Black Hills (BKH) 10-K 26 Feb 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2020	Jan. 31, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2020
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 3,528,768,075
Entity Common Stock, Shares Outstanding		62,794,490
Documents Incorporated by Reference	Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2021 Annual Meeting of Stockholders to be held on April 27, 2021, are incorporated by reference in Part III of this Form 10-K.
Entity Central Index Key	0001130464
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue:
Revenue	$ 1,696,941	$ 1,734,900	$ 1,754,268
Operating expenses:
Fuel, purchased power and cost of natural gas sold	492,404	570,829	625,610
Operations and maintenance	495,404	495,994	481,706
Depreciation, depletion and amortization	224,457	209,120	196,328
Taxes - property and production	56,373	52,915	51,746
Other operating expenses	0	0	1,841
Total operating expenses	1,268,638	1,328,858	1,357,231
Operating income	428,303	406,042	397,037
Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	(144,931)	(139,291)	(141,616)
Interest income	1,461	1,632	1,641
Impairment of investment	(6,859)	(19,741)	0
Other income (expense), net	(2,293)	(5,740)	(1,180)
Total other income (expense)	(152,622)	(163,140)	(141,155)
Income before income taxes	275,681	242,902	255,882
Income tax benefit (expense)	(32,918)	(29,580)	23,667
Income from continuing operations	242,763	213,322	279,549
Net (loss) from discontinued operations	0	0	(6,887)
Net income	242,763	213,322	272,662
Net income attributable to noncontrolling interest	(15,155)	(14,012)	(14,220)
Net income available for common stock	227,608	199,310	258,442
Amounts attributable to common shareholders:
Net income from continuing operations	227,608	199,310	265,329
Net (loss) from discontinued operations	0	0	(6,887)
Net income available for common stock	$ 227,608	$ 199,310	$ 258,442
Earnings (loss) per share of common stock, Basic -
Earnings from continuing operations, Basic (usd per share)	$ 3.65	$ 3.29	$ 4.88
(Loss) from discontinued operations, Basic (usd per share)	0	0	(0.13)
Total earnings per share of common stock, Basic (usd per share)	3.65	3.29	4.75
Earnings (loss) per share of common stock, Diluted -
Earnings from continuing operations, Diluted (usd per share)	3.65	3.28	4.78
(Loss) from discontinued operations, Diluted (usd per share)	0	0	(0.12)
Total earnings per share of common stock, Diluted (usd per share)	$ 3.65	$ 3.28	$ 4.66
Weighted average common shares outstanding:
Basic (in shares)	62,378	60,662	54,420
Diluted (in shares)	62,439	60,798	55,486

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Net income	$ 242,763	$ 213,322	$ 272,662
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $191, $1,886 and $(660), respectively)	(1,062)	(6,253)	2,155
Benefit plan liability adjustments - prior service costs (net of tax of $0, $2 and $0 respectively)	0	(8)	0
Reclassification adjustment of benefit plan liability - net loss (net of tax of $(958), $434 and $(586), respectively)	1,429	1,179	1,901
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $23, $19 and $43, respectively)	(80)	(58)	(135)
Other comprehensive income (loss), net of tax	3,309	(3,739)	7,027
Comprehensive income	246,072	209,583	279,689
Less: comprehensive income attributable to non-controlling interest	(15,155)	(14,012)	(14,220)
Comprehensive income available for common stock	230,917	195,571	265,469
Interest rate swaps
Other comprehensive income (loss), net of tax:
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax	2,564	2,185	2,252
Commodity derivatives
Other comprehensive income (loss), net of tax:
Reclassification of net realized (gains) losses on settled/amortized derivatives, net of tax	505	(362)	99
Net unrealized gains (losses) on commodity derivatives (net of tax of $14, $126 and $(228), respectively)	$ (47)	$ (422)	$ 755

