021 (a) June 17, 2021 N/A — 300,000 Corporate term loan due 2021 June 7, 2021 2.32% 7,178 12,921 Total Corporate debt 2,632,178 2,437,921 Less unamortized debt discount (6,462 ) (5,122 ) Total Corporate debt, net 2,625,716 2,432,799 South Dakota Electric Series 94A Debt, variable rate (b) June 1, 2024 1.84% 2,855 2,855 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 2044 October 20, 2044 4.43% 85,000 85,000 Total South Dakota Electric debt 342,855 342,855 Less unamortized debt discount (82 ) (86 ) Total South Dakota Electric debt, net 342,773 342,769 Wyoming Electric Industrial development revenue bonds due 2021 (a) September 1, 2021 1.68% 7,000 7,000 Industrial development revenue bonds due 2027 (a) March 1, 2027 1.68% 10,000 10,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 Total Wyoming Electric debt 202,000 202,000 Less unamortized debt discount — — Total Wyoming Electric debt, net 202,000 202,000 Total long-term debt 3,170,489 2,977,568 Less current maturities 5,743 5,743 Less unamortized deferred financing costs (b) 24,650 20,990 Long-term debt, net of current maturities and deferred financing costs $ 3,140,096 $ 2,950,835 _______________ (a) Variable interest rate. (b) Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2019 and December 31, 2018 , respectively. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2020 $ 5,743 2021 $ 8,435 2022 $ — 2023 $ 525,000 2024 $ 2,855 Thereafter $ 2,635,000 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2019 . 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. Debt Transactions On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured noted. The debt offering consisted of $400 million of 3.05% 10 -year senior notes due October 15, 2029 and $300 million of 3.875% 30 -year senior notes due October 15, 2049 (together the “Notes”). The proceeds of the Notes were used for the following: • Repay the $400 million Corporate term loan under the Amended and Restated Credit Agreement due June 17, 2021; • Retire the $200 million 5.875% senior notes due July 15, 2020; and • Repay a portion of short-term debt. On June 17, 2019, we amended our Corporate term loan due July 30, 2020. This amendment increased total commitments to $400 million from $300 million , extended the term through June 17, 2021, and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. The net proceeds from the increase in total commitments were used to pay down short-term debt. Proceeds from the October 3, 2019 public debt offering were used to repay this term loan. On December 12, 2018, we paid off the $250 million , 2.5% senior unsecured notes due January 11, 2019. Proceeds from the November 1, 2018 Equity Unit conversion were used to pay off this debt. On August 17, 2018, we issued $400 million principal amount, 4.350% senior unsecured notes due May 1, 2033. A portion of these notes were issued in a private exchange that resulted in the retirement of all $299 million principal amount of our RSNs due 2028. The remainder of the notes were sold for cash in a public offering, with the net proceeds being used to pay down short-term debt. The issuance of the $400 million senior notes was the culmination of a series of transactions that also included the contractually required remarketing of such RSNs on behalf of the holders of our Equity Units, with the proceeds being deposited as collateral to secure the obligations of those holders under the purchase contracts included in the Equity Units (see Note 12 ). As a result of the remarketing, the annual interest rate on such RSNs was automatically reset to 4.579% (however, because the RSNs were then immediately retired, no interest accrued at this reset rate). On July 30, 2018, we amended and restated our unsecured term loan due August 2019. This amended and restated term loan, with $300 million outstanding at December 31, 2018, had a maturity date of July 30, 2020 and had substantially similar terms and covenants as the amended and restated Revolving Credit Facility. This term loan was later amended on June 17, 2019 and then repaid using proceeds from the October 3, 2019 public debt offering. Amortization Expense Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2019 2019 2018 2017 $ 24,650 $ 3,242 $ 2,829 $ 3,349 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. As of December 31, 2019 , 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, 2019 : • 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, 2019 , the restricted net assets at our Electric and Gas Utilities were approximately $156 million . •

Notes Payable_

Notes Payable:	12 Months Ended
	Dec. 31, 2019
Notes Payable [Abstract]
Notes Payable	NOTES PAYABLE We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands): December 31, 2019 December 31, 2018 Balance Outstanding Letters of Credit (a) Balance Outstanding Letters of Credit (a) Revolving Credit Facility $ — $ 30,274 $ — $ 22,311 CP Program 349,500 — 185,620 — Total $ 349,500 $ 30,274 $ 185,620 $ 22,311 _______________ (a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility. Revolving Credit Facility and CP Program On July 30, 2018, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 30, 2023 with two one year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us, with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment, to increase total commitments 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 Corporate credit rating from S&P, Fitch, and Moody's for our senior unsecured long-term debt. Based on our credit ratings, the margins for base rate borrowings, Eurodollar borrowings, and letters of credit were 0.125% , 1.125% , and 1.125% , respectively, at December 31, 2019 . Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2019 . We have 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 short-term borrowings (payments) during 2019 were $164 million . As of December 31, 2019 , the weighted average interest rate on short-term borrowings was 2.03% . Total accumulated deferred financing costs on the Revolving Credit Facility of $6.7 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See Note 6 above for additional details. Debt Covenants Under our 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 and certain guarantees issued by (ii) Capital, which includes Consolidated Indebtedness plus Net Worth, which excludes noncontrolling interest in subsidiaries. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. As of December 31, 2019, we were in compliance with these covenants.

Asset Retirement Obligations_

Asset Retirement Obligations:	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS We have identified legal retirement obligations related to reclamation of mining sites in the Mining segment and removal of fuel tanks, transformers containing polychlorinated biphenyls, and an evaporation pond at our Electric Utilities, wind turbines at our Electric Utilities and Power Generation segments, retirement of gas pipelines at our Gas Utilities and removal of asbestos at our Electric and Gas Utilities. We periodically review and update estimated costs related to these AROs. 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, 2018 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a) (b) December 31, 2019 Electric Utilities (c) $ 6,258 $ — $ — $ 385 $ 2,686 $ 9,329 Gas Utilities 34,627 — — 1,458 — 36,085 Power Generation (c) 300 3,445 — 158 836 4,739 Mining 15,615 — (380 ) 740 (1,923 ) 14,052 Total $ 56,800 $ 3,445 $ (380 ) $ 2,741 $ 1,599 $ 64,205 December 31, 2017 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (b) December 31, 2018 Electric Utilities $ 6,287 $ — $ — $ 269 $ 2 $ 6,558 Gas Utilities 33,238 152 — 1,237 — 34,627 Mining 12,499 — (4 ) 649 2,471 15,615 Total $ 52,024 $ 152 $ (4 ) $ 2,155 $ 2,473 $ 56,800 _____________________ (a) The increase in Electric Utilities Revisions to Prior Estimates was primarily driven by an increase to the estimated cost to decommission certain regulated wind farm assets. (b) The changes in the Mining Revision to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process. (c) We reclassified $0.3 million of ARO as of December 31, 2018 related to Busch Ranch I from Electric Utilities to the Power Generation segment as a result of Black Hills Electric Generation’s purchase of its 50% ownership interest in Busch Ranch I. Additional liabilities were incurred in 2019 from new wind assets. 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.

Risk Management Activities_

Risk Management Activities:	12 Months Ended
	Dec. 31, 2019
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, rate or supply. 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 several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, market speculation, pipeline constraints, and other factors that may impact natural gas supply and demand; • Interest rate risk associated with our variable debt as described in Notes 6 and 7 . 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, 2019 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 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. 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 2020 through December 2021. 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, 2019 December 31, 2018 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 1,450,000 12 4,000,000 24 Natural gas options purchased, net 3,240,000 3 4,320,000 13 Natural gas basis swaps purchased 1,290,000 12 3,960,000 24 Natural gas over-the-counter swaps, net (b) 4,600,000 24 3,660,000 24 Natural gas physical commitments, net (c) 13,548,235 12 18,325,852 30 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2019 , 1,415,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude contracts that qualify for normal purchase, normal sales exception. Based on December 31, 2019 prices, a $0.5 million gain 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. Cash Flow Hedges The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2019 , 2018 and 2017 (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, 2019 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income Interest rate swaps Interest expense $ (2,851 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold 417 Total impact from cash flow hedges $ (2,434 ) December 31, 2018 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income Interest rate swaps Interest expense $ (2,851 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold (130 ) Total impact from cash flow hedges $ (2,981 ) 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 Interest rate swaps Interest expense $ (2,941 ) Commodity derivatives Net (loss) from discontinued operations 913 Commodity derivatives Fuel, purchased power and cost of natural gas sold (243 ) Total impact from cash flow hedges $ (2,271 ) 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, 2019 , 2018 and 2017 (in thousands). December 31, 2019 December 31, 2018 December 31, 2017 Increase (decrease) in fair value: Forward commodity contracts $ (548 ) $ 983 $ 366 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,851 2,851 2,941 Forward commodity contracts (417 ) 130 (670 ) Total other comprehensive income (loss) from hedging $ 1,886 $ 3,964 $ 2,637 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 for the years ended December 31, 2019 , 2018 and 2017 (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, 2019 December 31, 2018 December 31, 2017 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 Fuel, purchased power and cost of natural gas sold $ (1,100 ) $ 1,101 $ (2,207 ) $ (1,100 ) $ 1,101 $ (2,207 ) 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 $3.3 million and $6.2 million at December 31, 2019 and 2018 , respectively.

Fair Value Measurements_

Fair Value Measurements:	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Nonrecurring Fair Value Measurement A discussion of the fair value of our investment in equity securities of a privately held oil and gas company, a Level 3 asset, is included in Note 1 . Recurring Fair Value Measurements 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 . 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, 2019 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 1,433 $ — $ (1,085 ) $ 348 Total $ — $ 1,433 $ — $ (1,085 ) $ 348 Liabilities: Commodity derivatives - Utilities $ — $ 5,254 $ — $ (2,909 ) $ 2,345 Total $ — $ 5,254 $ — $ (2,909 ) $ 2,345 As of December 31, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — 2,927 $ — $ (1,408 ) $ 1,519 Total $ — $ 2,927 $ — $ (1,408 ) $ 1,519 Liabilities: Commodity derivatives - Utilities $ — $ 6,801 $ — $ (5,794 ) $ 1,007 Total $ — $ 6,801 $ — $ (5,794 ) $ 1,007 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): December 31, Balance Sheet Location 2019 2018 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1 $ 415 Noncurrent commodity derivatives Other assets, non-current 3 18 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (490 ) (114 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (29 ) (4 ) Total derivatives designated as hedges $ (515 ) $ 315 Not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 341 $ 1,085 Noncurrent commodity derivatives Other assets, non-current 2 1 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (1,764 ) (833 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (63 ) (56 ) Total derivatives not designated as hedges $ (1,484 ) $ 197 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, 2019 and 2018 , 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, 2019 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 Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,085 $ (1,085 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 348 — 348 Total derivative assets $ 1,433 $ (1,085 ) $ 348 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 2,908 $ (2,908 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 2,345 — 2,345 Total derivative liabilities $ 5,253 $ (2,908 ) $ 2,345 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2018 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 Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,408 $ (1,408 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 1,519 — 1,519 Total derivative assets $ 2,927 $ (1,408 ) $ 1,519 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 5,794 $ (5,794 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 1,007 — 1,007 Total derivative liabilities $ 6,801 $ (5,794 ) $ 1,007

Fair Value Of Financial Instrum

Fair Value Of Financial Instruments:	12 Months Ended
	Dec. 31, 2019
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): 2019 2018 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 9,777 $ 9,777 $ 20,776 $ 20,776 Restricted cash and equivalents (a) $ 3,881 $ 3,881 $ 3,369 $ 3,369 Notes payable (b) $ 349,500 $ 349,500 $ 185,620 $ 185,620 Long-term debt, including current maturities (c) $ 3,145,839 $ 3,479,367 $ 2,956,578 $ 3,039,108 _______________ (a) Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings. 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. 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, 2019
Stockholders' Equity Note [Abstract]
Equity	EQUITY At-the-Market Equity Offering Program Our ATM equity offering program allows us to sell shares of our common stock with an aggregate value of up 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. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM equity offering program for $99 million , net of $1.2 million in issuance costs. As of December 31, 2019, all shares were settled. We did not issue any common shares under the ATM equity offering program during the twelve months ended December 31, 2018 and 2017. Equity Units On November 23, 2015, we issued 5.98 million Equity Units for total gross proceeds of $299 million . Each Equity Unit had a stated amount of $50.00 and consisted 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. On October 29, 2018, we announced the settlement rate for the stock purchase contracts that are components of the Equity Units issued on November 23, 2015. The settlement rate was based upon the minimum settlement rate, as adjusted to account for past dividends, because the average of the closing price per share of BHC common stock on the New York Stock Exchange for the 20 consecutive trading days ending on October 29, 2018 exceeded the threshold appreciation price. Each holder of the Equity Units on that date, following payment of $50.00 for each unit which it holds, received 1.0655 shares of BHC common stock for each such unit. The holders' obligations to make such payments were satisfied with proceeds generated by the successful remarketing on August 17, 2018, of the RSNs that formerly constituted a component of the Equity Units. See Note 6 for additional information. Upon settlement of all outstanding stock purchase obligations, the Company received gross proceeds of approximately $299 million in exchange for approximately 6.372 million shares of common stock. Proceeds were used to pay down the $250 million senior unsecured notes due January 11, 2019, with the balance used to pay down short-term debt. 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 672,049 shares available to grant at December 31, 2019 . 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, 2019 , total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 2 years. Stock-based compensation expense included in Operations and maintenance on the accompanying Consolidated Statements of Income was as follows for the years ended December 31 (in thousands): 2019 2018 2017 Stock-based compensation expense $ 12,095 $ 12,390 $ 7,626 Stock Options The Company has not issued any stock options since 2014 and has 14,000 stock options outstanding at December 31, 2019 . 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, 2019 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 236 $ 57.50 Granted 92 73.66 Vested (120 ) 56.33 Forfeited (16 ) 62.02 Balance at end of period 192 $ 65.66 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, were as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2019 $ 73.66 $ 8,438 2018 $ 57.31 $ 6,776 2017 $ 60.63 $ 7,909 As of December 31, 2019 , there was $9.0 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 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 $2.9 million at December 31, 2019 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, 2017 January 1, 2017 - December 31, 2019 46 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 50 0% 200% January 1, 2019 January 1, 2019 - December 31, 2021 37 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, 2019 (in thousands) (in thousands) Performance Shares balance at beginning of period 77 $ 57.66 77 Granted 20 68.72 20 Forfeited (4 ) 64.60 (4 ) Vested (26 ) 47.76 (26 ) Performance Shares balance at end of period 67 $ 64.32 67 $ 89.63 _____________________ (a) The grant date fair values for the performance shares granted in 2019 , 2018 and 2017 were determined by Monte Carlo simulation using a blended volatility of 21% , 21% and 23% , 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, 2019 $ 68.72 December 31, 2018 $ 61.82 December 31, 2017 $ 63.52 Performance plan payouts have been as follows (in thousands): Performance Period Year Paid Stock Issued Cash Paid Total Intrinsic Value January 1, 2016 to December 31, 2018 2019 44 $ 2,860 $ 5,720 January 1, 2015 to December 31, 2017 — — — January 1, 2014 to December 31, 2016 — — — On January 28, 2020 , the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2017 through December 31, 2019 performance period was at the 36.3 percentile of its peer group and confirmed a payout equal to 58.86% of target shares, valued at $2.2 million . The payout was fully accrued at December 31, 2019 . As of December 31, 2019 , there was $3.4 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 until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2019 , there were 214,967 shares of unissued stock available for future offering under the plan. 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. Noncontrolling Interest in Subsidiary Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In April 2016, Black Hills Electric Generation sold a 49.9% , noncontrolling interest in Black Hills Colorado IPP for $216 million to a third-party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric. The accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated, is specified under ASC 810. 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, 2019 , 2018 and 2017 was reduced by $14 million , $14 million , and $14 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 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 (in thousands): 2019 2018 Assets Current assets $ 13,350 $ 13,620 Property, plant and equipment of variable interest entities, net $ 193,046 $ 199,839 Liabilities Current liabilities $ 6,013 $ 5,174

Regulatory Matters_

Regulatory Matters:	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Regulatory Matters	REGULATORY MATTERS We had the following regulatory assets and liabilities as of December 31 (in thousands): 2019 2018 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 34,088 $ 29,661 Deferred gas cost adjustments (a) 1,540 3,362 Gas price derivatives (a) 3,328 6,201 Deferred taxes on AFUDC (b) 7,790 7,841 Employee benefit plans (c) 115,900 110,524 Environmental (a) 1,454 959 Loss on reacquired debt (a) 24,777 21,001 Renewable energy standard adjustment (a) 1,622 1,722 Deferred taxes on flow through accounting (c) 41,220 31,044 Decommissioning costs (a) 10,670 11,700 Gas supply contract termination (a) 8,485 14,310 Other regulatory assets (a) 20,470 45,910 Total regulatory assets 271,344 284,235 Less current regulatory assets (43,282 ) (48,776 ) Regulatory assets, non-current $ 228,062 $ 235,459 Regulatory liabilities Deferred energy and gas costs (a) $ 17,278 $ 6,991 Employee benefit plan costs and related deferred taxes (c) 43,349 42,533 Cost of removal (a) 166,727 150,123 Excess deferred income taxes (c) 285,438 310,562 TCJA revenue reserve 3,418 18,032 Other regulatory liabilities (c) 20,442 12,553 Total regulatory liabilities 536,652 540,794 Less current regulatory liabilities (33,507 ) (29,810 ) Regulatory liabilities, non-current $ 503,145 $ 510,984 __________ (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. Regulatory assets represent items we expect to recover from customers through probable future rates. Deferred Energy and Fuel Cost Adjustments - 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 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. The recovery period for these costs is less than a year. 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. The recovery period for these costs is less than a year. 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. Gas price derivatives at December 31, 2019 are hedged over a maximum forward term of two years . Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. Employee Benefit Plans - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI. Environmental - Environmental expenditures are costs associated with manufactured gas plant sites. The amortization of this asset is first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining recovery will be requested in future rate filings. Recovery has not yet been approved by the applicable commission or board and therefore, the recovery period is unknown. Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue. Renewable Energy Standard Adjustment - The renewable energy standard adjustment is associated with incentives for our Colorado Electric customers to install renewable energy equipment at their location. These incentives are recovered over time with an additional rider charged on customers’ bills. Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer in the year in which the tax benefits are realized and result in lower utility rates. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes, but are capitalized for book purposes. Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs in a regulatory asset, with recovery to be determined in a future regulatory filing. Gas Supply Contract Termination - Agreements under the previous ownership required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to distribution customers in Colorado, Nebraska, and Wyoming, which are subject to cost recovery mechanisms. The prices to be paid under these agreements varied, ranging from $6 to $8 per MMBtu at the time of acquisition, which exceeded market prices. We recorded a liability for this contract in our purchase price allocation. We were granted approval to terminate these agreements from the CPUC, NPSC and WPSC on the basis that these agreements were not beneficial to customers over the long term. We received written orders allowing us to create a regulatory asset for the net buyout costs associated with the contract termination, and recover the majority of costs from customers over a period of five years . We terminated the contract and settled the liability on April 29, 2016. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Deferred Energy and Gas Costs - Deferred energy costs and gas costs related to over-recovery of purchased power, transmission and natural gas costs. Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with accounting standards for compensation - retirement benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense. Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. TCJA Revenue Reserve - Revenue to be returned to customers as a result of the TCJA. See Note 15 for additional information. Regulatory Matters Electric Utilities Regulatory Activity South Dakota Electric Settlement On January 7, 2020, South Dakota Electric received approval from the SDPUC on a settlement agreement to extend the 6 -year moratorium period by an additional 3 years to June 30, 2026. Also, as part of the settlement, we withdrew our application for deferred accounting treatment and expensed $5.4 million of development costs related to projects we no longer intend to construct. This settlement amends a previous agreement approved by the SDPUC on June 16, 2017, whereby South Dakota Electric would not increase base rates, absent an extraordinary event, for a 6 year moratorium period effective July 1, 2017. The moratorium period also includes suspension of both the TFA and EIA. FERC Formula Rate 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, 2019 the annual revenue requirement increased by $1.9 million and included estimated weighted average capital additions of $31 million for 2018 and 2019 combined. The annual transmission revenue requirement has a true up mechanism that is posted in June of each year. South Dakota Electric and Wyoming Electric Renewable Ready In July 2019, South Dakota Electric and Wyoming Electric received approvals for the Renewable Ready program and related jointly-filed CPCN to construct Corriedale. The wind project will be jointly owned by the two electric utilities to deliver renewable energy for large commercial, industrial and governmental agency customers. In November 2019, South Dakota Electric received approval from the SDPUC to increase the offering under the program by 12.5 MW. The two electric utilities also received a determination from the WPSC to increase the project to 52.5 MW. The $79 million project is expected to be in service by year-end 2020. Black Hills Wyoming and Wyoming Electric Wygen 1 FERC Filing On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for an additional 20 years to December 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC. Wyoming Electric Blockchain Tariff On April 30, 2019, the WPSC approved Wyoming Electric’s application for a new Blockchain Interruptible Service Tariff. The utility has partnered with the economic development organization for City of Cheyenne and Laramie County to actively recruit blockchain customers to the state. This tariff is complementary to recently enacted Wyoming legislation supporting the development of blockchain within the state. PCA Settlement On October 31, 2018, Wyoming Electric received approval from the WPSC for a comprehensive, multi-year settlement regarding its PCA Application filed earlier in 2018. Wyoming Electric’s PCA permits the recovery of costs associated with fuel, purchased electricity and other specified costs, including the portion of the company’s energy that is delivered from the Wygen I PPA with Black Hills Wyoming. Wyoming Electric was to provide a total of $7.0 million in customer credits through the PCA mechanism in 2018, 2019 and 2020 to resolve all outstanding issues relating to its current and prior PCA filings. The settlement also stipulated the adjustment for the variable cost segment of the Wygen I PPA with Wyoming Electric will escalate by 3.0% annually through 2022, providing price certainty for Wyoming Electric and its customers. Gas Utilities Regulatory Activity Arkansas Gas Rate Review On October 5, 2018, Arkansas Gas received approval from the APSC for a general rate increase. The new rates were to generate approximately $12 million of new annual revenue. The APSC’s approval also allowed Arkansas Gas to include $11 million of revenue that was being collected through certain rider mechanisms in the new base rates. The new revenue increase was based on a return on equity of 9.61% and a capital structure of 49.1% equity and 50.9% debt. New rates, inclusive of customer benefits related to the TCJA, were effective October 15, 2018. Colorado Gas Jurisdictional Consolidation and Rate Review On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. The rate review requested $2.5 million in new revenue to recover investments in safety, reliability and system integrity. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On December 27, 2019, the ALJ issued a recommended decision denying the company’s plan to consolidate rate territories and recommending a rate decrease. Colorado Gas has filed exceptions to the ALJ’s recommended decision. A decision by the CPUC is expected by the end of March 2020. Legal consolidation was previously approved by the CPUC in late 2018 and completed in early 2019. Nebraska Gas Jurisdictional Consolidation and Rate Review On October 29, 2019, Nebraska Gas received approval from the NPSC to merge its two gas distribution companies. Legal consolidation was effective January 1, 2020, and a rate review is expected to be filed by mid-year 2020 to consolidate the rates, tariffs and services. SSIR On June 1, 2018, Nebraska Gas Distribution filed an application with the NPSC requesting a continuation of the SSIR beyond the expiration date of October 31, 2019. On September 5, 2018, the NPSC approved continuation of the SSIR tariff to December 31, 2020. The SSIR provides approximately $6.0 million of revenue annually on investments made prior to January 1, 2018, with investments after that date to be recovered through other methods. If a base rate review is filed prior to expiration of the rider, that rate request will include the remaining investment to be recovered. 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. Wyoming Gas Jurisdictional Consolidation and Rate Review On December 11, 2019, Wyoming Gas received approval from the WPSC to consolidate the rates, tariffs and services of its four existing gas distribution territories. A new, single statewide rate structure will be effective March 1, 2020. New rates are expected to generate $13 million in new revenue based on a return on equity of 9.40% and a capital structure of 50.23% equity and 49.77% debt. The approval also allows for a rider to recover integrity investments for system safety and reliability.

Leases_

Leases:	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Operating Leases	LEASES Lessee We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than 1 year to 36 years , including options to extend that are reasonably certain to be exercised. The components of lease expense for the year ended December 31 were as follows (in thousands) : Income Statement Location 2019 Operating lease cost Operations and maintenance $ 1,456 Finance lease cost: Amortization of right-of-use asset Depreciation, depletion and amortization 100 Interest on lease liabilities Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) 19 Total lease cost $ 1,575 Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2019 Assets: Operating lease assets Other assets, non-current $ 4,629 Finance lease assets Other assets, non-current 465 Total lease assets $ 5,094 Liabilities: Current: Operating leases Accrued liabilities $ 1,179 Finance lease Accrued liabilities 109 Noncurrent: Operating leases Other deferred credits and other liabilities 3,821 Finance lease Other deferred credits and other liabilities 364 Total lease liabilities $ 5,473 Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,263 Operating cash flows from finance lease $ 19 Financing cash flows from finance lease $ 93 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 2,801 Finance lease $ 67 Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2019 Weighted average remaining lease term (years): Operating leases 8 years Finance lease 4 years Weighted average discount rate: Operating leases 4.27 % Finance lease 4.19 % As of December 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases Finance Lease Total 2020 1,018 126 1,144 2021 865 126 991 2022 743 126 869 2023 718 126 844 2024 714 10 724 Thereafter 2,009 — 2,009 Total lease payments (a) $ 6,067 $ 514 $ 6,581 Less imputed interest 1,067 41 1,108 Present value of lease liabilities $ 5,000 $ 473 $ 5,473 _______________ (a) Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance. As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands): Operating Leases 2019 $ 1,052 2020 464 2021 344 2022 224 2023 216 Thereafter 1,776 Total lease payments $ 4,076
Lessee, Finance Leases	LEASES Lessee We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than 1 year to 36 years , including options to extend that are reasonably certain to be exercised. The components of lease expense for the year ended December 31 were as follows (in thousands) : Income Statement Location 2019 Operating lease cost Operations and maintenance $ 1,456 Finance lease cost: Amortization of right-of-use asset Depreciation, depletion and amortization 100 Interest on lease liabilities Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) 19 Total lease cost $ 1,575 Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2019 Assets: Operating lease assets Other assets, non-current $ 4,629 Finance lease assets Other assets, non-current 465 Total lease assets $ 5,094 Liabilities: Current: Operating leases Accrued liabilities $ 1,179 Finance lease Accrued liabilities 109 Noncurrent: Operating leases Other deferred credits and other liabilities 3,821 Finance lease Other deferred credits and other liabilities 364 Total lease liabilities $ 5,473 Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,263 Operating cash flows from finance lease $ 19 Financing cash flows from finance lease $ 93 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 2,801 Finance lease $ 67 Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2019 Weighted average remaining lease term (years): Operating leases 8 years Finance lease 4 years Weighted average discount rate: Operating leases 4.27 % Finance lease 4.19 % As of December 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases Finance Lease Total 2020 1,018 126 1,144 2021 865 126 991 2022 743 126 869 2023 718 126 844 2024 714 10 724 Thereafter 2,009 — 2,009 Total lease payments (a) $ 6,067 $ 514 $ 6,581 Less imputed interest 1,067 41 1,108 Present value of lease liabilities $ 5,000 $ 473 $ 5,473 _______________ (a) Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance. As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands): Operating Leases 2019 $ 1,052 2020 464 2021 344 2022 224 2023 216 Thereafter 1,776 Total lease payments $ 4,076
Lessor, Operating Leases	LEASES Lessee We lease from third parties certain office and operation center facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than 1 year to 36 years , including options to extend that are reasonably certain to be exercised. The components of lease expense for the year ended December 31 were as follows (in thousands) : Income Statement Location 2019 Operating lease cost Operations and maintenance $ 1,456 Finance lease cost: Amortization of right-of-use asset Depreciation, depletion and amortization 100 Interest on lease liabilities Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) 19 Total lease cost $ 1,575 Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2019 Assets: Operating lease assets Other assets, non-current $ 4,629 Finance lease assets Other assets, non-current 465 Total lease assets $ 5,094 Liabilities: Current: Operating leases Accrued liabilities $ 1,179 Finance lease Accrued liabilities 109 Noncurrent: Operating leases Other deferred credits and other liabilities 3,821 Finance lease Other deferred credits and other liabilities 364 Total lease liabilities $ 5,473 Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,263 Operating cash flows from finance lease $ 19 Financing cash flows from finance lease $ 93 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 2,801 Finance lease $ 67 Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2019 Weighted average remaining lease term (years): Operating leases 8 years Finance lease 4 years Weighted average discount rate: Operating leases 4.27 % Finance lease 4.19 % As of December 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases Finance Lease Total 2020 1,018 126 1,144 2021 865 126 991 2022 743 126 869 2023 718 126 844 2024 714 10 724 Thereafter 2,009 — 2,009 Total lease payments (a) $ 6,067 $ 514 $ 6,581 Less imputed interest 1,067 41 1,108 Present value of lease liabilities $ 5,000 $ 473 $ 5,473 _______________ (a) Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance. As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands): Operating Leases 2019 $ 1,052 2020 464 2021 344 2022 224 2023 216 Thereafter 1,776 Total lease payments $ 4,076 Lessor We lease to third parties certain generating station ground leases, communication tower sites, and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 35 years . The components of lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2019 Operating lease income Revenue $ 2,306 As of December 31, 2019, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2020 2,227 2021 1,857 2022 1,793 2023 1,799 2024 1,743 Thereafter 53,739 Total lease receivables $ 63,158

Income Taxes_

Income Taxes:	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES TCJA 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% . As such, the Company 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 federal and state utility commissions, 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 at December 31, 2017, 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. During the year ended December 31, 2018 we recorded approximately $11 million of additional regulatory liability associated with TCJA related items primarily related to property, completing the revaluation of deferred taxes pursuant to the TCJA. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. As of December 31, 2019, the Company has amortized $6.5 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2019, but is awaiting resolution of the treatment of these amounts in future regulatory proceedings, has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. Tax benefit related to legal entity restructuring As part of the Company’s ongoing efforts to continue to integrate the legal entities that the Company has acquired in recent years, certain legal entity restructuring transactions occurred on March 31, 2018 and December 31, 2018. As a result of these transactions, additional deferred income tax assets of $73 million , related to goodwill that is amortizable for tax purposes, were recorded and deferred tax benefits of $73 million were recorded to income tax benefit (expense) on the Consolidated Statements of Income. Due to this being a common control transaction, it had no effect on the other assets and liabilities of these entities. Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2019 2018 2017 Current: Federal $ (8,578 ) $ 325 $ (6,193 ) State 138 247 (1,432 ) (8,440 ) 572 (7,625 ) Deferred: Federal 34,551 (25,022 ) 76,522 State 3,469 783 4,470 38,020 (24,239 ) 80,992 $ 29,580 $ (23,667 ) $ 73,367 Included in discontinued operations is a tax benefit of $2.6 million and $8.4 million for 2018 and 2017 , respectively. The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): 2019 2018 Deferred tax assets: Regulatory liabilities $ 89,754 $ 92,966 State tax credits 23,261 20,466 Federal net operating loss 120,624 139,371 State net operating loss 13,537 16,647 Partnership 14,030 16,032 Credit Carryovers 27,139 23,124 Other deferred tax assets (a) 33,395 39,349 Less: Valuation allowance (12,063 ) (11,809 ) Total deferred tax assets 309,677 336,146 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (533,292 ) (529,338 ) Regulatory assets (23,586 ) (32,324 ) Goodwill (b) (15,875 ) (602 ) State deferred tax liability (72,911 ) (64,095 ) Other deferred tax liabilities (24,732 ) (21,118 ) Total deferred tax liabilities (670,396 ) (647,477 ) Net deferred tax liability $ (360,719 ) $ (311,331 ) _______________ (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) Legal entity restructuring - see above. The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2019 2018 2017 Federal statutory rate 21.0 % 21.0 % 35.0 % State income tax (net of federal tax effect) 1.5 2.3 0.9 Non-controlling interest (a) (1.2 ) (1.3 ) (1.8 ) Tax credits (3.9 ) (2.0 ) (1.7 ) Flow-through adjustments (b) (2.4 ) (1.6 ) (1.1 ) Jurisdictional consolidation project (d) — (28.5 ) — Other tax differences (1.6 ) (0.1 ) (2.6 ) TCJA corporate rate reduction (c) — 1.6 (2.7 ) Amortization of excess deferred income tax expense (e) (1.2 ) (0.7 ) — 12.2 % (9.3 )% 26.0 % _________________________ (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. During the year ended December 31, 2018, we recorded $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded $7.6 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. (d) Legal entity restructuring - see above. (e) Primarily TCJA - see above. At December 31, 2019 , 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 $ 575,457 2022 to 2037 State Net Operating Loss Carryforward (a) $ 224,716 2020 to 2040 _________________________ (a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes. As of December 31, 2019 , we had a $0.5 million valuation allowance against the state NOL carryforwards. Our 2019 analysis of the ability to utilize such NOLs resulted in no increase in the valuation allowance. 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, 2017 $ 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 Additions for prior year tax positions 251 Reductions for prior year tax positions (417 ) Additions for current year tax positions 486 Settlements — Ending balance at December 31, 2018 3,583 Additions for prior year tax positions 446 Reductions for prior year tax positions (862 ) Additions for current year tax positions 998 Settlements — Ending balance at December 31, 2019 $ 4,165 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $0.3 million . We recognized no interest expense associated with income taxes for the years ended December 31, 2019 , December 31, 2018 and December 31, 2017 . We had no accrued interest (before tax effect) associated with income taxes at December 31, 2019 and December 31, 2018 . The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. Black Hills Gas, Inc. and subsidiaries, which filed a separate consolidated tax return from BHC and subsidiaries through March 31, 2018, is under examination by the IRS for 2014. BHC is no longer subject to examination for tax years prior to 2016. As of December 31, 2019 , 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, 2020 . State tax credits have been generated and are available to offset future state income taxes. At December 31, 2019 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year ITC $ 23,060 2023 to 2041 Research and development $ 201 No expiration As of December 31, 2019 , we had a $9 million valuation allowance against the state tax credit carryforwards. 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, 2019
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 for the period, net of tax (in thousands): Location on the Consolidated Statements of Income Amount Reclassified from AOCI December 31, 2019 December 31, 2018 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,851 ) $ (2,851 ) Commodity contracts Fuel, purchased power and cost of natural gas sold 417 (130 ) (2,434 ) (2,981 ) Income tax Income tax benefit (expense) 611 630 Total reclassification adjustments related to cash flow hedges, net of tax $ (1,823 ) $ (2,351 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 77 $ 178 Actuarial gain (loss) Operations and maintenance (745 ) (2,487 ) (668 ) (2,309 ) Income tax Income tax benefit (expense) (453 ) 543 Total reclassification adjustments related to defined benefit plans, net of tax $ (1,121 ) $ (1,766 ) Total reclassifications $ (2,944 ) $ (4,117 ) 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, 2018 $ (17,307 ) $ 328 $ (9,937 ) $ (26,916 ) Other comprehensive income (loss) before reclassifications — (422 ) (6,261 ) (6,683 ) Amounts reclassified from AOCI 2,185 (362 ) 1,121 2,944 As of December 31, 2019 $ (15,122 ) $ (456 ) $ (15,077 ) $ (30,655 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Other comprehensive income (loss) before reclassifications — 755 2,155 2,910 Amounts reclassified from AOCI 2,252 99 1,766 4,117 Reclassification to regulatory asset — — 6,519 6,519 Reclassification of certain tax effects from AOCI 22 (8 ) 726 740 As of December 31, 2018 $ (17,307 ) $ 328 $ (9,937 ) $ (26,916 )

Supplemental Disclosure of Cash

Supplemental Disclosure of Cash flow Information:	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Years ended December 31, 2019 2018 2017 (in thousands) Non-cash investing activities and financing from continuing operations - Accrued property, plant and equipment purchases at December 31 $ 91,491 $ 69,017 $ 28,191 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 5,044 $ 2,625 $ 3,198 Cash (paid) refunded during the period for continuing operations- Interest (net of amounts capitalized) $ (131,774 ) $ (137,965 ) $ (132,428 ) Income taxes (paid) refunded $ 4,682 $ (14,730 ) $ 1,775

Employee Benefit Plans_

Employee Benefit Plans:	12 Months Ended
	Dec. 31, 2019
Defined Benefit Plan [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS Defined Contribution Plans We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company. Defined Benefit Pension Plan We have one defined benefit pension 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. 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 determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns, and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2019 , the expected rate of return on pension plan assets was based on the targeted asset allocation range of 29% to 37% return-seeking assets and 63% to 71% liability-hedging assets. 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: 2019 2018 Equity 20% 17% Real estate 3 4 Fixed income 71 71 Cash 1 3 Hedge funds 5 5 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 funded on a cash basis as benefits are paid. Non-pension Defined Benefit Postretirement Healthcare Plan BHC sponsors a retiree healthcare plan (Healthcare Plan) 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 Plan for participating business units are pre-funded via VEBA trusts. Pre-65 retirees as well as a grandfathered group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for Medicare-eligible retirees is provided through an individual market healthcare exchange. Plan Assets We fund the Healthcare Plan on a cash basis as benefits are paid. The Black Hills Corporation Retiree Medical Plan provides for partial pre-funding via VEBA trusts. 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, Iowa and Kansas. We do not pre-fund the Healthcare Plan for those employees outside Arkansas, Iowa and Kansas. 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): 2019 2018 Defined Contribution Plan Company retirement contributions $ 9,714 $ 8,766 Company matching contributions $ 14,558 $ 13,559 2019 2018 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 12,700 Non-Pension Defined Benefit Postretirement Healthcare Plan $ 7,033 $ 5,298 Supplemental Non-Qualified Defined Benefit Plans $ 2,344 $ 2,073 While we do not have required contributions, we expect to make approximately $13 million in contributions to our Pension Plan in 2020 . 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, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 60 $ — $ 60 $ — $ 60 Common Collective Trust - Cash and Cash Equivalents — 7,054 — 7,054 — 7,054 Common Collective Trust - Equity — 87,106 — 87,106 — 87,106 Common Collective Trust - Fixed Income — 306,275 — 306,275 — 306,275 Common Collective Trust - Real Estate — — — — 14,239 14,239 Hedge Funds — — — — 19,550 19,550 Total investments measured at fair value $ — $ 400,495 $ — $ 400,495 $ 33,789 $ 434,284 Pension Plan December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,867 $ — $ 1,867 $ — $ 1,867 Common Collective Trust - Cash and Cash Equivalents — 9,923 — 9,923 — 9,923 Common Collective Trust - Equity — 67,457 — 67,457 — 67,457 Common Collective Trust - Fixed Income — 279,148 — 279,148 — 279,148 Common Collective Trust - Real Estate — 67 — 67 13,551 13,618 Hedge Funds — — — — 18,783 18,783 Total investments measured at fair value $ — $ 358,462 $ — $ 358,462 $ 32,334 $ 390,796 _____________ (a) Certain investments that are measured at fair value using 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 Plan December 31, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,305 $ — $ — $ 8,305 $ 8,305 Total investments measured at fair value $ 8,305 $ — $ — $ 8,305 $ 8,305 Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 4,873 $ — $ — $ 4,873 $ 4,873 Equity Securities 1,005 — — 1,005 1,005 Intermediate-term Bond — 2,284 — 2,284 2,284 Total investments measured at fair value $ 5,878 $ 2,284 $ — $ 8,162 $ 8,162 Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows: 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. Some of 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. 20% of the shares may be redeemed at the end of each month with a 10 -day notice and full redemptions are available at the end of each quarter with 30 -day notice and is limited to a percentage of the total net assets 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. 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 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. 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: Benefit Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31 (in thousands), 2019 2018 2019 2018 2019 2018 Change in benefit obligation: Projected benefit obligation at beginning of year $ 445,381 $ 474,725 $ 43,010 $ 45,112 $ 60,817 $ 69,339 Service cost 5,383 6,834 4,995 1,764 1,815 2,291 Interest cost 17,374 15,470 1,295 1,170 2,247 2,085 Actuarial (gain) loss 56,384 (31,340 ) 7,132 (2,963 ) 5,976 (9,045 ) Benefits paid (39,146 ) (20,308 ) (2,344 ) (2,073 ) (7,033 ) (5,298 ) Plan participants’ contributions — — — — 1,455 1,445 Projected benefit obligation at end of year $ 485,376 $ 445,381 $ 54,088 $ 43,010 $ 65,277 $ 60,817 Employee Benefit Plan Assets Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan (a) As of December 31 (in thousands), 2019 2018 2019 2018 2019 2018 Change in fair value of plan assets: Beginning fair value of plan assets $ 390,796 $ 416,343 $ — $ — $ 8,162 $ 8,621 Investment income (loss) 69,934 (17,939 ) — — 260 (149 ) Employer contributions 12,700 12,700 2,344 2,073 5,461 3,543 Retiree contributions — — — — 1,455 1,445 Benefits paid (39,146 ) (20,308 ) (2,344 ) (2,073 ) (7,033 ) (5,298 ) Ending fair value of plan assets $ 434,284 $ 390,796 $ — $ — $ 8,305 $ 8,162 ____________________ (a) Assets of VEBA trusts. 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 Plan 2019 2018 2019 2018 2019 2018 Regulatory assets $ 88,471 $ 82,919 $ — $ — $ 11,670 $ 6,655 Current liabilities $ — $ — $ 1,420 $ 1,463 $ 4,802 $ 3,885 Non-current assets $ — $ — $ — $ — $ — $ 249 Non-current liabilities $ 51,093 $ 54,585 $ 51,243 $ 41,547 $ 52,136 $ 49,015 Regulatory liabilities $ 3,524 $ 4,620 $ — $ — $ 4,088 $ 5,207 Accumulated Benefit Obligation Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31 (in thousands) 2019 2018 2019 2018 2019 2018 Accumulated Benefit Obligation $ 470,615 $ 428,851 $ 49,241 $ 40,530 $ 65,277 $ 60,817 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 Plan 2019 2018 2017 2019 2018 2017 2019 2018 2017 Service cost $ 5,383 $ 6,834 $ 7,034 $ 4,995 $ 1,764 $ 1,546 $ 1,815 $ 2,291 $ 2,300 Interest cost 17,374 15,470 15,520 1,295 1,170 1,276 2,247 2,085 2,141 Expected return on assets (24,401 ) (24,741 ) (24,517 ) — — — (230 ) (315 ) (315 ) Net amortization of prior service cost 26 58 58 2 2 2 (398 ) (398 ) (411 ) Recognized net actuarial loss (gain) 3,763 8,632 4,007 535 1,000 1,001 — 216 499 Net periodic expense $ 2,145 $ 6,253 $ 2,102 $ 6,827 $ 3,936 $ 3,825 $ 3,434 $ 3,879 $ 4,214 For the years ended December 31, 2019 and 2018, service costs were recorded in Operations and maintenance expense while non-service costs were recorded in Other expense on the Consolidated Statements of Income. For the year ended December 31, 2017, service costs and non-service costs were recorded in Operations and maintenance expense. Because non-service costs were not considered material for the year ended December 31, 2017, they were not reclassified on the Consolidated Statements of Income. 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 Plan 2019 2018 2019 2018 2019 2018 Net (gain) loss $ 5,322 $ 11,967 $ 9,893 $ 4,668 $ 90 $ 860 Prior service cost (gain) — 1 2 3 (230 ) (317 ) Reclassification of certain tax effects from AOCI — (594 ) — (87 ) — (45 ) Reclassification to regulatory asset — (5,600 ) — — — (919 ) Total AOCI $ 5,322 $ 5,774 $ 9,895 $ 4,584 $ (140 ) $ (421 ) Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine benefit obligations: 2019 2018 2017 2019 2018 2017 2019 2018 2017 Discount rate 3.27 % 4.40 % 3.71 % 3.14 % 4.34 % 3.56 % 3.15 % 4.28 % 3.60 % Rate of increase in compensation levels 3.49 % 3.52 % 3.43 % 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 Plan Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2019 2018 2017 2019 2018 2017 2019 2018 2017 Discount rate (a) 4.40 % 3.71 % 4.27 % 4.34 % 3.67 % 4.02 % 4.28 % 3.60 % 4.05 % Expected long-term rate of return on assets (b) 6.00 % 6.25 % 6.75 % N/A N/A N/A 3.00 % 3.93 % 3.88 % Rate of increase in compensation levels 3.52 % 3.43 % 3.47 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 3.27% for the calculation of the 2020 net periodic pension costs. (b) The expected rate of return on plan assets is 5.25% for the calculation of the 2020 net periodic pension cost. The healthcare benefit obligation was determined at December 31 as follows: 2019 2018 Trend Rate - Medical Pre-65 for next year - All Plans 6.40% 6.70% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2027 Post-65 for next year - All Plans 4.92% 4.94% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2028 2026 The following benefit payments to employees, 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 Plan 2020 $ 24,586 $ 1,420 $ 5,919 2021 $ 25,774 $ 1,786 $ 5,974 2022 $ 26,728 $ 2,167 $ 5,790 2023 $ 27,795 $ 2,223 $ 5,521 2024 $ 28,547 $ 2,412 $ 5,329 2025-2029 $ 145,426 $ 14,689 $ 23,030

Commitments And Contingencies_

Commitments And Contingencies:	12 Months Ended
	Dec. 31, 2019
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: • Colorado Electric’s PPA with PRPA to purchase up to 60 MW of wind energy upon construction of a new wind project, which is expected in mid-2020. This agreement will expire May 31, 2030 . • Colorado Electric’s PPA with PRPA to purchase 25 MW of unit contingent energy. This agreement will expire June 30, 2024 . • 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 expiring December 31, 2023 . The agreement provides 50 MW of capacity and energy to be transmitted annually by PacifiCorp. • South Dakota Electric’s PPA with PRPA to purchase up to 12 MW of wind energy through PRPA’s agreement with Silver Sage. This agreement will expire September 30, 2029 . • Wyoming Electric’s PPA with Happy Jack, expiring September 3, 2028 , provides up to 30 MW of wind energy. Under a separate intercompany agreement, Wyoming Electric sells 50% of the facility output to South Dakota Electric. • Wyoming Electric’s PPA with Silver Sage, 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. • 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. Costs under these power purchase contracts for the years ended December 31 were as follows (in thousands): 2019 2018 2017 Colorado Electric PPA with PRPA - Unit Contingent Energy $ 1,802 $ — $ — Colorado Electric PPA Busch Ranch I (a) $ — $ — $ 1,966 South Dakota Electric PPA with PacifiCorp $ 7,477 $ 13,681 $ 13,218 South Dakota Electric Transmission services agreement with PacifiCorp $ 1,741 $ 1,742 $ 1,671 South Dakota Electric PPA with PRPA $ 688 $ 223 $ — Wyoming Electric PPA with Happy Jack $ 3,936 $ 3,884 $ 3,846 Wyoming Electric PPA with Silver Sage $ 5,366 $ 5,376 $ 4,934 ________________ (a) On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm. Power Purchase Agreements - Related Party On November 26, 2019, Black Hills Electric Generation completed and placed in service Busch Ranch II. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric under a new PPA, which expires in November 2044. On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest in Busch Ranch I. Black Hills Electric Generation provides its 14.5 MW share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037 . 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. Effective January 1, 2019, we changed how we account for this PPA at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information. 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, 2019 , the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): NNG-Ventura NWPL-Wyoming 2020 3,660,000 1,520,000 2021 3,650,000 1,510,000 2022 1,810,000 1,510,000 2023 0 1,510,000 2024 0 910,000 Thereafter 0 0 Purchases under these contracts totaled $6.7 million , $27 million and $65 million for 2019 , 2018 and 2017 , respectively. The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and natural gas transportation and storage agreements (in thousands): Power purchase and transmission services agreements Natural gas transportation and storage agreements 2020 $ 25,476 $ 156,297 2021 $ 11,678 $ 148,149 2022 $ 11,678 $ 122,340 2023 $ 11,678 $ 93,905 2024 $ 2,738 $ 51,360 Thereafter $ — $ 126,147 Future Purchase Agreement - Related Party Wyoming Electric has a PPA with Black Hills Wyoming expiring on December 31, 2022, which provides 60 MW of unit-contingent capacity and energy from Black Hills Wyoming’s Wygen I facility. On August 2, 2019, Black Hills Wyoming and Wyoming Electric jointly filed a request with FERC for approval of a new 60 MW PPA. The agreement would fulfill the capacity need for Wyoming Electric at the expiration of the current agreement on December 31, 2022. If approved, Black Hills Wyoming will continue to deliver 60 MW of energy to Wyoming Electric from its Wygen I power plant starting January 1, 2023, and continuing for an additional 20 years to December 31, 2042. On December 23, 2019, the Company filed a response to questions from the FERC and awaits a decision from FERC. 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, South Dakota Electric will provide MDU 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 provide 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, South Dakota Electric 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 is renewed annually on September 3, South Dakota Electric will also provide the City of Gillette their operating component of spinning reserves. • South Dakota Electric has an amended agreement, effective January 1, 2019, to supply up to 20 MW of energy and capacity to MEAN under a contract that expires May 31, 2028 . The contract terms are from June 1 through May 31 for each interval listed below. This contract is unit-contingent based on the availability of our Neil Simpson II and Wygen III plants, with decreasing capacity purchased over the term of the agreement. The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: Contract Years Total Contract Capacity Contingent Capacity Amounts on Wygen III Contingent Capacity Amounts on Neil Simpson II 2019-2020 15 MW 10 MW 5 MW 2020-2022 15 MW 7 MW 8 MW 2022-2023 15 MW 8 MW 7 MW 2023-2028 10 MW 5 MW 5 MW • South Dakota Electric has an agreement that expires December 31, 2021 to provide 50 MW of energy to Macquarie Energy, LLC during heavy and light load timing intervals. 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. 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 our land leases for our wind generation facilities, we are required to reclaim all land where we have placed wind turbines. The reclamation liabilities are 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 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 In 2008, we acquired whole and partial liabilities for 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 $1.1 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 $1.5 million regulatory asset for manufactured gas processing sites; see Note 13 for additional information. As of December 31, 2019 , our estimated liabilities for Iowa’s manufactured gas processing site currently range from approximately $2.6 million to $10 million for which we had $2.6 million accrued for remediation of the site as of December 31, 2019 included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. 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. For additional information, see Environmental Matters in Item 1 of 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, 2019
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, 2019 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 55,527 Ongoing Contract performance guarantee (b) 46,831 May 2020 $ 102,358 _______________________ (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. (b) BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of Busch Ranch II. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations.