Cosolidated Statements of Compr

Cosolidated Statements of Comprehensive Income (parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
(Tax) benefit on benefit plan liability adjustments - net gain (loss)	$ 191	$ 1,886	$ (660)
(Tax) benefit on benefit plan liability adjustments - prior service costs	0	2	0
(Tax) benefit on reclassification adjustment of benefit plan liability - net loss	(958)	434	(586)
(Tax) benefit on reclassification adjustment of benefit plan liability - prior service cost	23	19	43
Interest Rate Swap
Tax (benefit) on reclassification of net realized (gains) losses on settled/amortized derivatives	(287)	(666)	(599)
Commodity Contract
Tax (benefit) on reclassification of net realized (gains) losses on settled/amortized derivatives	(96)	55	(31)
(Tax) benefit on net unrealized gains (losses) on commodity derivatives	$ 14	$ 126	$ (228)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets:
Cash and cash equivalents	$ 6,356	$ 9,777
Restricted cash and equivalents	4,383	3,881
Accounts receivable, net	265,961	255,805
Materials, supplies and fuel	117,400	117,172
Derivative assets, current	1,848	342
Income tax receivable, net	19,446	16,446
Regulatory assets, current	51,676	43,282
Other current assets	26,221	26,479
Total current assets	493,291	473,184
Property, plant and equipment	7,305,530	6,784,679
Less accumulated depreciation and depletion	(1,285,816)	(1,281,493)
Total property, plant and equipment, net	6,019,714	5,503,186
Other assets:
Goodwill	1,299,454	1,299,454
Intangible assets, net	11,944	13,266
Regulatory assets, non-current	226,582	228,062
Other assets, non-current	37,801	41,305
Total other assets, non-current	1,575,781	1,582,087
TOTAL ASSETS	8,088,786	7,558,457
Current liabilities:
Accounts payable	183,340	193,523
Accrued liabilities	243,612	226,767
Derivative liabilities, current	2,044	2,254
Regulatory liabilities, current	25,061	33,507
Notes payable	234,040	349,500
Current maturities of long-term debt	8,436	5,743
Total current liabilities	696,533	811,294
Long-term debt, net of current maturities	3,528,100	3,140,096
Deferred credits and other liabilities:
Deferred income tax liabilities, net	408,624	360,719
Regulatory liabilities, non-current	507,659	503,145
Benefit plan liabilities	150,556	154,472
Other deferred credits and other liabilities	134,667	124,662
Total deferred credits and other liabilities	1,201,506	1,142,998
Commitments, contingencies and guarantees (Note 3)
Stockholders’ equity -
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 62,827,179 and 61,480,658, respectively	62,827	61,481
Additional paid-in capital	1,657,285	1,552,788
Retained earnings	870,738	778,776
Treasury stock at cost - 32,492 and 3,956, respectively	(2,119)	(267)
Accumulated other comprehensive income (loss)	(27,346)	(30,655)
Total stockholders’ equity	2,561,385	2,362,123
Noncontrolling interest	101,262	101,946
Total equity	2,662,647	2,464,069
TOTAL LIABILITIES AND TOTAL EQUITY	$ 8,088,786	$ 7,558,457
Common stock, par value (usd per share)	$ 1	$ 1
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares, issued	62,827,179	61,480,658
Treasury stock, shares	32,492	3,956

Consolidated Balance Sheets (pa

Consolidated Balance Sheets (parentheticals) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Common stock, par value (usd per share)	$ 1	$ 1
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares, issued	62,827,179	61,480,658
Treasury stock, shares	32,492	3,956

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating activities:
Net income	$ 242,763	$ 213,322	$ 272,662
Loss from discontinued operations, net of tax	0	0	6,887
Income from continuing operations	242,763	213,322	279,549
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	224,457	209,120	196,328
Deferred financing cost amortization	7,883	7,838	7,845
Impairment of investment	6,859	19,741	0
Stock compensation	5,373	12,095	12,390
Deferred income taxes	38,091	38,020	(24,239)
Employee benefit plans	11,997	12,406	14,068
Other adjustments, net	11,669	16,485	5,836
Change in certain operating assets and liabilities:
Materials, supplies and fuel	2,755	2,052	(2,919)
Accounts receivable and other current assets	(10,843)	7,578	(45,966)
Accounts payable and other current liabilities	24,659	(34,906)	5,305
Regulatory assets - current	(5,047)	23,619	33,608
Regulatory liabilities - current	(10,706)	(15,158)	18,533
Contributions to defined benefit pension plans	(12,700)	(12,700)	(12,700)
Other operating activities, net	4,653	6,001	6,689
Net cash provided by operating activities of continuing operations	541,863	505,513	494,327
Net cash provided by (used in) operating activities of discontinued operations	0	0	(5,516)
Net cash provided by operating activities	541,863	505,513	488,811
Investing activities:
Property, plant and equipment additions	(767,404)	(818,376)	(457,524)
Purchase of investment	0	0	(24,429)
Other investing activities	5,740	2,166	(4,281)
Net cash (used in) investing activities of continuing operations	(761,664)	(816,210)	(486,234)
Net cash provided by investing activities of discontinued operations	0	0	20,385
Net cash (used in) investing activities	(761,664)	(816,210)	(465,849)
Financing activities:
Dividends paid on common stock	(135,439)	(124,647)	(106,591)
Common stock issued	99,278	101,358	300,834
Net (payments) borrowings of short-term debt	(115,460)	163,880	(25,680)
Long-term debt - issuance	400,000	1,100,000	700,000
Long-term debt - repayments	(8,597)	(905,743)	(854,743)
Distributions to noncontrolling interests	(15,839)	(17,901)	(19,617)
Other financing activities	(7,061)	(16,737)	(11,260)
Net cash provided by (used in) financing activities	216,882	300,210	(17,057)
Net change in cash, restricted cash and cash equivalents	(2,919)	(10,487)	5,905
Cash and cash equivalents:
Cash, restricted cash and cash equivalents beginning of year	13,658	24,145	18,240
Cash, restricted cash and cash equivalents end of year	10,739	13,658	24,145
Supplemental cash flow information:
Interest (net of amounts capitalized)	(136,549)	(131,774)	(137,965)
Income taxes	2,172	4,682	(14,730)
Accrued property, plant and equipment purchases at December 31	72,215	91,491	69,017
Increase in capitalized assets associated with asset retirement obligations	$ 4,774	$ 5,044	$ 2,625