Discontinued Operations_

Discontinued Operations:	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS Results of operations for discontinued operations were classified as Net (loss) from discontinued operations in the accompanying Consolidated Statements of Income. Prior periods relating to our discontinued operations were 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. We completed the divestiture in 2018. In 2017, 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 fourth quarter 2017 sale of our Powder River Basin assets and pending sale transactions of our other properties. We believe that the estimates used in calculating the fair value of our assets and liabilities held for sale were 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 a pre-tax write down of $20 million . There were no adjustments made to the fair value of our held for sale liabilities. For the year ended December 31, 2018, we recorded $3.3 million of expenses comprised of royalty payments and reclamation costs related to final closing on the sale of oil and gas assets. 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, 2018 December 31, 2017 Revenue $ 5,897 $ 25,382 Operations and maintenance 11,014 22,872 Loss on sale of assets 3,259 — Depreciation, depletion and amortization 1,300 7,521 Impairment of long-lived assets — 20,385 Total operating expenses 15,573 50,778 Operating (loss) (9,676 ) (25,396 ) Interest income (expense), net (19 ) 181 Other income (expense), net 190 (297 ) Income tax benefit 2,618 8,413 Net (loss) from discontinued operations $ (6,887 ) $ (17,099 )

Quarterly Historical Data (Unau

Quarterly Historical Data (Unaudited):	12 Months Ended
	Dec. 31, 2019
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 2019 and 2018 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2019 Revenue $ 597,810 $ 333,888 $ 325,548 $ 477,654 Operating income $ 160,131 $ 54,001 $ 70,551 $ 121,359 Income from continuing operations $ 107,362 $ 17,693 $ 15,395 $ 72,872 (Loss) from discontinued operations $ — $ — $ — $ — Net income attributable to noncontrolling interest $ (3,554 ) $ (3,110 ) $ (3,655 ) $ (3,693 ) Net income available for common stock $ 103,808 $ 14,583 $ 11,740 $ 69,179 Amounts attributable to common shareholders: Net income from continuing operations $ 103,808 $ 14,583 $ 11,740 $ 69,179 Net (loss) from discontinued operations — — — — Net income available for common stock $ 103,808 $ 14,583 $ 11,740 $ 69,179 Income per share for continuing operations - Basic $ 1.73 $ 0.24 $ 0.19 $ 1.13 (Loss) per share for discontinued operations - Basic — — — — Earnings per share - Basic $ 1.73 $ 0.24 $ 0.19 $ 1.13 Income per share for continuing operations - Diluted $ 1.73 $ 0.24 $ 0.19 $ 1.13 (Loss) per share for discontinued operations - Diluted — — — — Earnings per share - Diluted $ 1.73 $ 0.24 $ 0.19 $ 1.13 Included within the Income (loss) from continuing operations in the third quarter of 2019 is $15 million non-cash after-tax impairment of our investment in equity securities of a privately held oil and gas company. First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2018 Revenue $ 575,389 $ 355,704 $ 321,979 $ 501,196 Operating income $ 148,274 $ 69,551 $ 65,085 $ 114,127 Income from continuing operations $ 138,977 $ 27,167 $ 21,801 $ 91,604 (Loss) from discontinued operations $ (2,343 ) $ (2,427 ) $ (857 ) $ (1,260 ) Net income attributable to noncontrolling interest $ (3,630 ) $ (2,823 ) $ (3,994 ) $ (3,773 ) Net income available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Amounts attributable to common shareholders: Net income from continuing operations $ 135,347 $ 24,344 $ 17,807 $ 87,831 Net (loss) from discontinued operations (2,343 ) (2,427 ) (857 ) (1,260 ) Net income available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Income per share for continuing operations - Basic $ 2.54 $ 0.46 $ 0.33 $ 1.52 (Loss) per share for discontinued operations - Basic (0.05 ) (0.05 ) (0.02 ) (0.02 ) Earnings per share - Basic $ 2.49 $ 0.41 $ 0.32 $ 1.50 Income per share for continuing operations - Diluted $ 2.50 $ 0.45 $ 0.32 $ 1.51 (Loss) per share for discontinued operations - Diluted (0.04 ) (0.05 ) (0.02 ) (0.02 ) Earnings per share - Diluted $ 2.46 $ 0.40 $ 0.31 $ 1.49 Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million , respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring.

Business Description (Policies)

Business Description (Policies)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Segment Reporting	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 Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Most 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 Colorado, Iowa and Wyoming. Our Mining segment, which is conducted through WRDC, engages in 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. We completed the divestiture of our Oil and Gas segment in 2018. The Oil and Gas segment assets and liabilities were classified as held for sale and the results of operations were shown in income (loss) from discontinued operations, other than certain general and administrative costs and interest expense which did not meet the criteria for income (loss) from discontinued operations in 2018 or 2017. 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. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 5 . Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account 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	Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and 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 and Restricted Cash	Cash and Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified 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 Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal. 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.
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.
Investments	Investments In February 2018, we made a contribution of $28 million of assets in exchange for equity securities in a privately held oil and gas company as we divested of our Oil and Gas segment. The carrying value of our investment in the equity securities was recorded at cost. We review this investment on a periodic basis to determine whether a significant event or change in circumstances has occurred that may have an adverse effect on the value of the investment. During the third quarter of 2019, we assessed our investment for impairment as a result of a deterioration in earnings performance of the privately held oil and gas company and an adverse change in future natural gas prices. We engaged a third-party valuation consultant to estimate the fair value of our investment. The valuation was primarily based on an income approach but also considered a market valuation approach. The significant inputs used to estimate the fair value were the oil and gas reserve quantities and values utilizing forward market price curves, industry standard reserve adjustment factors and a discount rate of 10% . Based on the results of the valuation, we concluded that the carrying value of the investment exceeded fair value. As a result, we recorded a pre-tax impairment loss of $20 million , which was the difference between the carrying amount and the fair value of the investment.
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. 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 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 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. Our annual goodwill impairment testing date is as of October 1, which aligns our testing date with our financial planning process. 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. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. 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, long-term earnings and merger multiples for comparable companies.
Asset Retirement Obligations	Asset Retirement Obligations Accounting standards for AROs 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. 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.
Fair Value Measurements	Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our financial instruments’ assets and liabilities for financial instruments 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. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, 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 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 when 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 The commodity contracts for our Electric and Gas Utilities are valued using the market approach and include Level 2 exchange-traded futures, options, basis swaps and over-the-counter swaps for natural gas contracts. For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable instrument. For over-the-counter instruments, fair value was obtained by utilizing a nationally recognized service that obtains observable inputs to compute fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position.
Derivatives and Hedging Activities	Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. 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. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. As part of our Electric and Gas Utilities’ operations, we enter into contracts to buy and sell energy to meet the requirements of our customers. In addition, certain derivatives contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980. We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The effective portion of the derivative gain or loss is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivatives contracts are recognized in earnings. 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. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterpart when a legal right of offset exists.
Deferred Financing Costs	Deferred Financing Costs Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities.
Regulatory Accounting	Regulatory Accounting Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these regulated operations accounting standards: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates. • Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings. If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment, and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows. As of December 31, 2019 and 2018, we had total regulatory assets of $271 million and $284 million respectively, and total regulatory liabilities of $537 million and $541 million respectively. See Note 13 for further information.
Income Taxes	Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense 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. It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs 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 ITC 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.
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, outstanding stock options, restricted stock and performance shares under our equity compensation plans.
Noncontrolling Interest	Noncontrolling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidations.
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 Simplifying the Accounting for Income Taxes, ASU 2019-12 In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes as part of its overall simplification initiative to reduce costs and complexity in applying accounting standards while maintaining or improving the usefulness of the information provided to users of the financial statements. Amendments include removal of certain exceptions to the general principles of ASC 740 , Income Taxes , and simplification in several other areas such as accounting for a franchise tax (or similar tax) that is partially based on income. The new guidance is effective for interim and annual periods beginning after December 15, 2020 with early adoption permitted. We are currently reviewing this standard to assess the impact on our financial position, results of operations and cash flows. Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, ASU 2018-15 In August 2018, the FASB issued ASU 2018-15, Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract , which aligns the requirements for recording implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. As a result, certain categories of implementation costs that previously would have been charged to expense as incurred are now capitalized as prepayments and amortized over the term of the arrangement. The new guidance is effective for annual periods beginning after December 15, 2019, and interim periods within those fiscal years. The new guidance can be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. Early adoption is permitted. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have a material impact on our financial position, results of operations or cash flows. Simplifying the Test for Goodwill Impairment, ASU 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 adopted this standard prospectively on January 1, 2020. Adoption of this guidance is not expected to have any impact on our financial position, results of operations or cash flows. Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2018-19 In June 2016, the FASB issued ASU 2016-13, Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, which was subsequently amended by ASU 2018-19, ASU 2019-04, 2019-05, 2019-10, and 2019-11. The standard introduces new accounting guidance for credit losses on financial instruments within its scope, including trade receivables. This new guidance adds an impairment model that is based on expected losses rather than incurred losses. It is effective for interim and annual reporting periods beginning after December 15, 2019, with early adoption permitted. We adopted this standard on January 1, 2020 with prior year comparative financial information remaining as previously reported when transitioning to the new standard. On January 1, 2020, we recorded an increase to our allowance for doubtful accounts, primarily associated with the inclusion of expected losses on unbilled revenue. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows. Recently Adopted Accounting Standards Leases, ASU 2016-02 In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations by requiring the recognition of right-of-use assets and lease liabilities on the balance sheet for most leases, whereas previously only financing-type lease liabilities (capital leases) were recognized on the balance sheet. Under the new standard, disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases. We adopted the standard effective January 1, 2019. We elected not to recast comparative periods coinciding with the new lease standard transition and will report these comparative periods as presented under previous lease guidance. In addition, we elected the package of practical expedients permitted under the transition guidance with the new standard, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for existing land easement agreements. Adoption of the new standard resulted in the recording of an operating lease right-of-use asset of $3.1 million , an operating lease obligation liability of $3.2 million , and an accrued receivable of $4.5 million , as of January 1, 2019. The cumulative effect of the adoption, net of tax impact, was $3.4 million , which was recorded as an adjustment to retained earnings at January 1, 2019. See Note 14 for additional details on leases. Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities, ASU 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. We have adopted this standard on January 1, 2019. Adoption of this standard did not have a material impact on our financial position, results of operations or cash flows.
Revenue from Contract with Customer	REVENUE Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer, and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of revenue contracts are: • Regulated natural gas and electric utility services tariffs - Our utilities have regulated operations, as defined by ASC 980, that provide services to regulated customers under tariff rates, charges, terms and conditions of service, and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our utilities’ regulated sales are subject to regulatory-approved tariffs. • Power sales agreements - Our Electric Utilities and Power Generation segments have long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. • Coal supply agreements - Our Mining segment sells coal primarily under long-term contracts to utilities for use at their power generating plants, including affiliate electric utilities, and an affiliate non-regulated power generation entity. The contracts include a single promise to supply coal necessary to fuel the customers’ facilities during the contract term. The transaction price is established in the supply agreements, including cost-based agreements with the affiliated regulated utilities, and is variable based on tons delivered. • Other non-regulated services - Our Electric and Gas Utilities segments also provide non-regulated services primarily comprised of appliance repair service and protection plans, electric and natural gas technical infrastructure construction and maintenance services, and in Nebraska and Wyoming, an unbundled natural gas commodity offering under the regulatory-approved Choice Gas Program. Revenue contracts for these services generally represent a single performance obligation with the price reflecting the standalone selling price stated in the agreement, and the revenue is variable based on the units delivered or services provided. The majority of our revenue contracts are based on variable quantities delivered; any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the table above include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, derivative revenue under ASC 815 and alternative revenue programs revenue under ASC 980. Effective January 1, 2019, we changed how we account for the PPA between Black Hills Colorado IPP and Colorado Electric at the segment level and now recognize on an accrual basis, rather than a finance lease. See Note 5 for additional information. Significant Judgments and Estimates Unbilled Revenue 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. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts Receivable further discussed in Note 1 . We do not typically incur costs that would be capitalized to obtain or fulfill a contract.

Business Description (Tables)

Business Description (Tables)	12 Months Ended
	Dec. 31, 2019
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): 2019 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 41,428 $ 33,886 $ (592 ) $ 74,722 Gas Utilities 97,607 79,616 (1,683 ) 175,540 Power Generation 2,164 — — 2,164 Mining 2,277 — — 2,277 Corporate 1,271 — (169 ) 1,102 Total $ 144,747 $ 113,502 $ (2,444 ) $ 255,805 2018 Accounts Receivable, Trade Unbilled Revenue Less Allowance for Doubtful Accounts Accounts Receivable, net Electric Utilities $ 39,721 $ 35,125 $ (448 ) $ 74,398 Gas Utilities 96,123 90,521 (2,592 ) 184,052 Power Generation 1,876 — — 1,876 Mining 3,988 — — 3,988 Corporate 5,008 — (169 ) 4,839 Total $ 146,716 $ 125,646 $ (3,209 ) $ 269,153
Schedule of Valuation and Qualifying Accounts Disclosure	Changes to allowance for doubtful accounts for the years ended December 31, were as follows (in thousands): Balance at Beginning of Year Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year 2019 $ 3,209 $ 5,795 $ 3,942 $ (10,502 ) $ 2,444 2018 $ 3,081 $ 6,859 $ 4,092 $ (10,823 ) $ 3,209 2017 $ 2,392 $ 4,926 $ 8,262 $ (12,499 ) $ 3,081
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): 2019 2018 Materials and supplies $ 82,809 $ 75,081 Fuel - Electric Utilities 2,425 2,850 Natural gas in storage 31,938 39,368 Total materials, supplies and fuel $ 117,172 $ 117,299
Investments	The following table presents the carrying value of our investments (in thousands) as of December 31: 2019 2018 Investment in privately held oil and gas company $ 8,359 $ 28,100 Cash surrender value of life insurance contracts 13,056 12,812 Other investments 514 101 Total investments $ 21,929 $ 41,013
Goodwill	As of December 31, 2019, 2018 and 2017, Goodwill balances were as follows (in thousands): Electric Utilities Gas Utilities Power Generation Total Goodwill $ 248,479 $ 1,042,210 $ 8,765 $ 1,299,454
Intangible Assets	Changes to intangible assets for the years ended December 31, were as follows (in thousands): 2019 2018 2017 Intangible assets, net, beginning balance $ 14,337 $ 7,559 $ 8,392 Additions (a) — 7,602 — Amortization expense (b) (1,071 ) (824 ) (833 ) Intangible assets, net, ending balance $ 13,266 $ 14,337 $ 7,559 _________________ (a) The 2018 addition is related to the Busch Ranch 1 contract intangible asset. See Note 4 for further information. (b) Amortization expense for existing intangible assets is expected to be $1.1 million for each year of the next five years.
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): 2019 2018 Accrued employee compensation, benefits and withholdings $ 62,837 $ 63,742 Accrued property taxes 44,547 42,510 Customer deposits and prepayments 54,728 43,574 Accrued interest 31,868 31,759 CIAC current portion 1,952 1,485 Other (none of which is individually significant) 30,835 32,431 Total accrued liabilities $ 226,767 $ 215,501
Earnings Per Share of Common Stock	A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands): 2019 2018 2017 Net income available for common stock $ 199,310 $ 258,442 $ 177,034 Weighted average shares - basic 60,662 54,420 53,221 Dilutive effect of: Equity Units — 898 1,783 Equity compensation 136 168 116 Weighted average shares - diluted 60,798 55,486 55,120 Net income available for common stock, per share - Diluted $ 3.28 $ 4.66 $ 3.21
Antidilutive Securities	The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands): 2019 2018 2017 Equity compensation 1 16 11 Anti-dilutive shares excluded from computation of earnings per share 1 16 11

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reporting segments, for the years ended December 31, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 605,756 $ 817,840 $ — $ 59,233 $ (32,053 ) $ 1,450,776 Transportation — 143,390 — — (1,042 ) 142,348 Wholesale 20,884 — 99,157 — (91,577 ) 28,464 Market - off-system sales 23,817 691 — — (7,736 ) 16,772 Transmission/Other 57,104 47,725 — — (16,797 ) 88,032 Revenue from contracts with customers 707,561 1,009,646 99,157 59,233 (149,205 ) 1,726,392 Other revenues 5,191 384 2,101 2,396 (1,564 ) 8,508 Total revenues $ 712,752 $ 1,010,030 $ 101,258 $ 61,629 $ (150,769 ) $ 1,734,900 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 59,233 $ (32,053 ) $ 27,180 Services transferred over time 707,561 1,009,646 99,157 — (117,152 ) 1,699,212 Revenue from contracts with customers $ 707,561 $ 1,009,646 $ 99,157 $ 59,233 $ (149,205 ) $ 1,726,392 Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation (a) Mining Inter-company Revenues (a) Total Customer types: (in thousands) Retail $ 594,329 $ 833,379 $ — $ 65,803 $ (32,194 ) $ 1,461,317 Transportation — 140,705 — — (1,348 ) 139,357 Wholesale 33,687 — 90,791 — (84,957 ) 39,521 Market - off-system sales 24,799 866 — — (8,102 ) 17,563 Transmission/Other 56,209 49,402 — — (14,827 ) 90,784 Revenue from contracts with customers 709,024 1,024,352 90,791 65,803 (141,428 ) 1,748,542 Other revenues 2,427 955 1,660 2,230 (1,546 ) 5,726 Total revenues $ 711,451 $ 1,025,307 $ 92,451 $ 68,033 $ (142,974 ) $ 1,754,268 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 65,803 $ (32,194 ) $ 33,609 Services transferred over time 709,024 1,024,352 90,791 — (109,234 ) 1,714,933 Revenue from contracts with customers $ 709,024 $ 1,024,352 $ 90,791 $ 65,803 $ (141,428 ) $ 1,748,542 (a) Due to the changes in our segment disclosures discussed in Note 5 , Power Generation Wholesale revenue was revised for the year ended December 31, 2018 , which resulted in an increase of $38 million . The changes to Power Generation Wholesale revenue were offset by a decrease to Power Generation Other revenues of $35 million and a decrease to eliminations in Inter-company Revenues of $3.5 million . There was no impact to our consolidated Total Revenues.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2019 2018 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment (b) Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,348,049 41 $ 1,318,643 41 32 46 Electric transmission 483,640 51 437,082 51 43 54 Electric distribution 861,042 47 793,725 48 46 50 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 259,266 28 233,531 28 26 33 Total electric plant in service 2,956,867 2,787,851 Construction work in progress 102,268 60,480 Total electric plant 3,059,135 2,848,331 Less accumulated depreciation and amortization (670,861 ) (615,365 ) Electric plant net of accumulated depreciation and amortization $ 2,388,274 $ 2,232,966 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 11 years remaining. (b) Due to the changes in our segment disclosures discussed in Note 5 , Total electric plant in service, Accumulated depreciation and amortization, and Electric plant net of accumulated depreciation and amortization were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million , $91 million and ($170) million , respectively. There was no impact on our consolidated Plant, property and equipment. 2019 2018 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 $ 13,000 35 $ 13,580 35 24 71 Gas transmission 516,172 50 423,873 48 22 67 Gas distribution 1,857,233 43 1,595,644 42 30 56 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciable (a) 44,443 N/A 46,369 N/A N/A N/A Storage 46,977 31 29,335 30 27 49 General 437,054 20 355,920 19 10 24 Total gas plant in service 2,918,418 2,468,260 Construction work in progress 63,080 38,271 Total gas plant 2,981,498 2,506,531 Less accumulated depreciation and amortization (336,721 ) (279,580 ) Gas plant net of accumulated depreciation and amortization $ 2,644,777 $ 2,226,951 _____________ (a) Depreciation of Cushion gas is determined by the respective regulatory jurisdiction in which the Cushion gas resides. 2019 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 $ 532,397 $ 2,121 $ 534,518 $ (154,362 ) $ 380,156 31 2 40 Mining $ 179,198 $ 1,275 $ 180,473 $ (118,585 ) $ 61,888 13 2 59 2018 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 (a) $ 435,438 $ 11,796 $ 447,234 $ (137,832 ) $ 309,402 31 2 40 Mining $ 175,650 $ — $ 175,650 $ (111,689 ) $ 63,961 13 2 59 _____________ (a) Due to the changes in our segment disclosures discussed in Note 5 , Property, plant and equipment, Accumulated depreciation and amortization, and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of $261 million , ($73) million and $188 million , respectively. There was no impact on our consolidated Plant, property and equipment. 2019 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 Corporate $ 5,721 $ 23,334 $ 29,055 $ (964 ) $ 28,091 10 3 30 2018 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Amortization Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate (a) $ 5,721 $ 16,548 $ 22,269 $ (670 ) $ 21,599 8 3 30 ___________ (a) Due to the changes in our segment disclosures discussed in Note 5 , Corporate Accumulated depreciation and amortization and Net property, plant and equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($18) million and ($18) million respectively. There was no impact on our consolidated Plant, property and equipment.

Jointly Owned Facilities (Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Jointly Owned Utility Plants	At December 31, 2019 , our interests in jointly-owned generating facilities and transmission systems were (in thousands): Plant in Service Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation Wyodak Plant $ 116,074 $ 729 $ (64,413 ) $ 52,390 Transmission Tie $ 19,862 $ 4,161 $ (6,612 ) $ 17,411 Wygen I $ 120,824 $ 289 $ (48,703 ) $ 72,410 Wygen III $ 146,161 $ 400 $ (25,518 ) $ 121,043

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 Electric Utilities (a) $ 2,900,983 $ 2,707,695 Gas Utilities 4,032,339 3,623,475 Power Generation (a) 417,715 342,085 Mining 77,175 80,594 Corporate and Other 130,245 209,478 Total assets $ 7,558,457 $ 6,963,327 __________________ (a) Due to the changes in our segment disclosures, Electric Utilities and Power Generation Total assets were revised as of December 31, 2018 which resulted in an increase (decrease) of ($188) million and $188 million , respectively. There was no impact on our consolidated Total assets. Capital Expenditures (a) for the years ended December 31, 2019 2018 Capital expenditures Electric Utilities $ 222,911 $ 152,524 Gas Utilities 512,366 288,438 Power Generation 85,346 30,945 Mining 8,430 18,794 Corporate and Other 20,702 11,723 Total capital expenditures of continuing operations 849,755 502,424 Total capital expenditures of discontinued operations — 2,402 Total capital expenditures $ 849,755 $ 504,826 _________________ (a) Includes accruals for property, plant and equipment as disclosed in Note 17 . Property, Plant and Equipment as of December 31, 2019 2018 Electric Utilities (a) $ 3,059,135 $ 2,848,331 Gas Utilities 2,981,498 2,506,531 Power Generation (a) 534,518 447,234 Mining 180,473 175,650 Corporate and Other 29,055 22,269 Total property, plant and equipment $ 6,784,679 $ 6,000,015 _______________ (a) Due to the changes in our segment disclosures, Electric Utilities and Power Generation Property, Plant and Equipment were revised as of December 31, 2018 which resulted in an increase (decrease) of ($261) million and $261 million , respectively. There was no impact on our consolidated Property, Plant and Equipment.
Segment information included in Consolidated Statements of Income	Consolidating Income Statement Year ended December 31, 2019 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 684,445 $ 1,007,187 $ 7,580 $ 27,180 $ — $ — $ 1,726,392 Other revenues 5,191 384 1,859 1,074 — — 8,508 689,636 1,007,571 9,439 28,254 — — 1,734,900 Inter-company operating revenue - Contracts with customers 23,116 2,459 91,577 32,053 230 (149,435 ) — Other revenues — — 242 1,322 343,975 (345,539 ) — 23,116 2,459 91,819 33,375 344,205 (494,974 ) — Total revenue 712,752 1,010,030 101,258 61,629 344,205 (494,974 ) 1,734,900 Fuel, purchased power and cost of natural gas sold 268,297 425,898 9,059 — 268 (132,693 ) 570,829 Operations and maintenance 195,581 301,844 28,429 40,032 286,799 (303,776 ) 548,909 Depreciation, depletion and amortization 88,577 92,317 18,991 8,970 22,065 (21,800 ) 209,120 Adjusted operating income (loss) $ 160,297 $ 189,971 $ 44,779 $ 12,627 $ 35,073 $ (36,705 ) $ 406,042 Interest expense, net (137,659 ) Impairment of investment (a) (19,741 ) Other income (expense), net (5,740 ) Income tax benefit (expense) (29,580 ) Income from continuing operations 213,322 (Loss) from discontinued operations, net of tax — Net income 213,322 Net income attributable to noncontrolling interest (14,012 ) Net income available for common stock $ 199,310 ________________ (a) In 2019 we recorded an impairment of our investment in equity securities of a privately held oil and gas company. See Note 1 for additional information. Consolidating Income Statement Year ended December 31, 2018 Electric Utilities (b) Gas Utilities Power Generation (b) Mining Corporate Inter-Company Eliminations (b) Total Revenue - Contracts with customers $ 686,272 $ 1,022,828 $ 5,833 $ 33,609 $ — $ — $ 1,748,542 Other revenues 2,427 955 1,413 931 — $ — 5,726 688,699 1,023,783 7,246 34,540 — — 1,754,268 Inter-company operating revenue - Contracts with customers 22,752 1,524 84,959 32,194 148 (141,577 ) — Other revenues — — 246 1,299 379,775 (381,320 ) — 22,752 1,524 85,205 33,493 379,923 (522,897 ) — Total revenue 711,451 1,025,307 92,451 68,033 379,923 (522,897 ) 1,754,268 Fuel, purchased power and cost of natural gas sold 283,840 462,153 8,592 — 44 (129,019 ) 625,610 Operations and maintenance 186,175 291,481 25,135 43,728 324,916 (336,142 ) 535,293 Depreciation, depletion and amortization 85,567 86,434 16,110 7,965 21,161 (20,909 ) 196,328 Adjusted operating income (loss) 155,869 185,239 42,614 16,340 33,802 (36,827 ) 397,037 Interest expense, net (139,975 ) Other income (expense), net (1,180 ) Income tax benefit (expense) (a) 23,667 Income from continuing operations 279,549 (Loss) from discontinued operations, net of tax (6,887 ) Net income 272,662 Net income attributable to noncontrolling interest (14,220 ) Net income available for common stock $ 258,442 ________________ (a) Income tax benefit (expense) includes a tax benefit of $73 million resulting from legal entity restructuring. See Note 15 . (b) Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2018, which resulted in an increase (decrease) as follows (in millions): Year ended December 31, 2018 Electric Utilities Power Generation Inter-Company Eliminations Total Inter-company operating revenue - Contracts with customers $ — $ 3.5 $ (3.5 ) $ — Fuel, purchased power and cost of natural gas sold 6.7 — (6.7 ) — Depreciation, depletion and amortization (13.1 ) 9.2 3.9 — Adjusted operating income (loss) $ 6.4 $ (5.7 ) $ (0.7 ) $ — Consolidating Income Statement Year ended December 31, 2017 Electric Utilities (b) Gas Utilities Power Generation (b) Mining Corporate Inter-Company Eliminations (b) Total Revenue $ 689,945 $ 947,595 $ 7,263 $ 35,463 $ — $ — $ 1,680,266 Inter-company revenue 14,705 35 87,357 31,158 344,685 (477,940 ) — Total revenue 704,650 947,630 94,620 66,621 344,685 (477,940 ) 1,680,266 Fuel, purchased power and cost of natural gas sold 274,363 409,603 9,340 — 151 (130,169 ) 563,288 Operations and maintenance 172,307 269,190 23,042 44,882 296,067 (293,492 ) 511,996 Depreciation, depletion and amortization 80,243 83,732 15,548 8,239 21,031 (20,547 ) 188,246 Adjusted operating income (loss) 177,737 185,105 46,690 13,500 27,436 (33,732 ) 416,736 Interest expense, net (137,102 ) Other income (expense), net 2,108 Income tax benefit (expense) (73,367 ) Income from continuing operations 208,375 (Loss) from discontinued operations, net of tax (a) (17,099 ) Net income 191,276 Net income attributable to noncontrolling interest (14,242 ) Net income available for common stock $ 177,034 ________________ (a) Discontinued operations includes oil and gas property impairments. See Note 21 . (b) Due to changes in our segment disclosures, Adjusted operating income and related income statement accounts were revised for the year ended December 31, 2017, which resulted in an increase (decrease) as follows (in millions): Year ended December 31, 2017 Electric Utilities Power Generation Inter-Company Eliminations Total Inter-company revenue $ — $ 3.1 $ (3.1 ) $ — Fuel, purchased power and cost of natural gas sold 6.0 — (6.0 ) — Depreciation, depletion and amortization (13.1 ) 9.6 3.5 — Adjusted operating income (loss) $ 7.1 $ (6.5 ) $ (0.6 ) $ —

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2019 December 31, 2018 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 Senior unsecured notes due 2020 July 15, 2020 N/A — 200,000 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 2033 May 1, 2033 4.35% 400,000 400,000 Senior unsecured notes, due 2046 September 15, 2046 4.20% 300,000 300,000 Senior unsecured notes, due 2029 October 15, 2029 3.05% 400,000 — Senior unsecured notes, due 2049 October 15, 2049 3.88% 300,000 — Corporate term loan due 2021 (a) June 17, 2021 N/A — 300,000 Corporate term loan due 2021 June 7, 2021 2.32% 7,178 12,921 Total Corporate debt 2,632,178 2,437,921 Less unamortized debt discount (6,462 ) (5,122 ) Total Corporate debt, net 2,625,716 2,432,799 South Dakota Electric Series 94A Debt, variable rate (b) June 1, 2024 1.84% 2,855 2,855 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 2044 October 20, 2044 4.43% 85,000 85,000 Total South Dakota Electric debt 342,855 342,855 Less unamortized debt discount (82 ) (86 ) Total South Dakota Electric debt, net 342,773 342,769 Wyoming Electric Industrial development revenue bonds due 2021 (a) September 1, 2021 1.68% 7,000 7,000 Industrial development revenue bonds due 2027 (a) March 1, 2027 1.68% 10,000 10,000 First Mortgage Bonds due 2037 November 20, 2037 6.67% 110,000 110,000 First Mortgage Bonds due 2044 October 20, 2044 4.53% 75,000 75,000 Total Wyoming Electric debt 202,000 202,000 Less unamortized debt discount — — Total Wyoming Electric debt, net 202,000 202,000 Total long-term debt 3,170,489 2,977,568 Less current maturities 5,743 5,743 Less unamortized deferred financing costs (b) 24,650 20,990 Long-term debt, net of current maturities and deferred financing costs $ 3,140,096 $ 2,950,835 _______________ (a) Variable interest rate. (b) Includes deferred financing costs associated with our Revolving Credit Facility of $1.7 million and $2.3 million as of December 31, 2019 and December 31, 2018 , 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): 2020 $ 5,743 2021 $ 8,435 2022 $ — 2023 $ 525,000 2024 $ 2,855 Thereafter $ 2,635,000
Deferred Financing Costs	Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands): Deferred Financing Costs Remaining at Amortization Expense for the years ended December 31, December 31, 2019 2019 2018 2017 $ 24,650 $ 3,242 $ 2,829 $ 3,349

Notes Payable (Tables)

Notes Payable (Tables)	12 Months Ended
	Dec. 31, 2019
Notes Payable [Abstract]
Schedule of Short-term Debt	We had the following short-term debt outstanding at the Consolidated Balance Sheets date (in thousands): December 31, 2019 December 31, 2018 Balance Outstanding Letters of Credit (a) Balance Outstanding Letters of Credit (a) Revolving Credit Facility $ — $ 30,274 $ — $ 22,311 CP Program 349,500 — 185,620 — Total $ 349,500 $ 30,274 $ 185,620 $ 22,311 _______________ (a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2018 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (a) (b) December 31, 2019 Electric Utilities (c) $ 6,258 $ — $ — $ 385 $ 2,686 $ 9,329 Gas Utilities 34,627 — — 1,458 — 36,085 Power Generation (c) 300 3,445 — 158 836 4,739 Mining 15,615 — (380 ) 740 (1,923 ) 14,052 Total $ 56,800 $ 3,445 $ (380 ) $ 2,741 $ 1,599 $ 64,205 December 31, 2017 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates (b) December 31, 2018 Electric Utilities $ 6,287 $ — $ — $ 269 $ 2 $ 6,558 Gas Utilities 33,238 152 — 1,237 — 34,627 Mining 12,499 — (4 ) 649 2,471 15,615 Total $ 52,024 $ 152 $ (4 ) $ 2,155 $ 2,473 $ 56,800 _____________________ (a) The increase in Electric Utilities Revisions to Prior Estimates was primarily driven by an increase to the estimated cost to decommission certain regulated wind farm assets. (b) The changes in the Mining Revision to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process. (c) We reclassified $0.3 million of ARO as of December 31, 2018 related to Busch Ranch I from Electric Utilities to the Power Generation segment as a result of Black Hills Electric Generation’s purchase of its 50% ownership interest in Busch Ranch I. Additional liabilities were incurred in 2019 from new wind assets.

Risk Management Activities (Tab

Risk Management Activities (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 December 31, 2018 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 1,450,000 12 4,000,000 24 Natural gas options purchased, net 3,240,000 3 4,320,000 13 Natural gas basis swaps purchased 1,290,000 12 3,960,000 24 Natural gas over-the-counter swaps, net (b) 4,600,000 24 3,660,000 24 Natural gas physical commitments, net (c) 13,548,235 12 18,325,852 30 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2019 , 1,415,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude contracts that qualify for normal purchase, normal sales exception.
Derivative Instruments, Gain (Loss)	The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2019 , 2018 and 2017 (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, 2019 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income Interest rate swaps Interest expense $ (2,851 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold 417 Total impact from cash flow hedges $ (2,434 ) December 31, 2018 Derivatives in Cash Flow Hedging Relationships Location of Reclassifications from AOCI into Income Amount of Gain/(Loss) Reclassified from AOCI into Income Interest rate swaps Interest expense $ (2,851 ) Commodity derivatives Fuel, purchased power and cost of natural gas sold (130 ) Total impact from cash flow hedges $ (2,981 ) 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 Interest rate swaps Interest expense $ (2,941 ) Commodity derivatives Net (loss) from discontinued operations 913 Commodity derivatives Fuel, purchased power and cost of natural gas sold (243 ) Total impact from cash flow hedges $ (2,271 ) 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, 2019 , 2018 and 2017 (in thousands). December 31, 2019 December 31, 2018 December 31, 2017 Increase (decrease) in fair value: Forward commodity contracts $ (548 ) $ 983 $ 366 Recognition of (gains) losses in earnings due to settlements: Interest rate swaps 2,851 2,851 2,941 Forward commodity contracts (417 ) 130 (670 ) Total other comprehensive income (loss) from hedging $ 1,886 $ 3,964 $ 2,637 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 for the years ended December 31, 2019 , 2018 and 2017 (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, 2019 December 31, 2018 December 31, 2017 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 Fuel, purchased power and cost of natural gas sold $ (1,100 ) $ 1,101 $ (2,207 ) $ (1,100 ) $ 1,101 $ (2,207 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — $ 1,433 $ — $ (1,085 ) $ 348 Total $ — $ 1,433 $ — $ (1,085 ) $ 348 Liabilities: Commodity derivatives - Utilities $ — $ 5,254 $ — $ (2,909 ) $ 2,345 Total $ — $ 5,254 $ — $ (2,909 ) $ 2,345 As of December 31, 2018 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting Total Assets: Commodity derivatives - Utilities $ — 2,927 $ — $ (1,408 ) $ 1,519 Total $ — $ 2,927 $ — $ (1,408 ) $ 1,519 Liabilities: Commodity derivatives - Utilities $ — $ 6,801 $ — $ (5,794 ) $ 1,007 Total $ — $ 6,801 $ — $ (5,794 ) $ 1,007
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): December 31, Balance Sheet Location 2019 2018 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1 $ 415 Noncurrent commodity derivatives Other assets, non-current 3 18 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (490 ) (114 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (29 ) (4 ) Total derivatives designated as hedges $ (515 ) $ 315 Not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 341 $ 1,085 Noncurrent commodity derivatives Other assets, non-current 2 1 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (1,764 ) (833 ) Noncurrent commodity derivatives Other deferred credits and other liabilities (63 ) (56 ) Total derivatives not designated as hedges $ (1,484 ) $ 197
Schedule of Derivative Offsetting on Balance Sheet	Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets at December 31, 2019 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 Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,085 $ (1,085 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 348 — 348 Total derivative assets $ 1,433 $ (1,085 ) $ 348 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 2,908 $ (2,908 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 2,345 — 2,345 Total derivative liabilities $ 5,253 $ (2,908 ) $ 2,345 Offsetting of derivative assets and derivative liabilities on our Consolidated Balance Sheets as of December 31, 2018 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 Commodity derivative assets subject to a master netting agreement or similar arrangement $ 1,408 $ (1,408 ) $ — Commodity derivative assets not subject to a master netting agreement or similar arrangement 1,519 — 1,519 Total derivative assets $ 2,927 $ (1,408 ) $ 1,519 Derivative Liabilities Gross Amounts of Derivative Liabilities Gross Amounts Offset on Consolidated Balance Sheets Net Amount of Total Derivative Liabilities on Consolidated Balance Sheets Commodity derivative liabilities subject to a master netting agreement or similar arrangement $ 5,794 $ (5,794 ) $ — Commodity derivative liabilities not subject to a master netting agreement or similar arrangement 1,007 — 1,007 Total derivative liabilities $ 6,801 $ (5,794 ) $ 1,007

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
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): 2019 2018 Carrying Amount Fair Value Carrying Amount Fair Value Cash and cash equivalents (a) $ 9,777 $ 9,777 $ 20,776 $ 20,776 Restricted cash and equivalents (a) $ 3,881 $ 3,881 $ 3,369 $ 3,369 Notes payable (b) $ 349,500 $ 349,500 $ 185,620 $ 185,620 Long-term debt, including current maturities (c) $ 3,145,839 $ 3,479,367 $ 2,956,578 $ 3,039,108 _______________ (a) Carrying value approximates fair value. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. (b) Notes payable consist of commercial paper borrowings. 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. Carrying amount of long-term debt is net of deferred financing costs.

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Stockholders' Equity Note [Abstract]
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 was as follows for the years ended December 31 (in thousands): 2019 2018 2017 Stock-based compensation expense $ 12,095 $ 12,390 $ 7,626
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, 2019 , was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at beginning of period 236 $ 57.50 Granted 92 73.66 Vested (120 ) 56.33 Forfeited (16 ) 62.02 Balance at end of period 192 $ 65.66 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, were as follows: Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) 2019 $ 73.66 $ 8,438 2018 $ 57.31 $ 6,776 2017 $ 60.63 $ 7,909
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, 2017 January 1, 2017 - December 31, 2019 46 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 50 0% 200% January 1, 2019 January 1, 2019 - December 31, 2021 37 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, 2019 (in thousands) (in thousands) Performance Shares balance at beginning of period 77 $ 57.66 77 Granted 20 68.72 20 Forfeited (4 ) 64.60 (4 ) Vested (26 ) 47.76 (26 ) Performance Shares balance at end of period 67 $ 64.32 67 $ 89.63 _____________________ (a) The grant date fair values for the performance shares granted in 2019 , 2018 and 2017 were determined by Monte Carlo simulation using a blended volatility of 21% , 21% and 23% , 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, 2019 $ 68.72 December 31, 2018 $ 61.82 December 31, 2017 $ 63.52
Performance Plan Payouts [Table Text Block]	Performance plan payouts have been as follows (in thousands): Performance Period Year Paid Stock Issued Cash Paid Total Intrinsic Value January 1, 2016 to December 31, 2018 2019 44 $ 2,860 $ 5,720 January 1, 2015 to December 31, 2017 — — — January 1, 2014 to December 31, 2016 — — —
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 (in thousands): 2019 2018 Assets Current assets $ 13,350 $ 13,620 Property, plant and equipment of variable interest entities, net $ 193,046 $ 199,839 Liabilities Current liabilities $ 6,013 $ 5,174

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2019
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities as of December 31 (in thousands): 2019 2018 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 34,088 $ 29,661 Deferred gas cost adjustments (a) 1,540 3,362 Gas price derivatives (a) 3,328 6,201 Deferred taxes on AFUDC (b) 7,790 7,841 Employee benefit plans (c) 115,900 110,524 Environmental (a) 1,454 959 Loss on reacquired debt (a) 24,777 21,001 Renewable energy standard adjustment (a) 1,622 1,722 Deferred taxes on flow through accounting (c) 41,220 31,044 Decommissioning costs (a) 10,670 11,700 Gas supply contract termination (a) 8,485 14,310 Other regulatory assets (a) 20,470 45,910 Total regulatory assets 271,344 284,235 Less current regulatory assets (43,282 ) (48,776 ) Regulatory assets, non-current $ 228,062 $ 235,459 Regulatory liabilities Deferred energy and gas costs (a) $ 17,278 $ 6,991 Employee benefit plan costs and related deferred taxes (c) 43,349 42,533 Cost of removal (a) 166,727 150,123 Excess deferred income taxes (c) 285,438 310,562 TCJA revenue reserve 3,418 18,032 Other regulatory liabilities (c) 20,442 12,553 Total regulatory liabilities 536,652 540,794 Less current regulatory liabilities (33,507 ) (29,810 ) Regulatory liabilities, non-current $ 503,145 $ 510,984 __________ (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.

Operating Leases (Tables)

Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Lessee Disclosure [Abstract]
Lease, Cost	The components of lease expense for the year ended December 31 were as follows (in thousands) : Income Statement Location 2019 Operating lease cost Operations and maintenance $ 1,456 Finance lease cost: Amortization of right-of-use asset Depreciation, depletion and amortization 100 Interest on lease liabilities Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) 19 Total lease cost $ 1,575
Lessee Supplemental Balance Sheet Information	Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2019 Assets: Operating lease assets Other assets, non-current $ 4,629 Finance lease assets Other assets, non-current 465 Total lease assets $ 5,094 Liabilities: Current: Operating leases Accrued liabilities $ 1,179 Finance lease Accrued liabilities 109 Noncurrent: Operating leases Other deferred credits and other liabilities 3,821 Finance lease Other deferred credits and other liabilities 364 Total lease liabilities $ 5,473
Lessee Supplemental Cash Flow Information	Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,263 Operating cash flows from finance lease $ 19 Financing cash flows from finance lease $ 93 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 2,801 Finance lease $ 67
Lessee Supplemental Weighted Average Schedule	Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2019 Weighted average remaining lease term (years): Operating leases 8 years Finance lease 4 years Weighted average discount rate: Operating leases 4.27 % Finance lease 4.19 %
Finance Lease, Liability, Maturity	As of December 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases Finance Lease Total 2020 1,018 126 1,144 2021 865 126 991 2022 743 126 869 2023 718 126 844 2024 714 10 724 Thereafter 2,009 — 2,009 Total lease payments (a) $ 6,067 $ 514 $ 6,581 Less imputed interest 1,067 41 1,108 Present value of lease liabilities $ 5,000 $ 473 $ 5,473 _______________ (a) Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance.
Lessee, Operating Lease, Liability, Maturity	As of December 31, 2019, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases Finance Lease Total 2020 1,018 126 1,144 2021 865 126 991 2022 743 126 869 2023 718 126 844 2024 714 10 724 Thereafter 2,009 — 2,009 Total lease payments (a) $ 6,067 $ 514 $ 6,581 Less imputed interest 1,067 41 1,108 Present value of lease liabilities $ 5,000 $ 473 $ 5,473 _______________ (a) Lease payments exclude payments to landlords for common area maintenance, real estate taxes, and insurance. As previously disclosed in Note 14 of the Notes to the Consolidated Financial Statements in our 2018 Annual Report on Form 10-K, prior to the adoption of ASU 2016-02, Leases (Topic 842), the future minimum payments required under operating lease agreements as of December 31, 2018 were as follows (in thousands): Operating Leases 2019 $ 1,052 2020 464 2021 344 2022 224 2023 216 Thereafter 1,776 Total lease payments $ 4,076
Lessor Disclosure [Abstract]
Operating Lease, Lease Income	The components of lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2019 Operating lease income Revenue $ 2,306
Lessor - Operating And Finance Lease, Liability, Maturity	As of December 31, 2019, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2020 2,227 2021 1,857 2022 1,793 2023 1,799 2024 1,743 Thereafter 53,739 Total lease receivables $ 63,158

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
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): 2019 2018 2017 Current: Federal $ (8,578 ) $ 325 $ (6,193 ) State 138 247 (1,432 ) (8,440 ) 572 (7,625 ) Deferred: Federal 34,551 (25,022 ) 76,522 State 3,469 783 4,470 38,020 (24,239 ) 80,992 $ 29,580 $ (23,667 ) $ 73,367
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): 2019 2018 Deferred tax assets: Regulatory liabilities $ 89,754 $ 92,966 State tax credits 23,261 20,466 Federal net operating loss 120,624 139,371 State net operating loss 13,537 16,647 Partnership 14,030 16,032 Credit Carryovers 27,139 23,124 Other deferred tax assets (a) 33,395 39,349 Less: Valuation allowance (12,063 ) (11,809 ) Total deferred tax assets 309,677 336,146 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (533,292 ) (529,338 ) Regulatory assets (23,586 ) (32,324 ) Goodwill (b) (15,875 ) (602 ) State deferred tax liability (72,911 ) (64,095 ) Other deferred tax liabilities (24,732 ) (21,118 ) Total deferred tax liabilities (670,396 ) (647,477 ) Net deferred tax liability $ (360,719 ) $ (311,331 ) _______________ (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) Legal entity restructuring - see above.
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: 2019 2018 2017 Federal statutory rate 21.0 % 21.0 % 35.0 % State income tax (net of federal tax effect) 1.5 2.3 0.9 Non-controlling interest (a) (1.2 ) (1.3 ) (1.8 ) Tax credits (3.9 ) (2.0 ) (1.7 ) Flow-through adjustments (b) (2.4 ) (1.6 ) (1.1 ) Jurisdictional consolidation project (d) — (28.5 ) — Other tax differences (1.6 ) (0.1 ) (2.6 ) TCJA corporate rate reduction (c) — 1.6 (2.7 ) Amortization of excess deferred income tax expense (e) (1.2 ) (0.7 ) — 12.2 % (9.3 )% 26.0 % _________________________ (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. During the year ended December 31, 2018, we recorded $4.0 million of additional tax expense associated with changes in the prior estimated impacts of TCJA related items. During the year ended December 31, 2017, we recorded $7.6 million of tax benefit resulting from revaluation of net deferred tax liabilities in accordance with ASC 740 and the enactment of the TCJA on December 22, 2017. (d) Legal entity restructuring - see above. (e) Primarily TCJA - see above.
Summary of Operating Loss Carryforwards	At December 31, 2019 , 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 $ 575,457 2022 to 2037 State Net Operating Loss Carryforward (a) $ 224,716 2020 to 2040 _________________________ (a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.
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, 2017 $ 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 Additions for prior year tax positions 251 Reductions for prior year tax positions (417 ) Additions for current year tax positions 486 Settlements — Ending balance at December 31, 2018 3,583 Additions for prior year tax positions 446 Reductions for prior year tax positions (862 ) Additions for current year tax positions 998 Settlements — Ending balance at December 31, 2019 $ 4,165
Summary of State Tax Carryforwards	State tax credits have been generated and are available to offset future state income taxes. At December 31, 2019 , we had the following state tax credit carryforwards (in thousands): State Tax Credit Carryforwards Expiration Year ITC $ 23,060 2023 to 2041 Research and development $ 201 No expiration

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2019
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 for the period, net of tax (in thousands): Location on the Consolidated Statements of Income Amount Reclassified from AOCI December 31, 2019 December 31, 2018 Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ (2,851 ) $ (2,851 ) Commodity contracts Fuel, purchased power and cost of natural gas sold 417 (130 ) (2,434 ) (2,981 ) Income tax Income tax benefit (expense) 611 630 Total reclassification adjustments related to cash flow hedges, net of tax $ (1,823 ) $ (2,351 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 77 $ 178 Actuarial gain (loss) Operations and maintenance (745 ) (2,487 ) (668 ) (2,309 ) Income tax Income tax benefit (expense) (453 ) 543 Total reclassification adjustments related to defined benefit plans, net of tax $ (1,121 ) $ (1,766 ) Total reclassifications $ (2,944 ) $ (4,117 )
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, 2018 $ (17,307 ) $ 328 $ (9,937 ) $ (26,916 ) Other comprehensive income (loss) before reclassifications — (422 ) (6,261 ) (6,683 ) Amounts reclassified from AOCI 2,185 (362 ) 1,121 2,944 As of December 31, 2019 $ (15,122 ) $ (456 ) $ (15,077 ) $ (30,655 ) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total As of December 31, 2017 $ (19,581 ) $ (518 ) $ (21,103 ) $ (41,202 ) Other comprehensive income (loss) before reclassifications — 755 2,155 2,910 Amounts reclassified from AOCI 2,252 99 1,766 4,117 Reclassification to regulatory asset — — 6,519 6,519 Reclassification of certain tax effects from AOCI 22 (8 ) 726 740 As of December 31, 2018 $ (17,307 ) $ 328 $ (9,937 ) $ (26,916 )

Supplemental Cash Flow Informat

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosure of Cash Flow Information	Years ended December 31, 2019 2018 2017 (in thousands) Non-cash investing activities and financing from continuing operations - Accrued property, plant and equipment purchases at December 31 $ 91,491 $ 69,017 $ 28,191 Increase (decrease) in capitalized assets associated with asset retirement obligations $ 5,044 $ 2,625 $ 3,198 Cash (paid) refunded during the period for continuing operations- Interest (net of amounts capitalized) $ (131,774 ) $ (137,965 ) $ (132,428 ) Income taxes (paid) refunded $ 4,682 $ (14,730 ) $ 1,775

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2019
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: 2019 2018 Equity 20% 17% Real estate 3 4 Fixed income 71 71 Cash 1 3 Hedge funds 5 5 Total 100% 100%
Schedule of Defined Contribution Plans Contributions	Contributions for the years ended December 31 were as follows (in thousands): 2019 2018 Defined Contribution Plan Company retirement contributions $ 9,714 $ 8,766 Company matching contributions $ 14,558 $ 13,559 2019 2018 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 12,700 Non-Pension Defined Benefit Postretirement Healthcare Plan $ 7,033 $ 5,298 Supplemental Non-Qualified Defined Benefit Plans $ 2,344 $ 2,073
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: Benefit Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31 (in thousands), 2019 2018 2019 2018 2019 2018 Change in benefit obligation: Projected benefit obligation at beginning of year $ 445,381 $ 474,725 $ 43,010 $ 45,112 $ 60,817 $ 69,339 Service cost 5,383 6,834 4,995 1,764 1,815 2,291 Interest cost 17,374 15,470 1,295 1,170 2,247 2,085 Actuarial (gain) loss 56,384 (31,340 ) 7,132 (2,963 ) 5,976 (9,045 ) Benefits paid (39,146 ) (20,308 ) (2,344 ) (2,073 ) (7,033 ) (5,298 ) Plan participants’ contributions — — — — 1,455 1,445 Projected benefit obligation at end of year $ 485,376 $ 445,381 $ 54,088 $ 43,010 $ 65,277 $ 60,817
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 Plan (a) As of December 31 (in thousands), 2019 2018 2019 2018 2019 2018 Change in fair value of plan assets: Beginning fair value of plan assets $ 390,796 $ 416,343 $ — $ — $ 8,162 $ 8,621 Investment income (loss) 69,934 (17,939 ) — — 260 (149 ) Employer contributions 12,700 12,700 2,344 2,073 5,461 3,543 Retiree contributions — — — — 1,455 1,445 Benefits paid (39,146 ) (20,308 ) (2,344 ) (2,073 ) (7,033 ) (5,298 ) Ending fair value of plan assets $ 434,284 $ 390,796 $ — $ — $ 8,305 $ 8,162 ____________________ (a) Assets of VEBA trusts.
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 Plan 2019 2018 2019 2018 2019 2018 Regulatory assets $ 88,471 $ 82,919 $ — $ — $ 11,670 $ 6,655 Current liabilities $ — $ — $ 1,420 $ 1,463 $ 4,802 $ 3,885 Non-current assets $ — $ — $ — $ — $ — $ 249 Non-current liabilities $ 51,093 $ 54,585 $ 51,243 $ 41,547 $ 52,136 $ 49,015 Regulatory liabilities $ 3,524 $ 4,620 $ — $ — $ 4,088 $ 5,207
Schedule of Accumulated and Projected Benefit Obligations	Accumulated Benefit Obligation Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31 (in thousands) 2019 2018 2019 2018 2019 2018 Accumulated Benefit Obligation $ 470,615 $ 428,851 $ 49,241 $ 40,530 $ 65,277 $ 60,817
Components of net periodic benefit cost	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 Plan 2019 2018 2017 2019 2018 2017 2019 2018 2017 Service cost $ 5,383 $ 6,834 $ 7,034 $ 4,995 $ 1,764 $ 1,546 $ 1,815 $ 2,291 $ 2,300 Interest cost 17,374 15,470 15,520 1,295 1,170 1,276 2,247 2,085 2,141 Expected return on assets (24,401 ) (24,741 ) (24,517 ) — — — (230 ) (315 ) (315 ) Net amortization of prior service cost 26 58 58 2 2 2 (398 ) (398 ) (411 ) Recognized net actuarial loss (gain) 3,763 8,632 4,007 535 1,000 1,001 — 216 499 Net periodic expense $ 2,145 $ 6,253 $ 2,102 $ 6,827 $ 3,936 $ 3,825 $ 3,434 $ 3,879 $ 4,214
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 Plan 2019 2018 2019 2018 2019 2018 Net (gain) loss $ 5,322 $ 11,967 $ 9,893 $ 4,668 $ 90 $ 860 Prior service cost (gain) — 1 2 3 (230 ) (317 ) Reclassification of certain tax effects from AOCI — (594 ) — (87 ) — (45 ) Reclassification to regulatory asset — (5,600 ) — — — (919 ) Total AOCI $ 5,322 $ 5,774 $ 9,895 $ 4,584 $ (140 ) $ (421 )
Schedule of Assumptions Used	Assumptions Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine benefit obligations: 2019 2018 2017 2019 2018 2017 2019 2018 2017 Discount rate 3.27 % 4.40 % 3.71 % 3.14 % 4.34 % 3.56 % 3.15 % 4.28 % 3.60 % Rate of increase in compensation levels 3.49 % 3.52 % 3.43 % 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 Plan Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2019 2018 2017 2019 2018 2017 2019 2018 2017 Discount rate (a) 4.40 % 3.71 % 4.27 % 4.34 % 3.67 % 4.02 % 4.28 % 3.60 % 4.05 % Expected long-term rate of return on assets (b) 6.00 % 6.25 % 6.75 % N/A N/A N/A 3.00 % 3.93 % 3.88 % Rate of increase in compensation levels 3.52 % 3.43 % 3.47 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 3.27% for the calculation of the 2020 net periodic pension costs. (b) The expected rate of return on plan assets is 5.25% for the calculation of the 2020 net periodic pension cost.
Schedule of Health Care Cost Trend Rates	The healthcare benefit obligation was determined at December 31 as follows: 2019 2018 Trend Rate - Medical Pre-65 for next year - All Plans 6.40% 6.70% Pre-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2027 2027 Post-65 for next year - All Plans 4.92% 4.94% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2028 2026
Schedule of Expected Benefit Payments	The following benefit payments to employees, 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 Plan 2020 $ 24,586 $ 1,420 $ 5,919 2021 $ 25,774 $ 1,786 $ 5,974 2022 $ 26,728 $ 2,167 $ 5,790 2023 $ 27,795 $ 2,223 $ 5,521 2024 $ 28,547 $ 2,412 $ 5,329 2025-2029 $ 145,426 $ 14,689 $ 23,030
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, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 60 $ — $ 60 $ — $ 60 Common Collective Trust - Cash and Cash Equivalents — 7,054 — 7,054 — 7,054 Common Collective Trust - Equity — 87,106 — 87,106 — 87,106 Common Collective Trust - Fixed Income — 306,275 — 306,275 — 306,275 Common Collective Trust - Real Estate — — — — 14,239 14,239 Hedge Funds — — — — 19,550 19,550 Total investments measured at fair value $ — $ 400,495 $ — $ 400,495 $ 33,789 $ 434,284 Pension Plan December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments AXA Equitable General Fixed Income $ — $ 1,867 $ — $ 1,867 $ — $ 1,867 Common Collective Trust - Cash and Cash Equivalents — 9,923 — 9,923 — 9,923 Common Collective Trust - Equity — 67,457 — 67,457 — 67,457 Common Collective Trust - Fixed Income — 279,148 — 279,148 — 279,148 Common Collective Trust - Real Estate — 67 — 67 13,551 13,618 Hedge Funds — — — — 18,783 18,783 Total investments measured at fair value $ — $ 358,462 $ — $ 358,462 $ 32,334 $ 390,796 _____________ (a) Certain investments that are measured at fair value using 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 Plan December 31, 2019 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,305 $ — $ — $ 8,305 $ 8,305 Total investments measured at fair value $ 8,305 $ — $ — $ 8,305 $ 8,305 Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2018 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 4,873 $ — $ — $ 4,873 $ 4,873 Equity Securities 1,005 — — 1,005 1,005 Intermediate-term Bond — 2,284 — 2,284 2,284 Total investments measured at fair value $ 5,878 $ 2,284 $ — $ 8,162 $ 8,162

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2019
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 and natural gas transportation and storage agreements (in thousands): Power purchase and transmission services agreements Natural gas transportation and storage agreements 2020 $ 25,476 $ 156,297 2021 $ 11,678 $ 148,149 2022 $ 11,678 $ 122,340 2023 $ 11,678 $ 93,905 2024 $ 2,738 $ 51,360 Thereafter $ — $ 126,147
Schedule of Unit Contingent Capacity	The unit-contingent capacity amounts from Wygen III and Neil Simpson II are as follows: Contract Years Total Contract Capacity Contingent Capacity Amounts on Wygen III Contingent Capacity Amounts on Neil Simpson II 2019-2020 15 MW 10 MW 5 MW 2020-2022 15 MW 7 MW 8 MW 2022-2023 15 MW 8 MW 7 MW 2023-2028 10 MW 5 MW 5 MW
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): 2019 2018 2017 Colorado Electric PPA with PRPA - Unit Contingent Energy $ 1,802 $ — $ — Colorado Electric PPA Busch Ranch I (a) $ — $ — $ 1,966 South Dakota Electric PPA with PacifiCorp $ 7,477 $ 13,681 $ 13,218 South Dakota Electric Transmission services agreement with PacifiCorp $ 1,741 $ 1,742 $ 1,671 South Dakota Electric PPA with PRPA $ 688 $ 223 $ — Wyoming Electric PPA with Happy Jack $ 3,936 $ 3,884 $ 3,846 Wyoming Electric PPA with Silver Sage $ 5,366 $ 5,376 $ 4,934 ________________ (a) On December 11, 2018, Black Hills Electric Generation purchased a 50% ownership interest of the Busch Ranch I. Black Hills Electric Generation and Colorado Electric now collectively own 100% of the wind farm.
Purchased Gas Cost Obligation
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment	At December 31, 2019 , the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): NNG-Ventura NWPL-Wyoming 2020 3,660,000 1,520,000 2021 3,650,000 1,510,000 2022 1,810,000 1,510,000 2023 0 1,510,000 2024 0 910,000 Thereafter 0 0

Guarantees (Tables)

Guarantees (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 Expiration Indemnification for subsidiary reclamation/surety bonds (a) $ 55,527 Ongoing Contract performance guarantee (b) 46,831 May 2020 $ 102,358 _______________________ (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. (b) BHC has guaranteed the full and complete payment and performance on behalf of Black Hills Electric Generation for construction of Busch Ranch II. The guarantee terminates when BHC or Black Hills Electric Generation has paid for and performed all guaranteed obligations.

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2019
Discontinued Operations and Disposal Groups [Abstract]
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, 2018 December 31, 2017 Revenue $ 5,897 $ 25,382 Operations and maintenance 11,014 22,872 Loss on sale of assets 3,259 — Depreciation, depletion and amortization 1,300 7,521 Impairment of long-lived assets — 20,385 Total operating expenses 15,573 50,778 Operating (loss) (9,676 ) (25,396 ) Interest income (expense), net (19 ) 181 Other income (expense), net 190 (297 ) Income tax benefit 2,618 8,413 Net (loss) from discontinued operations $ (6,887 ) $ (17,099 )

Quarterly Historical Data (Un_2

Quarterly Historical Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 and 2018 . First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2019 Revenue $ 597,810 $ 333,888 $ 325,548 $ 477,654 Operating income $ 160,131 $ 54,001 $ 70,551 $ 121,359 Income from continuing operations $ 107,362 $ 17,693 $ 15,395 $ 72,872 (Loss) from discontinued operations $ — $ — $ — $ — Net income attributable to noncontrolling interest $ (3,554 ) $ (3,110 ) $ (3,655 ) $ (3,693 ) Net income available for common stock $ 103,808 $ 14,583 $ 11,740 $ 69,179 Amounts attributable to common shareholders: Net income from continuing operations $ 103,808 $ 14,583 $ 11,740 $ 69,179 Net (loss) from discontinued operations — — — — Net income available for common stock $ 103,808 $ 14,583 $ 11,740 $ 69,179 Income per share for continuing operations - Basic $ 1.73 $ 0.24 $ 0.19 $ 1.13 (Loss) per share for discontinued operations - Basic — — — — Earnings per share - Basic $ 1.73 $ 0.24 $ 0.19 $ 1.13 Income per share for continuing operations - Diluted $ 1.73 $ 0.24 $ 0.19 $ 1.13 (Loss) per share for discontinued operations - Diluted — — — — Earnings per share - Diluted $ 1.73 $ 0.24 $ 0.19 $ 1.13 Included within the Income (loss) from continuing operations in the third quarter of 2019 is $15 million non-cash after-tax impairment of our investment in equity securities of a privately held oil and gas company. First Quarter Second Quarter Third Quarter Fourth Quarter (in thousands, except per share amounts, dividends and common stock prices) 2018 Revenue $ 575,389 $ 355,704 $ 321,979 $ 501,196 Operating income $ 148,274 $ 69,551 $ 65,085 $ 114,127 Income from continuing operations $ 138,977 $ 27,167 $ 21,801 $ 91,604 (Loss) from discontinued operations $ (2,343 ) $ (2,427 ) $ (857 ) $ (1,260 ) Net income attributable to noncontrolling interest $ (3,630 ) $ (2,823 ) $ (3,994 ) $ (3,773 ) Net income available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Amounts attributable to common shareholders: Net income from continuing operations $ 135,347 $ 24,344 $ 17,807 $ 87,831 Net (loss) from discontinued operations (2,343 ) (2,427 ) (857 ) (1,260 ) Net income available for common stock $ 133,004 $ 21,917 $ 16,950 $ 86,571 Income per share for continuing operations - Basic $ 2.54 $ 0.46 $ 0.33 $ 1.52 (Loss) per share for discontinued operations - Basic (0.05 ) (0.05 ) (0.02 ) (0.02 ) Earnings per share - Basic $ 2.49 $ 0.41 $ 0.32 $ 1.50 Income per share for continuing operations - Diluted $ 2.50 $ 0.45 $ 0.32 $ 1.51 (Loss) per share for discontinued operations - Diluted (0.04 ) (0.05 ) (0.02 ) (0.02 ) Earnings per share - Diluted $ 2.46 $ 0.40 $ 0.31 $ 1.49 Included within the Income (loss) from continuing operations in the first and fourth quarters of 2018 are tax benefits of $49 million and $23 million , respectively, related to goodwill that is amortizable for tax purposes which resulted from legal entity restructuring.

Business Description And Sign_2

Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	$ (2,444)	$ (3,209)
Accounts receivable, net	255,805	269,153
Corporate, Non-Segment
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(169)	(169)
Accounts receivable, net	1,102	4,839
Electric Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(592)	(448)
Accounts receivable, net	74,722	74,398
Gas Utilities
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	(1,683)	(2,592)
Accounts receivable, net	175,540	184,052
Power Generation
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	2,164	1,876
Mining
Accounts Receivable [Line Items]
Allowance for Doubtful Accounts	0	0
Accounts receivable, net	2,277	3,988
Billed Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	144,747	146,716
Billed Revenues | Corporate, Non-Segment
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,271	5,008
Billed Revenues | Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	41,428	39,721
Billed Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	97,607	96,123
Billed Revenues | Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,164	1,876
Billed Revenues | Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,277	3,988
Unbilled Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	113,502	125,646
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	33,886	35,125
Unbilled Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	79,616	90,521
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 Sign_3

Business Description And Significant Accounting Policies: Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$ 2,444	$ 3,209	$ 3,081	$ 2,392
Additions Charged to Costs and Expenses	5,795	6,859	4,926
Recoveries and Other Additions	3,942	4,092	8,262
Write-offs and Other Deductions	(10,502)	(10,823)	(12,499)
Balance at End of Year	$ 2,444	$ 3,209	$ 3,081

Business Description And Sign_4

Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Materials and supplies	$ 82,809	$ 75,081
Fuel - Electric Utilities	2,425	2,850
Natural gas in storage	31,938	39,368
Total materials, supplies and fuel	$ 117,172	$ 117,299

Business Description And Sign_5

Business Description And Significant Accounting Policies: Investments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 28, 2019
Investment [Line Items]
Assets Held For Sale Used to Acquire Other Investments				$ 28,000
Discount Rate Used in Valuation of Fair Value of Oil and Gas Reserve Quantities	10.00%
Impairment of investment	$ 19,741	$ 0	$ 0
Investments	21,929	41,013
Equity Securities
Investment [Line Items]
Investments	8,359	28,100
Cash Surrender Value
Investment [Line Items]
Investments	13,056	12,812
Investments
Investment [Line Items]
Investments	$ 514	$ 101

Business Description And Sign_6

Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill	$ 1,299,454	$ 1,299,454	$ 1,299,454
Electric Utilities
Goodwill [Line Items]
Goodwill	248,479	248,479	248,479
Gas Utilities
Goodwill [Line Items]
Goodwill	1,042,210	1,042,210	1,042,210
Power Generation
Goodwill [Line Items]
Goodwill	$ 8,765	$ 8,765	$ 8,765

Business Description And Sign_7

Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 14,337	$ 7,559	$ 8,392
Intangible assets, additions	0	7,602	0
Intangible assets, amortization expense	(1,071)	(824)	(833)
Intangible assets, net, ending balance	13,266	$ 14,337	$ 7,559
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Future Amortization Expense, Year One	1,100
Future Amortization Expense, Year Two	1,100
Future Amortization Expense, Year Three	1,100
Future Amortization Expense, Year Four	1,100
Future Amortization Expense, Year Five	$ 1,100
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

Business Description And Sign_8

Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued employee compensation, benefits and withholdings	$ 62,837	$ 63,742
Accrued property taxes	44,547	42,510
Customer deposits and prepayments	54,728	43,574
Accrued interest	31,868	31,759
Contributions in Aid of Construction-current portion	1,952	1,485
Other (none of which is individually significant)	30,835	32,431
Total accrued liabilities	$ 226,767	$ 215,501

Business Description And Sign_9

Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Regulatory assets	$ 271,344	$ 284,235
Regulatory liabilities	$ 536,652	$ 540,794

Business Description And Sig_10

Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income available for common stock	$ 69,179	$ 11,740	$ 14,583	$ 103,808	$ 86,571	$ 16,950	$ 21,917	$ 133,004	$ 199,310	$ 258,442	$ 177,034
Weighted average shares - Basic (in shares)									60,662	54,420	53,221
Dilutive effect of:
Equity Units (in shares)									0	898	1,783
Equity compensation (in shares)									136	168	116
Weighted average shares - diluted (in shares)									60,798	55,486	55,120
Total earnings (loss) per share of common stock, Diluted (usd per share)	$ 1.13	$ 0.19	$ 0.24	$ 1.73	$ 1.49	$ 0.31	$ 0.40	$ 2.46	$ 3.28	$ 4.66	$ 3.21

Business Description And Sig_11

Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	1	16	11
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)	1	16	11

Business Description And Sig_12

Business Description And Significant Accounting Policies: Recently Adopted Accounting Standards (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating Lease, Liability	$ 5,000
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 3,390
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right-of-use asset		$ 3,100
Operating Lease, Liability		3,200
Deferred Rent Receivables, Net		4,500
Cumulative Effect of New Accounting Principle in Period of Adoption		$ 3,400

Revenue_ Disaggregation of Reve

Revenue: Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue from contracts with customers									$ 1,726,392	$ 1,748,542
Revenue	$ 477,654	$ 325,548	$ 333,888	$ 597,810	$ 501,196	$ 321,979	$ 355,704	$ 575,389	1,734,900	1,754,268	$ 1,680,266
Services transferred at a point in time
Revenue from contracts with customers									27,180	33,609
Services transferred over time
Revenue from contracts with customers									1,699,212	1,714,933
Other revenues
Revenue									8,508	5,726
Intercompany Eliminations
Revenue from contracts with customers									(149,205)	(141,428)
Revenue									(150,769)	(142,974)	$ (477,940)
Intercompany Eliminations | Revenues | Scenario, Adjustment
Changes To Our Segment Performance Measure - Income Statement										3,500
Intercompany Eliminations | Services transferred at a point in time
Revenue from contracts with customers									(32,053)	(32,194)
Intercompany Eliminations | Services transferred over time
Revenue from contracts with customers									(117,152)	(109,234)
Intercompany Eliminations | Other revenues
Revenue									(1,564)	(1,546)
Electric Utilities
Revenue from contracts with customers									707,561	709,024
Revenue									712,752	711,451
Electric Utilities | Services transferred at a point in time
Revenue from contracts with customers									0	0
Electric Utilities | Services transferred over time
Revenue from contracts with customers									707,561	709,024
Electric Utilities | Other revenues
Revenue									5,191	2,427
Gas Utilities
Revenue from contracts with customers									1,009,646	1,024,352
Revenue									1,010,030	1,025,307
Gas Utilities | Services transferred at a point in time
Revenue from contracts with customers									0	0
Gas Utilities | Services transferred over time
Revenue from contracts with customers									1,009,646	1,024,352
Gas Utilities | Other revenues
Revenue									384	955
Power Generation
Revenue from contracts with customers									99,157	90,791
Revenue									101,258	92,451
Power Generation | Services transferred at a point in time
Revenue from contracts with customers									0	0
Power Generation | Services transferred over time
Revenue from contracts with customers									99,157	90,791
Power Generation | Other revenues
Revenue									2,101	1,660
Power Generation | Other revenues | Revenues | Scenario, Adjustment
Changes To Our Segment Performance Measure - Income Statement										35,000
Mining
Revenue from contracts with customers									59,233	65,803
Revenue									61,629	68,033
Mining | Services transferred at a point in time
Revenue from contracts with customers									59,233	65,803
Mining | Services transferred over time
Revenue from contracts with customers									0	0
Mining | Other revenues
Revenue									2,396	2,230
Retail
Revenue from contracts with customers									1,450,776	1,461,317
Retail | Intercompany Eliminations
Revenue from contracts with customers									(32,053)	(32,194)
Retail | Electric Utilities
Revenue from contracts with customers									605,756	594,329
Retail | Gas Utilities
Revenue from contracts with customers									817,840	833,379
Retail | Power Generation
Revenue from contracts with customers									0	0
Retail | Mining
Revenue from contracts with customers									59,233	65,803
Transportation
Revenue from contracts with customers									142,348	139,357
Transportation | Intercompany Eliminations
Revenue from contracts with customers									(1,042)	(1,348)
Transportation | Electric Utilities
Revenue from contracts with customers									0	0
Transportation | Gas Utilities
Revenue from contracts with customers									143,390	140,705
Transportation | Power Generation
Revenue from contracts with customers									0	0
Transportation | Mining
Revenue from contracts with customers									0	0
Wholesale
Revenue from contracts with customers									28,464	39,521
Wholesale | Intercompany Eliminations
Revenue from contracts with customers									(91,577)	(84,957)
Wholesale | Electric Utilities
Revenue from contracts with customers									20,884	33,687
Wholesale | Gas Utilities
Revenue from contracts with customers									0	0
Wholesale | Power Generation
Revenue from contracts with customers									99,157	90,791
Wholesale | Power Generation | Revenues | Scenario, Adjustment
Changes To Our Segment Performance Measure - Income Statement										38,000
Wholesale | Mining
Revenue from contracts with customers									0	0
Market - off-system sales
Revenue from contracts with customers									16,772	17,563
Market - off-system sales | Intercompany Eliminations
Revenue from contracts with customers									(7,736)	(8,102)
Market - off-system sales | Electric Utilities
Revenue from contracts with customers									23,817	24,799
Market - off-system sales | Gas Utilities
Revenue from contracts with customers									691	866
Market - off-system sales | Power Generation
Revenue from contracts with customers									0	0
Market - off-system sales | Mining
Revenue from contracts with customers									0	0
Transmission/Other
Revenue from contracts with customers									88,032	90,784
Transmission/Other | Intercompany Eliminations
Revenue from contracts with customers									(16,797)	(14,827)
Transmission/Other | Electric Utilities
Revenue from contracts with customers									57,104	56,209
Transmission/Other | Gas Utilities
Revenue from contracts with customers									47,725	49,402
Transmission/Other | Power Generation
Revenue from contracts with customers									0	0
Transmission/Other | Mining
Revenue from contracts with customers									$ 0	$ 0

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 6,784,679	$ 6,000,015
Less accumulated depreciation and depletion	(1,281,493)	(1,145,136)
Total property, plant and equipment, net	5,503,186	4,854,879
Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	29,055	22,269
Less accumulated depreciation and depletion	(964)	(670)
Total property, plant and equipment, net	28,091	21,599
Construction in progress, gross	23,334	16,548
Property, Plant and Equipment	$ 5,721	5,721
Corporate, Non-Segment | Scenario, Adjustment | Accumulated Depreciation and Amortization
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		18,000
Corporate, Non-Segment | Scenario, Adjustment | Net Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		$ (18,000)
Weighted Average | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	10 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	$ 2,956,867	$ 2,787,851
Construction work in progress	102,268	60,480
Property, plant and equipment	3,059,135	2,848,331
Less accumulated depreciation and depletion	(670,861)	(615,365)
Total property, plant and equipment, net	$ 2,388,274	2,232,966
Depreciation, depletion and amortization, remaining amortization period	11 years
Electric Utilities | Scenario, Adjustment | Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		(261,000)
Electric Utilities | Scenario, Adjustment | Accumulated Depreciation and Amortization
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		91,000
Electric Utilities | Scenario, Adjustment | Net Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		(170,000)
Electric Utilities | Production, Electric
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 1,348,049	$ 1,318,643
Electric Utilities | Production, Electric | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	41 years	41 years
Electric Utilities | Production, Electric | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	32 years
Electric Utilities | Production, Electric | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	46 years
Electric Utilities | Electric transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 483,640	$ 437,082
Electric Utilities | Electric transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	51 years	51 years
Electric Utilities | Electric transmission | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	43 years
Electric Utilities | Electric transmission | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	54 years
Electric Utilities | Electric distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 861,042	$ 793,725
Electric Utilities | Electric distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	47 years	48 years
Electric Utilities | Electric distribution | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	46 years
Electric Utilities | Electric distribution | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	50 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	$ 259,266	$ 233,531
Electric Utilities | General | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	28 years	28 years
Electric Utilities | General | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	26 years
Electric Utilities | General | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	33 years
Gas Utilities
Property, Plant and Equipment [Line Items]
Total plant in service before construction work in progress	$ 2,918,418	$ 2,468,260
Construction work in progress	63,080	38,271
Property, plant and equipment	2,981,498	2,506,531
Less accumulated depreciation and depletion	(336,721)	(279,580)
Total property, plant and equipment, net	2,644,777	2,226,951
Gas Utilities | Production, Gas
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 13,000	$ 13,580
Gas Utilities | Production, Gas | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	35 years	35 years
Gas Utilities | Production, Gas | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	24 years
Gas Utilities | Production, Gas | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	71 years
Gas Utilities | Gas transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 516,172	$ 423,873
Gas Utilities | Gas transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	50 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	67 years
Gas Utilities | Gas distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 1,857,233	$ 1,595,644
Gas Utilities | Gas distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	43 years	42 years
Gas Utilities | Gas distribution | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	30 years
Gas Utilities | Gas distribution | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	56 years
Gas Utilities | Cushion Gas - Depreciable
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 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, processing and storage	$ 44,443	$ 46,369
Gas Utilities | Gas, Storage
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 46,977	$ 29,335
Gas Utilities | Gas, Storage | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	31 years	30 years
Gas Utilities | Gas, Storage | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	27 years
Gas Utilities | Gas, Storage | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	49 years
Gas Utilities | General
Property, Plant and Equipment [Line Items]
General	$ 437,054	$ 355,920
Gas Utilities | General | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	20 years	19 years
Gas Utilities | General | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	10 years
Gas Utilities | General | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	24 years
Power Generation
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 534,518	$ 447,234
Less accumulated depreciation and depletion	(154,362)	(137,832)
Total property, plant and equipment, net	380,156	309,402
Construction in progress, gross	2,121	11,796
Property, Plant and Equipment	$ 532,397	435,438
Power Generation | Scenario, Adjustment | Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		261,000
Power Generation | Scenario, Adjustment | Accumulated Depreciation and Amortization
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		(73,000)
Power Generation | Scenario, Adjustment | Net Property, Plant and Equipment
Property, Plant and Equipment [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		$ 188,000
Power Generation | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	31 years	31 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	$ 180,473	$ 175,650
Less accumulated depreciation and depletion	(118,585)	(111,689)
Total property, plant and equipment, net	61,888	63,961
Construction in progress, gross	1,275	0
Property, Plant and Equipment	$ 179,198	$ 175,650
Mining | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	13 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	Dec. 31, 2019USD ($)MW
Wyodak Plant | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	20.00%
Plant in Service	$ 116,074
Construction Work in Progress	729
Less Accumulated Depreciation	(64,413)
Jointly Owned Utility Plant, Net Ownership Amount	$ 52,390
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	$ 19,862
Construction Work in Progress	4,161
Less Accumulated Depreciation	(6,612)
Jointly Owned Utility Plant, Net Ownership Amount	$ 17,411
Wygen I I I Generating Facility | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	52.00%
Plant in Service	$ 146,161
Construction Work in Progress	400
Less Accumulated Depreciation	(25,518)
Jointly Owned Utility Plant, Net Ownership Amount	$ 121,043
Wygen I Generating Facility | Power Generation
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	76.50%
Plant in Service	$ 120,824
Construction Work in Progress	289
Less Accumulated Depreciation	(48,703)
Jointly Owned Utility Plant, Net Ownership Amount	$ 72,410

Jointly Owned Facilities - Rela

Jointly Owned Facilities - Related Party (Details) - USD ($) $ in Millions	Dec. 11, 2018	Dec. 31, 2019
Jointly Owned Utility Plant Interests [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	50.00%
Total consideration paid, net of working-capital adjustment received	$ 16
Fair Value
Jointly Owned Utility Plant Interests [Line Items]
Property, plant & equipment, net	8.7
Fair Value | Contractual Rights
Jointly Owned Utility Plant Interests [Line Items]
Indefinite-lived Intangible Assets Acquired	$ 7.6
Busch Ranch I Wind Farm
Jointly Owned Utility Plant Interests [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired	50.00%
Electric Utilities | Busch Ranch I Wind Farm
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%	50.00%

Business Segment Information_ I

Business Segment Information: Intercompany Power Purchase Agreement (Details)	Dec. 31, 2019MW
Pueblo Airport Generation | Subsidiary of Common Parent
Segment Reporting Information [Line Items]
Megawatts of Capacity Purchased	200

Business Segment Information_ S

Business Segment Information: Segment Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting, Asset Reconciling Item
Total Assets	$ 7,558,457	$ 6,963,327
Corporate, Non-Segment
Segment Reporting, Asset Reconciling Item
Total Assets	130,245	209,478
Electric Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	2,900,983	2,707,695
Electric Utilities | Scenario, Adjustment | Assets, Total
Segment Reporting, Asset Reconciling Item
Changes To Our Segment Performance Measure - Balance Sheet		(188,000)
Gas Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	4,032,339	3,623,475
Power Generation
Segment Reporting, Asset Reconciling Item
Total Assets	417,715	342,085
Power Generation | Scenario, Adjustment | Assets, Total
Segment Reporting, Asset Reconciling Item
Changes To Our Segment Performance Measure - Balance Sheet		188,000
Mining
Segment Reporting, Asset Reconciling Item
Total Assets	$ 77,175	$ 80,594

Business Segment Information_ C

Business Segment Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Capital Expenditures	$ 849,755	$ 504,826
Continuing Operations
Segment Reporting Information [Line Items]
Capital Expenditures	849,755	502,424
Continuing Operations | Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital Expenditures	20,702	11,723
Continuing Operations | Electric Utilities
Segment Reporting Information [Line Items]
Capital Expenditures	222,911	152,524
Continuing Operations | Gas Utilities
Segment Reporting Information [Line Items]
Capital Expenditures	512,366	288,438
Continuing Operations | Power Generation
Segment Reporting Information [Line Items]
Capital Expenditures	85,346	30,945
Continuing Operations | Mining
Segment Reporting Information [Line Items]
Capital Expenditures	8,430	18,794
Discontinued Operations
Segment Reporting Information [Line Items]
Capital Expenditures	$ 0	$ 2,402

Business Segment Information_ P

Business Segment Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	$ 6,784,679	$ 6,000,015
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	29,055	22,269
Electric Utilities
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	3,059,135	2,848,331
Gas Utilities
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	2,981,498	2,506,531
Power Generation
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	534,518	447,234
Mining
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	$ 180,473	175,650
Property, Plant and Equipment | Scenario, Adjustment | Electric Utilities
Segment Reporting Information [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		(261,000)
Property, Plant and Equipment | Scenario, Adjustment | Power Generation
Segment Reporting Information [Line Items]
Changes To Our Segment Performance Measure - Balance Sheet		$ 261,000

Business Segment Information__2

Business Segment Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information
Revenue from contracts with customers									$ 1,726,392	$ 1,748,542
Revenue	$ 477,654	$ 325,548	$ 333,888	$ 597,810	$ 501,196	$ 321,979	$ 355,704	$ 575,389	1,734,900	1,754,268	$ 1,680,266
Fuel, purchased power and cost of natural gas sold									570,829	625,610	563,288
Operations and maintenance									548,909	535,293	511,996
Depreciation, depletion and amortization									(209,120)	(196,328)	(188,246)
Operating income	121,359	70,551	54,001	160,131	114,127	65,085	69,551	148,274	406,042	397,037	416,736
Interest expense									(137,659)	(139,975)	(137,102)
Impairment of investment									(19,741)	0	0
Other income (expense), net									(5,740)	(1,180)	2,108
Income tax benefit (expense)									(29,580)	23,667	(73,367)
Income from continuing operations	72,872	15,395	17,693	107,362	91,604	21,801	27,167	138,977	213,322	279,549	208,375
(Income) loss from discontinued operations, net of tax	0	0	0	0	(1,260)	(857)	(2,427)	(2,343)	0	(6,887)	(17,099)
Net income (loss)									213,322	272,662	191,276
Net income attributable to noncontrolling interest	(3,693)	(3,655)	(3,110)	(3,554)	(3,773)	(3,994)	(2,823)	(3,630)	(14,012)	(14,220)	(14,242)
Net income (loss) available for common stock	$ 69,179	$ 11,740	$ 14,583	$ 103,808	86,571	$ 16,950	$ 21,917	133,004	199,310	258,442	177,034
Deferred Income Tax Expense (Benefit)									(38,020)	24,239	(80,992)
Scenario, Adjustment
Segment Reporting Information
Fuel, purchased power and cost of natural gas sold										0	0
Depreciation, depletion and amortization										0	0
Adjusted operating income (loss)										0	0
Other Restructuring
Segment Reporting Information
Deferred Income Tax Expense (Benefit)					$ (23,000)			$ (49,000)		73,000
Electric Utilities
Segment Reporting Information
Revenue from contracts with customers									707,561	709,024
Revenue									712,752	711,451
Fuel, purchased power and cost of natural gas sold									268,297	283,840	274,363
Operations and maintenance									195,581	186,175	172,307
Depreciation, depletion and amortization									(88,577)	(85,567)	(80,243)
Adjusted operating income (loss)									160,297	155,869	177,737
Electric Utilities | Scenario, Adjustment
Segment Reporting Information
Fuel, purchased power and cost of natural gas sold										6,700	6,000
Depreciation, depletion and amortization										(13,100)	(13,100)
Adjusted operating income (loss)										6,400	7,100
Gas Utilities
Segment Reporting Information
Revenue from contracts with customers									1,009,646	1,024,352
Revenue									1,010,030	1,025,307
Fuel, purchased power and cost of natural gas sold									425,898	462,153	409,603
Operations and maintenance									301,844	291,481	269,190
Depreciation, depletion and amortization									(92,317)	(86,434)	(83,732)
Adjusted operating income (loss)									189,971	185,239	185,105
Power Generation
Segment Reporting Information
Revenue from contracts with customers									99,157	90,791
Revenue									101,258	92,451
Fuel, purchased power and cost of natural gas sold									9,059	8,592	9,340
Operations and maintenance									28,429	25,135	23,042
Depreciation, depletion and amortization									(18,991)	(16,110)	(15,548)
Adjusted operating income (loss)									44,779	42,614	46,690
Net income attributable to noncontrolling interest									(14,000)	(14,000)	(14,000)
Power Generation | Scenario, Adjustment
Segment Reporting Information
Fuel, purchased power and cost of natural gas sold										0	0
Depreciation, depletion and amortization										9,200	9,600
Adjusted operating income (loss)										(5,700)	(6,500)
Mining
Segment Reporting Information
Revenue from contracts with customers									59,233	65,803
Revenue									61,629	68,033
Fuel, purchased power and cost of natural gas sold									0	0	0
Operations and maintenance									40,032	43,728	44,882
Depreciation, depletion and amortization									(8,970)	(7,965)	(8,239)
Adjusted operating income (loss)									12,627	16,340	13,500
Intercompany Eliminations
Segment Reporting Information
Revenue from contracts with customers									(149,205)	(141,428)
Revenue									(150,769)	(142,974)	(477,940)
Fuel, purchased power and cost of natural gas sold									(132,693)	(129,019)	(130,169)
Operations and maintenance									(303,776)	(336,142)	(293,492)
Depreciation, depletion and amortization									21,800	20,909	20,547
Adjusted operating income (loss)									(36,705)	(36,827)	(33,732)
Intercompany Eliminations | Scenario, Adjustment
Segment Reporting Information
Fuel, purchased power and cost of natural gas sold										(6,700)	(6,000)
Depreciation, depletion and amortization										3,900	3,500
Adjusted operating income (loss)										(700)	(600)
Operating Segments | Electric Utilities
Segment Reporting Information
Revenue											704,650
Operating Segments | Gas Utilities
Segment Reporting Information
Revenue											947,630
Operating Segments | Power Generation
Segment Reporting Information
Revenue											94,620
Operating Segments | Mining
Segment Reporting Information
Revenue											66,621
Corporate, Non-Segment
Segment Reporting Information
Revenue									344,205	379,923	344,685
Fuel, purchased power and cost of natural gas sold									268	44	151
Operations and maintenance									286,799	324,916	296,067
Depreciation, depletion and amortization									(22,065)	(21,161)	(21,031)
Adjusted operating income (loss)									35,073	33,802	27,436
Consolidation, Eliminations
Segment Reporting Information
Revenue											0
Other revenues
Segment Reporting Information
Revenue									8,508	5,726
Other revenues | Electric Utilities
Segment Reporting Information
Revenue									5,191	2,427
Other revenues | Gas Utilities
Segment Reporting Information
Revenue									384	955
Other revenues | Power Generation
Segment Reporting Information
Revenue									2,101	1,660
Other revenues | Mining
Segment Reporting Information
Revenue									2,396	2,230
Other revenues | Intercompany Eliminations
Segment Reporting Information
Revenue									(1,564)	(1,546)
External Customers
Segment Reporting Information
Revenue from contracts with customers									1,726,392	1,748,542
Revenue									1,734,900	1,754,268
External Customers | Electric Utilities
Segment Reporting Information
Revenue from contracts with customers									684,445	686,272
Revenue									689,636	688,699	689,945
External Customers | Gas Utilities
Segment Reporting Information
Revenue from contracts with customers									1,007,187	1,022,828
Revenue									1,007,571	1,023,783	947,595
External Customers | Power Generation
Segment Reporting Information
Revenue from contracts with customers									7,580	5,833
Revenue									9,439	7,246	7,263
External Customers | Mining
Segment Reporting Information
Revenue from contracts with customers									27,180	33,609
Revenue									28,254	34,540	35,463
External Customers | Other revenues
Segment Reporting Information
Revenue									8,508	5,726
External Customers | Other revenues | Electric Utilities
Segment Reporting Information
Revenue									5,191	2,427
External Customers | Other revenues | Gas Utilities
Segment Reporting Information
Revenue									384	955
External Customers | Other revenues | Power Generation
Segment Reporting Information
Revenue									1,859	1,413
External Customers | Other revenues | Mining
Segment Reporting Information
Revenue									1,074	931
Intercompany Customers
Segment Reporting Information
Revenue from contracts with customers									0	0
Revenue									0	0
Intercompany Customers | Scenario, Adjustment
Segment Reporting Information
Revenue from contracts with customers										0	0
Intercompany Customers | Electric Utilities
Segment Reporting Information
Revenue from contracts with customers									23,116	22,752
Revenue									23,116	22,752	14,705
Intercompany Customers | Electric Utilities | Scenario, Adjustment
Segment Reporting Information
Revenue from contracts with customers										0	0
Intercompany Customers | Gas Utilities
Segment Reporting Information
Revenue from contracts with customers									2,459	1,524
Revenue									2,459	1,524	35
Intercompany Customers | Power Generation
Segment Reporting Information
Revenue from contracts with customers									91,577	84,959
Revenue									91,819	85,205	87,357
Intercompany Customers | Power Generation | Scenario, Adjustment
Segment Reporting Information
Revenue from contracts with customers										3,500	3,100
Intercompany Customers | Mining
Segment Reporting Information
Revenue from contracts with customers									32,053	32,194
Revenue									33,375	33,493	31,158
Intercompany Customers | Intercompany Eliminations
Segment Reporting Information
Revenue from contracts with customers									(149,435)	(141,577)
Revenue									(494,974)	(522,897)
Intercompany Customers | Intercompany Eliminations | Scenario, Adjustment
Segment Reporting Information
Revenue from contracts with customers										(3,500)	$ (3,100)
Intercompany Customers | Corporate, Non-Segment
Segment Reporting Information
Revenue from contracts with customers									230	148
Revenue									344,205	379,923
Intercompany Customers | Other revenues
Segment Reporting Information
Revenue									0	0
Intercompany Customers | Other revenues | Electric Utilities
Segment Reporting Information
Revenue									0	0
Intercompany Customers | Other revenues | Gas Utilities
Segment Reporting Information
Revenue									0	0
Intercompany Customers | Other revenues | Power Generation
Segment Reporting Information
Revenue									242	246
Intercompany Customers | Other revenues | Mining
Segment Reporting Information
Revenue									1,322	1,299
Intercompany Customers | Other revenues | Intercompany Eliminations
Segment Reporting Information
Revenue									(345,539)	(381,320)
Intercompany Customers | Other revenues | Corporate, Non-Segment
Segment Reporting Information
Revenue									$ 343,975	$ 379,775

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Oct. 03, 2019	Dec. 31, 2018	Dec. 12, 2018
Debt Instrument [Line Items]
Total long-term debt	$ 3,170,489		$ 2,977,568
Less current maturities	5,743		5,743
Less unamortized deferred financing costs	24,650		20,990
Long-term debt, net of current maturities	3,140,096		2,950,835
Revolving Credit Facility
Debt Instrument [Line Items]
Less unamortized deferred financing costs	1,700		2,300
Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Stated interest rate (percent)		5.875%
Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Stated interest rate (percent)				2.50%
Corporate Term Loan Due July 2020
Debt Instrument [Line Items]
Long-term debt	300,000
Corporate, Non-Segment | Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Stated interest rate (percent)		3.05%
Corporate, Non-Segment | Senior Unsecured Notes Due 2049
Debt Instrument [Line Items]
Stated interest rate (percent)		3.875%
Black Hills Corporation | Corporate, Non-Segment
Debt Instrument [Line Items]
Long-term debt	2,632,178		2,437,921
Less unamortized debt discount	(6,462)		(5,122)
Total long-term debt	$ 2,625,716		2,432,799
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2023
Debt Instrument [Line Items]
Stated interest rate (percent)	4.25%
Long-term debt	$ 525,000		525,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Long-term debt	$ 0		200,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026
Debt Instrument [Line Items]
Stated interest rate (percent)	3.95%
Long-term debt	$ 300,000		300,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Stated interest rate (percent)	3.15%
Long-term debt	$ 400,000		400,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2033
Debt Instrument [Line Items]
Stated interest rate (percent)	4.35%
Long-term debt	$ 400,000		400,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046
Debt Instrument [Line Items]
Stated interest rate (percent)	4.20%
Long-term debt	$ 300,000		300,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Stated interest rate (percent)	3.05%
Long-term debt	$ 400,000		0
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2049
Debt Instrument [Line Items]
Stated interest rate (percent)	3.88%
Long-term debt	$ 300,000		0
Black Hills Corporation | Corporate, Non-Segment | Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Stated interest rate (percent)	2.32%
Long-term debt	$ 7,178		12,921
Black Hills Corporation | Corporate, Non-Segment | London Interbank Offered Rate (LIBOR) | Corporate Term Loan Due July 2020
Debt Instrument [Line Items]
Long-term debt	0		300,000
South Dakota Electric | Electric Utilities
Debt Instrument [Line Items]
Long-term debt	342,855		342,855
Less unamortized debt discount	(82)		(86)
Total long-term debt	$ 342,773		342,769
South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Stated interest rate (percent)	4.43%
Long-term debt	$ 85,000		85,000
South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2032
Debt Instrument [Line Items]
Stated interest rate (percent)	7.23%
Long-term debt	$ 75,000		75,000
South Dakota Electric | Electric Utilities | First Mortgage Bonds Due 2039
Debt Instrument [Line Items]
Stated interest rate (percent)	6.13%
Long-term debt	$ 180,000		180,000
South Dakota Electric | Electric Utilities | Series 94 A Debt, Due 2024
Debt Instrument [Line Items]
Variable interest rate (percent)	1.84%
Long-term debt	$ 2,855		2,855
Wyoming Electric | Electric Utilities
Debt Instrument [Line Items]
Long-term debt	202,000		202,000
Less unamortized debt discount	0		0
Total long-term debt	$ 202,000		202,000
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Stated interest rate (percent)	4.53%
Long-term debt	$ 75,000		75,000
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2037
Debt Instrument [Line Items]
Stated interest rate (percent)	6.67%
Long-term debt	$ 110,000		110,000
Wyoming Electric | Electric Utilities | Industrial Development Revenue Bonds Due 2021
Debt Instrument [Line Items]
Variable interest rate (percent)	1.68%
Long-term debt	$ 7,000		7,000
Wyoming Electric | Electric Utilities | Industrial Development Revenue Bonds Due 2027
Debt Instrument [Line Items]
Variable interest rate (percent)	1.68%
Long-term debt	$ 10,000		$ 10,000

Long-Term Debt_ Aggregate Matur

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Long-term Debt, Unclassified [Abstract]
Less current maturities	$ 5,743	$ 5,743
2021	8,435
2022	0
2023	525,000
2024	2,855
Thereafter	$ 2,635,000

Long-Term Debt_ Debt Transactio

Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands	Oct. 03, 2019	Jun. 17, 2019	Dec. 12, 2018	Aug. 17, 2018	Dec. 31, 2019	Dec. 31, 2018
Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 400,000
Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Stated interest rate (percent)	5.875%
Extinguishment of Debt, Amount	$ 200,000
Corporate Term Loan Due July 2020
Debt Instrument [Line Items]
Long-term debt					$ 300,000
Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Stated interest rate (percent)			2.50%
Extinguishment of Debt, Amount			$ 250,000
Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Extinguishment of Debt, Amount				$ 299,000
Remarketable Junior Subordinated Notes Due 2028 | Junior Subordinated Debt
Debt Instrument [Line Items]
Stated interest rate (percent)					4.579%
Corporate, Non-Segment
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	700,000
Corporate, Non-Segment | Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 400,000
Stated interest rate (percent)	3.05%
Long-term Debt, Term	10 years
Corporate, Non-Segment | Senior Unsecured Notes Due 2049
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 300,000
Stated interest rate (percent)	3.875%
Long-term Debt, Term	30 years
Corporate, Non-Segment | Corporate Term Loan Due 2033
Debt Instrument [Line Items]
Stated interest rate (percent)				4.35%
Proceeds from senior unsecured notes				$ 400,000
Corporate, Non-Segment | Black Hills Corporation
Debt Instrument [Line Items]
Long-term debt					$ 2,632,178	$ 2,437,921
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Stated interest rate (percent)					3.05%
Long-term debt					$ 400,000	0
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2049
Debt Instrument [Line Items]
Stated interest rate (percent)					3.88%
Long-term debt					$ 300,000	0
Corporate, Non-Segment | Black Hills Corporation | Corporate Term Loan Due June 2021
Debt Instrument [Line Items]
Proceeds from Issuance of Debt		$ 400,000
Stated interest rate (percent)					2.32%
Long-term debt					$ 7,178	12,921
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2020
Debt Instrument [Line Items]
Long-term debt					$ 0	200,000
Corporate, Non-Segment | Black Hills Corporation | Corporate Term Loan Due July 2020
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 300,000
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2033
Debt Instrument [Line Items]
Stated interest rate (percent)					4.35%
Long-term debt					$ 400,000	$ 400,000

Long-Term Debt_ Amortization Ex

Long-Term Debt: Amortization Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Long-term Debt, Unclassified [Abstract]
Deferred Finance Costs Remaining, Noncurrent	$ 24,650
Amortization expense for deferred financing costs	$ 3,242	$ 2,829	$ 3,349

Long-Term Debt_ Dividend Restri

Long-Term Debt: Dividend Restrictions (Details) $ in Millions	Dec. 31, 2019USD ($)
Utilities Group
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$ 156

Notes Payable (Details)

Notes Payable (Details)	12 Months Ended
	Dec. 31, 2019USD ($)credit_extension	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jul. 30, 2018USD ($)
Short-term Debt [Line Items]
Notes payable	$ 349,500,000	$ 185,620,000
Letters of Credit Outstanding, Amount	30,274,000	22,311,000
Commercial Paper, Maximum Borrowing Capacity	750,000,000
Net (payments) borrowings of short-term debt	$ 163,880,000	(25,680,000)	$ 114,700,000
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	$ 349,500,000	185,620,000
Debt Instrument, Term	397 days
Debt, Weighted Average Interest Rate	2.03%
Revolving Credit Facility
Short-term Debt [Line Items]
Notes payable	$ 0	0
Letters of Credit Outstanding, Amount	$ 30,274,000	$ 22,311,000
Line of Credit Facility, Current Borrowing Capacity				$ 750,000,000
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	0.175%
Debt Issuance Cost, Gross, Noncurrent	$ 6,700,000
Revolving Credit Facility | Base Rate
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End	0.125%
Revolving Credit Facility | Eurodollar
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End	1.125%
Revolving Credit Facility | Letter of Credit
Short-term Debt [Line Items]
Line of Credit Facility, Interest Rate at Period End	1.125%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 11, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 56,800	$ 52,024
Liabilities Incurred	3,445	152
Liabilities Settled	(380)	(4)
Accretion	2,741	2,155
Revisions to Prior Estimates	1,599	2,473
Ending Balance	64,205	56,800
Electric Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	6,558	6,287
Liabilities Incurred	0	0
Liabilities Settled	0	0
Accretion	385	269
Revisions to Prior Estimates	2,686	2
Ending Balance	$ 9,329	6,558
Electric Utilities | Busch Ranch I Wind Farm
Asset Retirement Obligation Costs [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%		50.00%
Gas Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 34,627	33,238
Liabilities Incurred	0	152
Liabilities Settled	0	0
Accretion	1,458	1,237
Revisions to Prior Estimates	0	0
Ending Balance	36,085	34,627
Power Generation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	300
Liabilities Incurred	3,445
Liabilities Settled	0
Accretion	158
Revisions to Prior Estimates	836
Ending Balance	4,739	300
Mining
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	15,615	12,499
Liabilities Incurred	0	0
Liabilities Settled	(380)	(4)
Accretion	740	649
Revisions to Prior Estimates	(1,923)	2,471
Ending Balance	14,052	15,615
Scenario, Adjustment | Electric Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	6,258
Ending Balance		6,258
Scenario, Adjustment | Power Generation | Busch Ranch I Wind Farm
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 300
Ending Balance		$ 300

Risk Management Activities_ Uti

Risk Management Activities: Utilities (Details) - Natural Gas, Distribution $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)MMBTU	Dec. 31, 2018MMBTU
Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,450,000	4,000,000
Derivative, Remaining Maturity	12 months	24 months
Commodity Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,240,000	4,320,000
Derivative, Remaining Maturity	3 months	13 months
Basis Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	1,290,000	3,960,000
Derivative, Remaining Maturity	12 months	24 months
Fixed for Float Swaps Purchased
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	4,600,000	3,660,000
Derivative, Remaining Maturity	24 months	24 months
Fixed for Float Swaps Purchased | Cash Flow Hedging
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure	1,415,000
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ 0.5
Natural Gas Physical Purchases
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	13,548,235	18,325,852
Derivative, Remaining Maturity	12 months	30 months

Risk Management Activities_ Cas

Risk Management Activities: Cash Flow Hedges (Details) - Cash Flow Hedging - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	$ 1,886	$ 3,964	$ 2,637
Interest Rate Swap | Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2,851	2,851	2,941
Commodity Contract | Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	(548)	983	366
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(417)	130	(670)
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2,434)	(2,981)	(2,271)
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | Interest Rate Swap | Interest Expense
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2,851)	(2,851)	(2,941)
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | Commodity Contract | Net (loss) from Discontinued Operations
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			913
Reclassification out of Accumulated Other Comprehensive Income | Cash Flow Hedging | Commodity Contract | Fuel, purchased power and cost of natural gas sold
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 417	$ (130)	$ (243)

Risk Management Activities_ Der

Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory assets	$ 271,344	$ 284,235
Deferred Derivative Gain (Loss)
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory assets	3,300	6,200
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(1,100)	1,101	$ (2,207)
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	$ (1,100)	$ 1,101	$ (2,207)

Schedule of Fair Values (Detail

Schedule of Fair Values (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	$ 348	$ 1,519
Derivative, Liabilities, Fair Value Disclosure	2,345	1,007
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	(1,085)	(1,408)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(2,909)	(5,794)
Fair Value, Measurements, Recurring | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	348	1,519
Derivative Liabilities, Total	2,345	1,007
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	1,433	2,927
Derivative Liabilities, Total	5,254	6,801
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, Measurements, Recurring | Commodity Contract
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	(1,085)	(1,408)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(2,909)	(5,794)
Fair Value, Measurements, Recurring | Commodity Contract | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	348	1,519
Derivative, Liabilities, Fair Value Disclosure	2,345	1,007
Fair Value, Measurements, Recurring | Commodity Contract | 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
Fair Value, Measurements, Recurring | Commodity Contract | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	1,433	2,927
Derivative, Liabilities, Fair Value Disclosure	5,254	6,801
Fair Value, Measurements, Recurring | Commodity Contract | 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

Fair Value Measurements_ Balanc

Fair Value Measurements: Balance Sheet Location (Details) - Commodity derivatives - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Fair Value Hedges, Net	$ (515)	$ 315
Designated as Hedging Instrument | Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Fair Value Hedge Assets	1	415
Designated as Hedging Instrument | Derivative Assets, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Fair Value Hedge Assets	3	18
Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Current	(490)	(114)
Designated as Hedging Instrument | Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Current	(29)	(4)
Not Designated as Hedging Instrument
Derivatives, Carrying Amount and Fair Value [Line Items]
Fair Value Hedges, Net	(1,484)	197
Not Designated as Hedging Instrument | Derivative Assets, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Fair Value Hedge Assets	341	1,085
Not Designated as Hedging Instrument | Derivative Assets, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Fair Value Hedge Assets	2	1
Not Designated as Hedging Instrument | Derivative Liabilities, Current
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Current	(1,764)	(833)
Not Designated as Hedging Instrument | Derivative Liabilities, Noncurrent
Derivatives, Carrying Amount and Fair Value [Line Items]
Derivative Liability, Current	$ (63)	$ (56)

Fair Value Measurements_ Bala_2

Fair Value Measurements: Balance Sheet Offsetting (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 1,433	$ 2,927
Gross Amounts Offset In Statement Of Financial Position Assets	(1,085)	(1,408)
Derivative Asset	348	1,519
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	5,253	6,801
Gross Amounts Offset In Statement Of Financial Position Liabilities	(2,908)	(5,794)
Derivative Liability	2,345	1,007
Contract Subject to Master Netting Arrangement
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	1,085	1,408
Gross Amounts Offset In Statement Of Financial Position Assets	(1,085)	(1,408)
Derivative Asset	0	0
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	2,908	5,794
Gross Amounts Offset In Statement Of Financial Position Liabilities	(2,908)	(5,794)
Derivative Liability	0	0
Contract Not Subject to Master Netting Arrangement
Derivative Asset [Abstract]
Derivative Asset, Fair Value, Gross Asset	348	1,519
Gross Amounts Offset In Statement Of Financial Position Assets	0	0
Derivative Asset	348	1,519
Derivative Liability [Abstract]
Derivative Liability, Fair Value, Gross Liability	2,345	1,007
Gross Amounts Offset In Statement Of Financial Position Liabilities	0	0
Derivative Liability	$ 2,345	$ 1,007

Fair Value of Financial Instr_3

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	$ 9,777	$ 20,776
Restricted cash - carrying amount	3,881	3,369
Notes payable	349,500	185,620
Carrying Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents - carrying amount	9,777	20,776
Restricted cash - carrying amount	3,881	3,369
Notes payable	349,500	185,620
Long-term debt, including current maturities - carrying amount	3,145,839	2,956,578
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	9,777	20,776
Restricted Cash Fair Value Disclosure	3,881	3,369
Notes payable - fair value	349,500	185,620
Long-term debt, including current maturities - fair value	$ 3,479,367	$ 3,039,108

Equity_ At-the-Market Equity Of

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Aug. 04, 2017
At The Market Equity Offering Program Authorized Aggregate Value		$ 300
Common Stock
At The Market Equity Offering Program Shares Issued	1,328,332
At The Market Equity Program Proceeds from Sale of Stock	$ 99
Payments of Stock Issuance Costs	$ 1.2

Equity Units (Details)

Equity Units (Details) $ / shares in Units, shares in Thousands	Dec. 12, 2018USD ($)	Nov. 01, 2018USD ($)shares	Oct. 29, 2018$ / shares	Aug. 17, 2018USD ($)	Nov. 23, 2015USD ($)shares$ / shares
Debt Instrument [Line Items]
Proceeds from Sale of Interest in Corporate Unit					$ 299,000,000
Equity Unit Stated Amount (usd per share) | $ / shares			$ 50		$ 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
Sale of Stock, Consideration Received on Transaction		$ 299,000,000
Sale of Stock, Number of Shares Issued in Transaction | shares		6,372
Remarketable Junior Subordinated Notes Due 2028
Debt Instrument [Line Items]
Issuance of equity units | shares					5,980
Debt Instrument, Convertible, Conversion Ratio			1.0655
Extinguishment of Debt, Amount				$ 299,000,000
Senior Unsecured Notes Due 2019
Debt Instrument [Line Items]
Extinguishment of Debt, Amount	$ 250,000,000

Equity_ Equity Compensation Pla

Equity: Equity Compensation Plans (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stockholders' Equity Note [Abstract]
Shares available for grant	672,049
Unrecognized compensation expense	$ 12,000
Weighted-average recognition period	2 years
Stock-based compensation expense	$ 12,095	$ 12,390	$ 7,626

Equity_ Stock Options (Details)

Equity: Stock Options (Details)	Dec. 31, 2019shares
Employee Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares exercisable at end of period	14,000

Equity_ Restricted Stock (Detai

Equity: Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Weighted Average Grant Date Fair Value
Restricted Stock and RSUs, total fair value of shares vested	$ 5,720	$ 0	$ 0
Unrecognized compensation expense	$ 12,000
Weighted-average recognition period	2 years
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	236
Shares Granted	92
Shares Vested	(120)
Shares Forfeited	(16)
Restricted Stock at end of period	192	236
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)	$ 57.50
Granted (usd per share)	73.66	$ 57.31	$ 60.63
Vested (usd per share)	56.33
Forfeited (usd per share)	62.02
Balance at end of period (usd per share)	$ 65.66	$ 57.50
Restricted Stock and RSUs, total fair value of shares vested	$ 8,438	$ 6,776	$ 7,909
Unrecognized compensation expense	$ 9,000
Weighted-average recognition period	2 years 1 month 6 days

Equity_ Performance Share Plan

Equity: Performance Share Plan (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense				$ 12,000
Performance Plan Payouts [Abstract]
Stock Issued During Period, Shares, Treasury Stock Reissued	44	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 2,860	$ 0	$ 0
Restricted Stock and RSUs, total fair value of shares vested	$ 5,720	$ 0	$ 0
Performance Goal - Percentile of Peer Group Performance				3630.00%
Weighted-average recognition period	2 years
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%
The percentage paid in cash for the accrued equity portion of the performance share plan upon change in control				100.00%
Unrecognized compensation expense				$ 2,900
Outstanding Performance Periods [Abstract]
Performance Shares, Number of Shares Authorized	37	50	46	37	50	46
Performance Share Award, Percentage of Target				58.86%
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	50	46
Performance Shares, Number of Shares Authorized, End of Period	37	50	46
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Granted (usd per share)	$ 68.72
Blended volatility	21.00%	21.00%	23.00%
Historical volatility	50.00%
Weighted-Average Grant-Date Fair Value Of Performance [Abstract]
Granted (usd per share)	$ 68.72
Weighted Average Grant Date Fair Value (usd per share)		$ 61.82	$ 63.52
Performance Plan Payouts [Abstract]
Performance Share Award, Percentage of Target				58.86%
Target shares, value				$ 2,200
Unrecognized compensation expense				$ 3,400
Weighted-average recognition period	1 year 7 months 6 days
Performance Shares, Liability Awards
Outstanding Performance Periods [Abstract]
Performance Shares, Number of Shares Authorized	67	77		67	77
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	77
Performance Shares, Granted in Period	20
Performance Shares, Forfeited in Period	(4)
Performance Shares, Vested in Period	(26)
Performance Shares, Number of Shares Authorized, End of Period	67	77
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at end of period (usd per share)	$ 89.63
Performance Shares, Equity Awards
Outstanding Performance Periods [Abstract]
Performance Shares, Number of Shares Authorized	67	77		67	77
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Performance Shares, Number of Shares Authorized, Beginning of Period	77
Performance Shares, Granted in Period	20
Performance Shares, Forfeited in Period	(4)
Performance Shares, Vested in Period	(26)
Performance Shares, Number of Shares Authorized, End of Period	67	77
Share-based Compensation Arrangement by Share-based Payment Award, Performance Shares, Outstanding [Roll Forward]
Balance at beginning of period (usd per share)	$ 57.66
Forfeited (usd per share)	64.60
Vested (usd per share)	47.76
Balance at end of period (usd per share)	$ 64.32	$ 57.66
Minimum | Performance Shares
Outstanding Performance Periods [Abstract]
Performance Share Award, Percentage of Target				0.00%	0.00%	0.00%
Performance Plan Payouts [Abstract]
Performance Share Award, Percentage of Target				0.00%	0.00%	0.00%
Maximum | Performance Shares
Outstanding Performance Periods [Abstract]
Performance Share Award, Percentage of Target				200.00%	200.00%	200.00%
Performance Plan Payouts [Abstract]
Performance Share Award, Percentage of Target				200.00%	200.00%	200.00%

Equity_ Dividend Reinvestment a

Equity: Dividend Reinvestment and Stock Purchase Plan (Details)	Dec. 31, 2019shares
Class of Stock [Line Items]
Unissued Shares Available	214,967
Dividend Reinvestment Plan
Class of Stock [Line Items]
Percent of recent average market price	100.00%

Equity_ Preferred Stock (Detail

Equity: Preferred Stock (Details)	Dec. 31, 2019shares
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 ($)	Dec. 31, 2019USD ($)MW	Sep. 30, 2019USD ($)	Jun. 30, 2019USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2019USD ($)MW	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Proceeds from Noncontrolling Interests	$ 216,000
Number of Days the Company has to Pay Distributions of Net Income Attributable to Noncontrolling Interests										30 days
Net income attributable to noncontrolling interest		$ (3,693)	$ (3,655)	$ (3,110)	$ (3,554)	$ (3,773)	$ (3,994)	$ (2,823)	$ (3,630)	$ (14,012)	$ (14,220)	$ (14,242)
Current assets		473,184				503,833				473,184	503,833
Property, plant and equipment of variable interest entities, net		5,503,186				4,854,879				5,503,186	4,854,879
Current liabilities		811,294				648,230				811,294	648,230
Power Generation
Net income attributable to noncontrolling interest										(14,000)	(14,000)	$ (14,000)
Property, plant and equipment of variable interest entities, net		380,156				309,402				380,156	309,402
Variable Interest Entity, Primary Beneficiary
Current assets		13,350				13,620				13,350	13,620
Property, plant and equipment of variable interest entities, net		193,046				199,839				193,046	199,839
Current liabilities		$ 6,013				$ 5,174				$ 6,013	$ 5,174
Pueblo Airport Generation | Subsidiary of Common Parent
Electric Generation Capacity, Megawatts | MW		200								200

Regulatory Matters_ Regulatory

Regulatory Matters: Regulatory Matters (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Regulatory assets	$ 271,344	$ 284,235
Regulatory assets, current	(43,282)	(48,776)
Regulatory assets, non-current	228,062	235,459
Regulatory liabilities	536,652	540,794
Regulatory liabilities, current	(33,507)	(29,810)
Regulatory liabilities, non-current	503,145	510,984
Deferred energy and gas costs
Regulatory liabilities	17,278	6,991
Employee benefit plan costs and related deferred taxes
Regulatory liabilities	43,349	42,533
Cost of removal
Regulatory liabilities	166,727	150,123
Excess deferred income taxes
Regulatory liabilities	285,438	310,562
TCJA revenue reserve
Regulatory liabilities	3,418	18,032
Other regulatory liabilities
Regulatory liabilities	20,442	12,553
Deferred energy and gas costs
Regulatory assets	34,088	29,661
Deferred gas cost adjustments
Regulatory assets	1,540	3,362
Gas price derivatives
Regulatory assets	3,328	6,201
Deferred taxes on AFUDC
Regulatory assets	7,790	7,841
Employee benefit plan costs and related deferred taxes
Regulatory assets	115,900	110,524
Environmental
Regulatory assets	1,454	959
Loss on reacquired debt
Regulatory assets	24,777	21,001
Renewable energy standard adjustment
Regulatory assets	1,622	1,722
Deferred taxes on flow through accounting
Regulatory assets	41,220	31,044
Decommissioning costs
Regulatory assets	10,670	11,700
Gas supply contract termination
Regulatory assets	8,485	14,310
Other regulatory assets
Regulatory assets	$ 20,470	$ 45,910

Regulatory Matters_ Gas Price D

Regulatory Matters: Gas Price Derivatives (Details)	12 Months Ended
	Dec. 31, 2019
Maximum
Derivative, Term of Contract	2 years

Regulatory Matters_ Gas Supply

Regulatory Matters: Gas Supply Contract Termination (Details)	12 Months Ended
	Dec. 31, 2019$ / Btu
Minimum
Oil and Gas Delivery Commitments and Contracts, Fixed Price	6
Maximum
Oil and Gas Delivery Commitments and Contracts, Fixed Price	8
Gas supply contract termination
Regulatory Asset, Amortization Period	5 years

Regulatory Matters_ Electric Ut

Regulatory Matters: Electric Utilities Regulatory Activity (Details) $ in Thousands	Aug. 02, 2019MW	Jan. 01, 2019USD ($)	Oct. 31, 2018USD ($)	Dec. 31, 2019USD ($)utilityMW	Dec. 31, 2018USD ($)	Nov. 01, 2019MW
Public Utilities, General Disclosures [Line Items]
Unrecorded Unconditional Purchase Obligation, Term				60 days
Regulatory liabilities				$ 536,652	$ 540,794
Other regulatory liabilities
Public Utilities, General Disclosures [Line Items]
Regulatory liabilities				20,442	12,553
South Dakota Electric | Federal Energy Regulatory Commission (FERC) Common Use System (CUS)
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement, as Required by the FERC Joint-Access Transmission Tariff		$ 1,900
Capital Addition Requirements by the FERC Joint-Access Transmission Tariff		$ 31,000		$ 31,000	$ 31,000
South Dakota Electric | South Dakota Public Utilities Commission (SDPUC)
Public Utilities, General Disclosures [Line Items]
Public Utilities, Moratorium Period				6 years
Public Utilities, Increase in Moratorium Period				3 years
Public Utilities, Previous Approved Moratorium Period				6 years
South Dakota Electric | South Dakota Public Utilities Commission (SDPUC) | Application for Deferred Accounting Treatment Withdrawn
Public Utilities, General Disclosures [Line Items]
Public Utilities, Development Costs Expensed				$ 5,400
South Dakota Electric | South Dakota Public Utilities Commission (SDPUC) | Amount of Increase sought in Generating Capacity Under Environmental Improvement Adjustment Tariff | Corriedale Wind Project
Public Utilities, General Disclosures [Line Items]
Utility Plant, Megawatt Capacity | MW						12.5
South Dakota Electric and Wyoming Electric | Wyoming Public Service Commission (WPSC) | Approval Received | Corriedale Wind Project
Public Utilities, General Disclosures [Line Items]
Public Utilities Increase (Decrease) in Utility Plant, Megawatt Capacity | MW				52.5
South Dakota Electric and Wyoming Electric | Wyoming Public Service Commission (WPSC) and South Dakota Public Utilities Commission (SDPUC) | Corriedale Wind Project
Public Utilities, General Disclosures [Line Items]
Public Utilities Number of Electric Utilities Jointly Owning Wind Project | utility				2
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment				$ 79,000
Black Hills Energy, Wyoming Electric | Wyoming Public Service Commission (WPSC)
Public Utilities, General Disclosures [Line Items]
Public Utilities, Aggregate Amount of Customer Credits Through The Power Cost Adjustment Mechanism			$ 7,000
Public Utilities, Power Purchase Agreement Annual Cost Escalation Percentage Through 2022			3.00%
Black Hills Wyoming and Wyoming Electric | Federal Energy Regulatory Commission (FERC)
Public Utilities, General Disclosures [Line Items]
Pending FERC Approval - Number of Megawatts Capacity to be Purchased and Delivered Through Intercompany Agreement | MW	60
Unrecorded Unconditional Purchase Obligation, Term	20 years

Regulatory Matters_ Gas Utiliti

Regulatory Matters: Gas Utilities Regulatory Activity (Details) $ in Millions	Dec. 11, 2019USD ($)utility	Feb. 01, 2019USD ($)utility	Oct. 05, 2018USD ($)	Sep. 05, 2018USD ($)	Feb. 01, 2018USD ($)	Dec. 31, 2019	Oct. 29, 2019utility
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Colorado Gas | Rate Review Filed with the Regulatory Agency
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Gas Distribution Territories Consolidating | utility		2
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 2.5
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Gas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 13
Public Utilities, Approved Return on Equity, Percentage	9.40%
Public Utilities, Approved Equity Capital Structure, Percentage	50.23%
Public Utilities, Approved Debt Capital Structure, Percentage	49.77%
Public Utilities, Number of Gas Distribution Territories Consolidating | utility	4
Arkansas Public Service Commission (APSC) | Black Hills Energy, Arkansas Gas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount			$ 12
Public Utilities, Amount Of Existing Revenue Collected Through Rider Mechanisms Included In New Base Rates			$ 11
Public Utilities, Approved Return on Equity, Percentage			9.61%
Public Utilities, Approved Equity Capital Structure, Percentage			49.10%
Public Utilities, Approved Debt Capital Structure, Percentage			50.90%
Nebraska Public Service Commission (NPSC) | Black Hills Gas Distribution - Nebraska
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount				$ 6
Nebraska Public Service Commission (NPSC) | Black Hills Energy, Nebraska Gas | Received Approval to Merge
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Gas Distribution Territories Consolidating | utility							2
Nebraska Public Service Commission (NPSC) | Black Hills Energy, Nebraska Gas | Approval of Recovery Received
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 0.3
Public Utilities, Property, Plant and Equipment, Cost Of Plant Investment					$ 6.8
Maximum
Public Utilities, General Disclosures [Line Items]
Derivative, Term of Contract						2 years

Operating Leases (Details)

Operating Leases (Details)	12 Months Ended
	Dec. 31, 2019
Minimum
Lessee, Lease, Description [Line Items]
Lessee - Lease Term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee - Lease Term	36 years

Lessee - Lease Costs (Details)

Lessee - Lease Costs (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Total lease cost	$ 1,575
Operations and maintenance
Operating lease cost	1,456
Depreciation, depletion and amortization
Amortization of right-of-use asset	100
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)
Interest on lease liabilities	$ 19

Lessee - Supplemental Balance S

Lessee - Supplemental Balance Sheet Information (Details) $ in Thousands	Dec. 31, 2019USD ($)
Total lease assets	$ 5,094
Operating and finance lease liabilities	5,473
Other assets, non-current
Operating lease assets	4,629
Finance lease assets	465
Accrued liabilities
Operating lease liability, current	1,179
Finance lease, liability, current	109
Other deferred credits and other liabilities
Operating lease, liability, noncurrent	3,821
Finance lease, liability, noncurrent	$ 364

Lessee - Supplemental Cash Flow

Lessee - Supplemental Cash Flow Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating cash flows from operating leases	$ 1,263
Operating cash flows from finance lease	19
Financing cash flows from finance lease	93
Operating leases	2,801
Finance lease	$ 67

Lessee - Weighted Average Infor

Lessee - Weighted Average Information (Details)	Dec. 31, 2019
Leases [Abstract]
Lease Term - Operating leases	8 years
Lease Term - Finance lease	4 years
Discount Rate - Operating leases	4.27%
Discount Rate - Finance lease	4.19%

Lessee - Future Minimum Payment

Lessee - Future Minimum Payments (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Operating Leases
2020	$ 1,018
2021	865
2022	743
2023	718
2024	714
Thereafter	2,009
Total lease payments	6,067
Less imputed interest	1,067
Operating Lease, Liability	5,000
Finance Lease
2020	126
2021	126
2022	126
2023	126
2024	10
Thereafter	0
Total lease payments	514
Less imputed interest	41
Present value of lease liabilities	473
Operating and Finance Lease Total
2020	1,144
2021	991
2022	869
2023	844
2024	724
Thereafter	2,009
Total lease payments	6,581
Less imputed interest	1,108
Present value of lease liabilities	$ 5,473
Prior Year End Operating Lease Future Minimum Payments
2019		$ 1,052
2020		464
2021		344
2022		224
2023		216
Thereafter		1,776
Total lease payments		$ 4,076

Lessor (Details)

Lessor (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Lessor, Lease, Description [Line Items]
Operating lease income	$ 2,306
Minimum
Lessor, Lease, Description [Line Items]
Lessor - lease term	1 year
Maximum
Lessor, Lease, Description [Line Items]
Lessor - lease term	35 years

Lessor - Future Minimum Payment

Lessor - Future Minimum Payments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 2,227
2021	1,857
2022	1,793
2023	1,799
2024	1,743
Thereafter	53,739
Total lease receivables	$ 63,158

Income Taxes_ Tax Cut and Jobs

Income Taxes: Tax Cut and Jobs Act (Details) - USD ($) $ in Thousands	12 Months Ended			24 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Regulatory Liability			$ 309,000
Increase (Decrease) in Regulatory Liabilities	$ (15,158)	$ 18,533	(4,536)
Deferred Income Tax Charge
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Regulatory Liability			$ 301,000
Increase (Decrease) in Regulatory Liabilities	$ 11,000
Revenue Subject to Refund
Revenue Refunded To Customers As A Result Of The TCJA Tax Benefits				$ 6,500

Income Taxes_ Tax Benefit Relat

Income Taxes: Tax Benefit Related to Legal Restructuring (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Deferred Income Tax Expense (Benefit)			$ (38,020)	$ 24,239	$ (80,992)
Other Restructuring
Deferred Tax Assets, Goodwill and Intangible Assets	$ 73,000			73,000
Deferred Income Tax Expense (Benefit)	$ (23,000)	$ (49,000)		$ 73,000

Income Taxes_ Current and Defer

Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal	$ (8,578)	$ 325	$ (6,193)
State	138	247	(1,432)
Total Current	(8,440)	572	(7,625)
Deferred:
Federal	34,551	(25,022)	76,522
State	3,469	783	4,470
Total Deferred	38,020	(24,239)	80,992
Total Current and Deferred	$ 29,580	(23,667)	73,367
Discontinued Operation, Tax Effect of Discontinued Operation		$ (2,618)	$ (8,413)

Income Taxes_ Deferred Income T

Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred Tax Assets, Net [Abstract]
Regulatory liabilities	$ 89,754	$ 92,966
State tax credits	23,261	20,466
Federal net operating loss	120,624	139,371
State net operating loss	13,537	16,647
Partnership	14,030	16,032
Credit Carryovers	27,139	23,124
Other deferred tax assets	33,395	39,349
Less: Valuation allowance	(12,063)	(11,809)
Total deferred tax assets	309,677	336,146
Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(533,292)	(529,338)
Regulatory assets	(23,586)	(32,324)
Goodwill	(15,875)	(602)
State deferred tax liability	(72,911)	(64,095)
Other deferred tax liabilities	(24,732)	(21,118)
Total deferred tax liabilities	(670,396)	(647,477)
Net deferred tax liability	$ (360,719)	$ (311,331)

Income Taxes_ Effective Tax Rat

Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Federal Statutory Rate	21.00%	21.00%	35.00%
State income tax (net of federal tax effect)	1.50%	2.30%	0.90%
Non-controlling interest	(1.20%)	(1.30%)	(1.80%)
Tax credits	(3.90%)	(2.00%)	(1.70%)
Flow-through adjustments	(2.40%)	(1.60%)	(1.10%)
Jurisdictional simplification project	0.00%	(28.50%)	0.00%
Other tax differences	(1.60%)	(0.10%)	(2.60%)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Percent	0.00%	1.60%	(2.70%)
Effective Income Tax Reconciliation, Amortization Of Excess Deferred Income Tax Expense	(1.20%)	(0.70%)	0.00%
Effective Income Tax Rate, Continuing Operations	12.20%	(9.30%)	26.00%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		$ 4	$ 7.6

Income Taxes_ Net Operating Los

Income Taxes: Net Operating Loss Carryforwards (Details) $ in Thousands	Dec. 31, 2019USD ($)
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	$ 575,457
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	224,716
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Valuation Allowance	$ 500

Income Taxes_ Reconciliation of

Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 3,583	$ 3,263	$ 3,592
Additions for prior year tax positions	446	251	358
Reductions for prior year tax positions	(862)	(417)	(5,713)
Additions for current year tax positions	998	486	5,026
Settlements	0	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	4,165	$ 3,583	$ 3,263
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 300

Income Taxes_ Interest, Penalti

Income Taxes: Interest, Penalties and Audits (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits, Interest Expense	$ 0	$ 0	$ 0
Unrecognized Tax Benefits, Interest Accrued	$ 0	$ 0

Income Taxes_ Carryforwards, St

Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - State and Local Jurisdiction $ in Thousands	Dec. 31, 2019USD ($)
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	$ 9,000
Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	23,060
Research Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	$ 201

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense	$ 145,847	$ 143,720	$ 140,533
Fuel, purchased power and cost of natural gas sold	570,829	625,610	563,288
Operations and maintenance	495,994	481,706	454,605
Income before income taxes	242,902	255,882	281,742
Income Tax Expense (Benefit)	(29,580)	23,667	(73,367)
Net income (loss)	213,322	272,662	$ 191,276
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income (loss)	(2,944)	(4,117)
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	(2,434)	(2,981)
Income Tax Expense (Benefit)	611	630
Net income (loss)	(1,823)	(2,351)
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Cost | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance	77	178
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	(745)	(2,487)
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	(668)	(2,309)
Income Tax Expense (Benefit)	(453)	543
Net income (loss)	(1,121)	(1,766)
Interest Rate Swap | Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense	(2,851)	(2,851)
Commodity Contract | Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Fuel, purchased power and cost of natural gas sold	$ 417	$ (130)

Other Comprehensive Income_ Acc

Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (26,916)	$ (41,202)
Reclassification from Legal Entity Restructuring		6,519
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(30,655)	(26,916)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(9,937)	(21,103)
before reclassifications	(6,261)	2,155
Reclassification from Legal Entity Restructuring		6,519
Reclassification of certain tax effects from AOCI		726
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(15,077)	(9,937)
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from AOCI	1,121	1,766
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
before reclassifications	(6,683)	2,910
Reclassification from Legal Entity Restructuring		6,519
Reclassification of certain tax effects from AOCI		740
Accumulated Other Comprehensive Income (Loss) | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from AOCI	2,944	4,117
Interest Rate Swap | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(17,307)	(19,581)
before reclassifications	0	0
Reclassification from Legal Entity Restructuring		0
Reclassification of certain tax effects from AOCI		22
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(15,122)	(17,307)
Interest Rate Swap | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from AOCI	2,185	2,252
Commodity Contract | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	328	(518)
before reclassifications	(422)	755
Reclassification from Legal Entity Restructuring		0
Reclassification of certain tax effects from AOCI		(8)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(456)	328
Commodity Contract | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from AOCI	$ (362)	$ 99

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Non-cash investing activities and financing from continuing operations -
Accrued property, plant and equipment purchases at December 31	$ 91,491	$ 69,017	$ 28,191
Increase (decrease) in capitalized assets associated with asset retirement obligations	5,044	2,625	3,198
Cash (paid) refunded during the period for continuing operations-
Interest (net of amounts capitalized)	(131,774)	(137,965)	(132,428)
Income taxes (paid) refunded	$ 4,682	$ (14,730)	$ 1,775

Employee Benefit Plans_ Narrati

Employee Benefit Plans: Narrative (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
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%
Hedge Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	5.00%	5.00%
Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Employers Matching Contribution, Annual Vesting Percentage	100.00%
Pension Plans, Defined Benefit | Minimum | Return Seeking Assets
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	29.00%
Pension Plans, Defined Benefit | Minimum | Hedge Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	63.00%
Pension Plans, Defined Benefit | Maximum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	71.00%
Pension Plans, Defined Benefit | Maximum | Return Seeking Assets
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	37.00%

Employee Benefit Plans_ Plan As

Employee Benefit Plans: Plan Assets Allocation (Details)	Dec. 31, 2019	Dec. 31, 2018
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	20.00%	17.00%
Real Estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	3.00%	4.00%
Fixed Income Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	71.00%	71.00%
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%	3.00%
Hedge Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Target Allocation Percentage of Assets	5.00%	5.00%

Employee Benefit Plans_ Plan Co

Employee Benefit Plans: Plan Contributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
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	12,700	$ 12,700
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	7,033	5,298
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	2,344	2,073
Defined Contribution Plan, Company Retirement
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	9,714	8,766
Defined Contribution Plan, 401K
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Employer Contributions	$ 14,558	$ 13,559

Employee Benefit Plans_ Employe

Employee Benefit Plans: Employee Benefit Plans Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Minimum | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment Redemption, Notice Period	10 days
Maximum | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment Redemption, Notice Period	30 days
Hedge Funds | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage Of Monthly Redemption	20.00%
Hedge Funds | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage Of Quarterly Redemption	100.00%
Pension Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 434,284	$ 390,796	$ 416,343
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	434,284	390,796
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	400,495	358,462
Alternative Investment, Fair Value Disclosure	33,789	32,334
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	60	1,867
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	60	1,867
Alternative Investment, Fair Value Disclosure	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	7,054	9,923
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	7,054	9,923
Alternative Investment, Fair Value Disclosure	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	87,106	67,457
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	87,106	67,457
Alternative Investment, Fair Value Disclosure	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	306,275	279,148
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	306,275	279,148
Alternative Investment, Fair Value Disclosure	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	14,239	13,618
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	0	67
Alternative Investment, Fair Value Disclosure	14,239	13,551
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	19,550	18,783
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	0	0
Alternative Investment, Fair Value Disclosure	19,550	18,783
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	400,495	358,462
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	60	1,867
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	7,054	9,923
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	87,106	67,457
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	306,275	279,148
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	67
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Fixed Income Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Common Collective Trust - Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Common Collective Trust - Equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Common Collective Trust - Fixed Income
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Common Collective Trust - Real Estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Hedge Funds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans, Defined Benefit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8,305	8,162	$ 8,621
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8,305	8,162
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	8,305	8,162
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8,305	4,873
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	8,305	4,873
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		1,005
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments		1,005
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		2,284
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments		2,284
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8,305	5,878
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	8,305	4,873
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		1,005
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1 | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	2,284
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2 | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		2,284
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Cash and Cash Equivalents
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 0	0
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Equity Securities
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		0
Other Postretirement Benefit Plans, Defined Benefit | Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3 | Intermediate - Term Bond
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Defined Benefit Plan, Plan Assets, Amount		$ 0

Employee Benefit Plans_ Changes

Employee Benefit Plans: Changes in Benefit Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	$ 445,381	$ 474,725
Service cost	5,383	6,834	$ 7,034
Interest cost	17,374	15,470	15,520
Actuarial (gain) loss	56,384	(31,340)
Benefits paid	(39,146)	(20,308)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	485,376	445,381	474,725
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	43,010	45,112
Service cost	4,995	1,764
Interest cost	1,295	1,170
Actuarial (gain) loss	7,132	(2,963)
Benefits paid	(2,344)	(2,073)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	54,088	43,010	45,112
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	60,817	69,339
Service cost	1,815	2,291	2,300
Interest cost	2,247	2,085	2,141
Actuarial (gain) loss	5,976	(9,045)
Benefits paid	(7,033)	(5,298)
Plan participants’ contributions	1,455	1,445
Projected benefit obligation at end of year	$ 65,277	$ 60,817	$ 69,339

Employee Benefit Plans_ Chang_2

Employee Benefit Plans: Changes in Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Pension Plans, Defined Benefit
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Beginning fair value of plan assets	$ 390,796	$ 416,343
Investment income (loss)	69,934	(17,939)
Employer contributions	12,700	12,700
Retiree contributions	0	0
Benefits paid	(39,146)	(20,308)
Ending fair value of plan assets	434,284	390,796
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
Investment income (loss)	0	0
Employer contributions	2,344	2,073
Retiree contributions	0	0
Benefits paid	(2,344)	(2,073)
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	8,162	8,621
Investment income (loss)	260	(149)
Employer contributions	5,461	3,543
Retiree contributions	1,455	1,445
Benefits paid	(7,033)	(5,298)
Ending fair value of plan assets	$ 8,305	$ 8,162

Employee Benefit Plans_ Amounts

Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	$ 271,344	$ 284,235
Non-current liabilities	154,472	145,147
Regulatory liabilities	536,652	540,794
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Regulatory assets	88,471	82,919
Current liabilities	0	0
Non-current assets	0	0
Non-current liabilities	51,093	54,585
Regulatory liabilities	3,524	4,620
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	1,420	1,463
Non-current assets	0	0
Non-current liabilities	51,243	41,547
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	11,670	6,655
Current liabilities	4,802	3,885
Non-current assets	0	249
Non-current liabilities	52,136	49,015
Regulatory liabilities	$ 4,088	$ 5,207

Employee Benefit Plans_ Accumul

Employee Benefit Plans: Accumulated Benefit Obligation (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$ 470,615	$ 428,851
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	49,241	40,530
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Accumulated Benefit Obligation	$ 65,277	$ 60,817

Employee Benefit Plans_ Compone

Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Pension Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 5,383	$ 6,834	$ 7,034
Interest cost	17,374	15,470	15,520
Expected return on assets	(24,401)	(24,741)	(24,517)
Net amortization of prior service cost	26	58	58
Recognized net actuarial loss (gain)	3,763	8,632	4,007
Net periodic benefit expense	2,145	6,253	2,102
Supplemental Non-qualified Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	4,995	1,764	1,546
Interest cost	1,295	1,170	1,276
Expected return on assets	0	0	0
Net amortization of prior service cost	2	2	2
Recognized net actuarial loss (gain)	535	1,000	1,001
Net periodic benefit expense	6,827	3,936	3,825
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plan Disclosure [Line Items]
Service cost	1,815	2,291	2,300
Interest cost	2,247	2,085	2,141
Expected return on assets	(230)	(315)	(315)
Net amortization of prior service cost	(398)	(398)	(411)
Recognized net actuarial loss (gain)	0	216	499
Net periodic benefit expense	$ 3,434	$ 3,879	$ 4,214

Employee Benefit Plans_ Accum_2

Employee Benefit Plans: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Pension Plans, Defined Benefit
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net (gain) loss	$ 5,322	$ 11,967
Prior service cost (gain)	0	1
Reclassification of certain tax effects from AOCI	0	(594)
Reclassification to regulatory asset	0	(5,600)
Total AOCI	5,322	5,774
Supplemental Employee Retirement Plans, Defined Benefit
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net (gain) loss	9,893	4,668
Prior service cost (gain)	2	3
Reclassification of certain tax effects from AOCI	0	(87)
Reclassification to regulatory asset	0	0
Total AOCI	9,895	4,584
Other Postretirement Benefit Plans, Defined Benefit
Accumulated Other Comprehensive (Income) Loss, Defined Benefit Plan, after Tax [Abstract]
Net (gain) loss	90	860
Prior service cost (gain)	(230)	(317)
Reclassification of certain tax effects from AOCI	0	(45)
Reclassification to regulatory asset	0	(919)
Total AOCI	$ (140)	$ (421)

Employee Benefit Plans_ Defined

Employee Benefit Plans: Defined Benefit Plans Assumptions (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Healthcare trend rate pre-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Year Ultimate Trend Reached	2027	2027
Healthcare trend rate post-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Year Ultimate Trend Reached	2028	2026
Black Hills Corporation - All Plans | Healthcare trend rate pre-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	6.40%	6.70%
Black Hills Corporation - All Plans | Healthcare trend rate post-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	4.92%	4.94%
Black Hills Service Company | Healthcare trend rate pre-65
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Ultimate trend rate	4.50%	4.50%
Black Hills Service Company | Healthcare trend rate post-65
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	3.27%	4.40%	3.71%
Rate of Increase in Compensation Levels	3.49%	3.52%	3.43%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	6.00%	6.25%	6.75%
Rate of Compensation Increase	3.52%	3.43%	3.47%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year	5.25%
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	4.40%	3.71%	4.27%
Pension Plans, Defined Benefit | Black Hills Corporation Pension Plan
Defined Benefit Plan, Assumed Health Care Cost Trend Rates [Abstract]
Trend for next year	3.27%
Supplemental Employee Retirement Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.14%	4.34%	3.56%
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	4.34%	3.67%	4.02%
Other Postretirement Benefit Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount Rate, Benefit Obligation	3.15%	4.28%	3.60%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected Long-term Return on Assets	3.00%	3.93%	3.88%
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	4.28%	3.60%	4.05%

Employee Benefit Plans_ Project

Employee Benefit Plans: Projected Benefit Plan Payments (Details) $ in Thousands	Dec. 31, 2019USD ($)
Pension Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	$ 24,586
2021	25,774
2022	26,728
2023	27,795
2024	28,547
2025-2029	145,426
Supplemental Employee Retirement Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	1,420
2021	1,786
2022	2,167
2023	2,223
2024	2,412
2025-2029	14,689
Other Postretirement Benefit Plans, Defined Benefit
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2020	5,919
2021	5,974
2022	5,790
2023	5,521
2024	5,329
2025-2029	$ 23,030

Commitments And Contingencies_

Commitments And Contingencies: Power Purchase and Transmission Services Agreements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)MW	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 11, 2018	Sep. 03, 2014MW
Long-term Purchase Commitment [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				50.00%
Busch Ranch I Wind Farm
Long-term Purchase Commitment [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired				50.00%
Black Hills Electric Generation and Colorado Electric | Busch Ranch I Wind Farm
Long-term Purchase Commitment [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	100.00%
Platte River Power Authority Wind Power Agreement
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	12
Cost of Purchased Power | $	$ 688	$ 223	$ 0
Platte River Power Authority Wind Power Agreement | Colorado Electric
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	60
Platte River Power Authority - Unit Contingent Energy
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $	$ 1,802	0	0
Platte River Power Authority - Unit Contingent Energy | Colorado Electric
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	25
PacifiCorp Purchase Power Agreement
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	50
Cost of Purchased Power | $	$ 7,477	13,681	13,218
PacifiCorp Transmission
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	50
Cost of Purchased Power | $	$ 1,741	1,742	1,671
Happy Jack Wind Purchase Power Agreement
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $	$ 3,936	3,884	3,846
Happy Jack Wind Purchase Power Agreement | Wyoming Electric
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	30
Happy Jack Wind Purchase Power Agreement | Wyoming Electric | 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%
Silver Sage Wind Power Purchase Agreement
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $	$ 5,366	5,376	4,934
Silver Sage Wind Power Purchase Agreement | Wyoming Electric
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	30
Silver Sage Wind Power Purchase Agreement | Wyoming Electric | Subsidiary of Common Parent
Long-term Purchase Commitment [Line Items]
Number of Megawatts Sold	20
Busch Ranch I Wind Farm
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	14.5
Cost of Purchased Power | $	$ 0	$ 0	$ 1,966
Sharing Arrangement with the City of Gillette, Wyoming
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment, Period	20 years
Sharing Arrangement with the City of Gillette, Wyoming | Black Hills Wyoming
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Sold					40

Commitments And Contingencies_2

Commitments And Contingencies: Power Purchase Agreement - Related Party (Details) - MW	Dec. 31, 2019	Dec. 11, 2018
Long-term Purchase Commitment [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		50.00%
Pueblo Airport Generation | Subsidiary of Common Parent
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	200
Busch Ranch I Wind Farm
Long-term Purchase Commitment [Line Items]
Business Acquisition, Percentage of Voting Interests Acquired		50.00%
Busch Ranch I Wind Farm
Long-term Purchase Commitment [Line Items]
Megawatts of Capacity Purchased	14.5

Commitments And Contingencies_3

Commitments And Contingencies: Purchase Commitment (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)MMBTU	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Long-term Purchase Commitment [Line Items]
Term of Evergreen Contracts	60 days
Natural Gas, Distribution
Long-term Purchase Commitment [Line Items]
Natural Gas Purchases | $	$ 6.7	$ 27	$ 65
NNG-Ventura
Long-term Purchase Commitment [Line Items]
2020	3,660,000
2021	3,650,000
2022	1,810,000
2023	0
2024	0
Thereafter	0
NWPL-Wyoming
Long-term Purchase Commitment [Line Items]
2020	1,520,000
2021	1,510,000
2022	1,510,000
2023	1,510,000
2024	910,000
Thereafter	0

Commitments And Contingencies_4

Commitments And Contingencies: Unconditional Purchase Obligations (Details) $ in Thousands	Dec. 31, 2019USD ($)
Power purchase and transmission services agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2020	$ 25,476
2021	11,678
2022	11,678
2023	11,678
2024	2,738
Thereafter	0
Natural gas transportation and storage agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2020	156,297
2021	148,149
2022	122,340
2023	93,905
2024	51,360
Thereafter	$ 126,147

Commitments And Contingencies_5

Commitments And Contingencies: Future Purchase Agreement - Related Party (Details) - Black Hills Wyoming and Wyoming Electric - MW	Aug. 02, 2019	Dec. 31, 2019
Unrecorded Unconditional Purchase Obligation [Line Items]
Megawatts Sold Under Long-Term Contract		60
Federal Energy Regulatory Commission (FERC)
Unrecorded Unconditional Purchase Obligation [Line Items]
Pending FERC Approval - Number of Megawatts Capacity to be Purchased and Delivered Through Intercompany Agreement	60
Pending FERC Approval, Number of Additional Years of Purchase Power Agreement	20 years

Commitments And Contingencies_6

Commitments And Contingencies: Power Sales Agreements (Details)	Dec. 31, 2019MW
M D U, Montana Dakota Utilities | Contingent Capacity Amounts on Wygen III
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, for up to 20 Megawatts
Long-term Purchase Commitment [Line Items]
2019-2020	15
2020-2022	15
2022-2023	15
2023-2028	10
Megawatts Sold Under Long-Term Contract	20
Purchase Power Contract, MEAN, for up to 20 Megawatts | Contingent Capacity Amounts on Wygen III
Long-term Purchase Commitment [Line Items]
2019-2020	10
2020-2022	7
2022-2023	8
2023-2028	5
Purchase Power Contract, MEAN, for up to 20 Megawatts | Contingent Capacity Amounts on Neil Simpson II
Long-term Purchase Commitment [Line Items]
2019-2020	5
2020-2022	8
2022-2023	7
2023-2028	5
Macquarie Energy, LLC Supply Agreement
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract	50

Commitments And Contingencies_7

Commitments And Contingencies: Reimbursement Agreement (Details) - Wyoming Electric - Electric Utilities - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term debt	$ 202,000	$ 202,000
Industrial Development Revenue Bonds Due 2027
Debt Instrument [Line Items]
Long-term debt	10,000	10,000
Industrial Development Revenue Bonds Due 2021
Debt Instrument [Line Items]
Long-term debt	$ 7,000	$ 7,000

Commitments And Contingencies_8

Commitments And Contingencies: Reclamation Liability (Details) $ in Millions	Dec. 31, 2019USD ($)
Electric Utilities
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies - Pueblo Airport Generation Site	$ 4.1

Commitments And Contingencies_9

Commitments And Contingencies: Manufactured Gas Processing (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Loss Contingencies [Line Items]
Regulatory assets	$ 271,344	$ 284,235
Environmental
Loss Contingencies [Line Items]
Regulatory assets	1,454	$ 959
Manufactured Gas Plant | Environmental
Loss Contingencies [Line Items]
Regulatory assets	1,500
Manufactured Gas Plant | Gas Utilities
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1,100
Accrual for Environmental Loss Contingencies, Gross	2,600
Manufactured Gas Plant | Gas Utilities | Minimum
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss	2,600
Manufactured Gas Plant | Gas Utilities | Maximum
Loss Contingencies [Line Items]
Loss Contingency, Range of Possible Loss	$ 10,000

Guarantees (Details)

Guarantees (Details) $ in Thousands	Dec. 31, 2019USD ($)
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 102,358
Surety Bond
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	55,527
Performance Guarantee
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 46,831

Discontinued Operations (Detail

Discontinued Operations (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Revenue										$ 5,897	$ 25,382
Operations and maintenance										11,014	22,872
Loss on sale of assets										3,259	0
Depreciation, depletion and amortization										1,300	7,521
Impairment of long-lived assets										0	20,385
Total operating expenses										15,573	50,778
Operating (loss)										(9,676)	(25,396)
Interest income (expense), net										(19)	181
Other income (expense), net										190	(297)
Income tax benefit										2,618	8,413
Net (loss) from discontinued operations	$ 0	$ 0	$ 0	$ 0	$ (1,260)	$ (857)	$ (2,427)	$ (2,343)	$ 0	$ (6,887)	(17,099)
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)											$ 20,000

Quarterly Historical Data (Un_3

Quarterly Historical Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Selected Quarterly Financial Information [Line Items]
Revenue -	$ 477,654	$ 325,548	$ 333,888	$ 597,810	$ 501,196	$ 321,979	$ 355,704	$ 575,389	$ 1,734,900	$ 1,754,268	$ 1,680,266
Operating income	121,359	70,551	54,001	160,131	114,127	65,085	69,551	148,274	406,042	397,037	416,736
Income from continuing operations	72,872	15,395	17,693	107,362	91,604	21,801	27,167	138,977	213,322	279,549	208,375
Net (loss) from discontinued operations	0	0	0	0	(1,260)	(857)	(2,427)	(2,343)	0	(6,887)	(17,099)
Net income attributable to noncontrolling interest	(3,693)	(3,655)	(3,110)	(3,554)	(3,773)	(3,994)	(2,823)	(3,630)	(14,012)	(14,220)	(14,242)
Net income available for common stock	69,179	11,740	14,583	103,808	86,571	16,950	21,917	133,004	199,310	258,442	177,034
Amounts attributable to common shareholders:
Net income from continuing operations	69,179	11,740	14,583	103,808	87,831	17,807	24,344	135,347	199,310	265,329	194,133
Net (loss) from discontinued operations	0	0	0	0	(1,260)	(857)	(2,427)	(2,343)	0	(6,887)	(17,099)
Net income available for common stock	$ 69,179	$ 11,740	$ 14,583	$ 103,808	$ 86,571	$ 16,950	$ 21,917	$ 133,004	$ 199,310	$ 258,442	$ 177,034
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations, Basic (usd per share)	$ 1.13	$ 0.19	$ 0.24	$ 1.73	$ 1.52	$ 0.33	$ 0.46	$ 2.54	$ 3.29	$ 4.88	$ 3.65
(Loss) from discontinued operations per share, Basic (usd per share)	0	0	0	0	(0.02)	(0.02)	(0.05)	(0.05)	0	(0.13)	(0.32)
Total earnings (loss) per share of common stock, Basic (usd per share)	1.13	0.19	0.24	1.73	1.50	0.32	0.41	2.49	3.29	4.75	3.33
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations, Diluted (usd per share)	1.13	0.19	0.24	1.73	1.51	0.32	0.45	2.50	3.28	4.78	3.52
(Loss) from discontinued operations, Diluted (usd per share)	0	0	0	0	(0.02)	(0.02)	(0.05)	(0.04)	0	(0.12)	(0.31)
Total earnings (loss) per share of common stock, Diluted (usd per share)	$ 1.13	$ 0.19	$ 0.24	$ 1.73	$ 1.49	$ 0.31	$ 0.40	$ 2.46	$ 3.28	$ 4.66	$ 3.21
Other Asset Impairment Charges, Net of Tax		$ 15,000
Deferred Income Tax Expense (Benefit)									$ 38,020	$ (24,239)	$ 80,992
Other Restructuring
Earnings (loss) per share of common stock, Diluted -
Deferred Income Tax Expense (Benefit)					$ 23,000			$ 49,000		$ (73,000)