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Cumulative Effect, Period of Adoption, Adjustment	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Beginning balance (in shares) at Dec. 31, 2017			53,579,986	39,064
Beginning balance 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]
Net income available for common stock	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						740
Reclassification to regulatory asset	6,519						6,519
Dividends on common stock	(106,591)					(106,591)
Share-based compensation (in shares)			92,830	5,189
Share-based compensation	7,190		$ 93	$ (204)	7,301
Issuance of common stock (in shares)			6,371,690
Issuance of common stock	299,000		$ 6,372		292,628
Issuance costs	(15)				(15)
Dividend reinvestment and stock purchase plan (in shares)			4,061
Dividend reinvestment and stock purchase plan	220		$ 4		216
Other stock transactions	82				154	(72)
Distributions to noncontrolling interest	(19,617)							(19,617)
Ending balance (in shares) at Dec. 31, 2018			60,048,567	44,253
Ending balance 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]
Net income available for common stock	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 (in shares)			103,759	40,297
Share-based compensation	7,076		$ 104	$ 2,243	4,729
Issuance of common stock (in shares)			1,328,332
Issuance of common stock	100,000		$ 1,328		98,672
Issuance costs	(1,182)				(1,182)
Other stock transactions	327					327
Distributions to noncontrolling interest	(17,901)							(17,901)
Ending balance (in shares) at Dec. 31, 2019			61,480,658	3,956
Ending balance at Dec. 31, 2019	2,464,069	$ 3,390	$ 61,481	$ (267)	1,552,788	778,776	(30,655)	101,946
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income available for common stock	242,763					227,608		15,155
Other comprehensive income (loss), net of tax	3,309						3,309
Dividends on common stock	(135,439)					(135,439)
Share-based compensation (in shares)			123,578	28,536
Share-based compensation	5,194		$ 123	$ (1,852)	6,923
Issuance of common stock (in shares)			1,222,943
Issuance of common stock	100,000		$ 1,223		98,777
Issuance costs	(1,203)				(1,203)
Distributions to noncontrolling interest	(15,839)							(15,839)
Ending balance (in shares) at Dec. 31, 2020			62,827,179	32,492
Ending balance at Dec. 31, 2020	$ 2,662,647	$ (207)	$ 62,827	$ (2,119)	$ 1,657,285	$ 870,738	$ (27,346)	$ 101,262

Consolidated Statement of Equit

Consolidated Statement of Equity (Parentheticals) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Stockholders' Equity [Abstract]
Dividends on common stock, Per Share	$ 2.17	$ 2.05	$ 1.93
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 2,662,647	$ 2,464,069	$ 2,287,423

Business Description And Signif

Business Description And Significant Accounting Policies:	12 Months Ended
	Dec. 31, 2020
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. Both 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 coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 18 . 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 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. Unless otherwise noted, the amounts presented in the accompanying Notes to Consolidated Financial Statements relate to the Company’s continuing operations. 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. COVID-19 Pandemic In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations. The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the year ended December 31, 2020, there were no material adverse impacts on the Company’s results of operations. 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 18 . 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 generation facility, wind farm or transmission tie. See Note 6 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 14 . 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 Credit Losses Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal primarily to affiliates or regional utilities. We maintain an allowance for credit losses 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 credit losses 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, expected losses, 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): 2020 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net Electric Utilities $ 45,841 $ 32,915 $ (1,269) $ 77,487 Gas Utilities 95,592 93,150 (5,734) 183,008 Power Generation 1,837 — — 1,837 Mining 2,511 — — 2,511 Corporate 1,118 — — 1,118 Total $ 146,899 $ 126,065 $ (7,003) $ 265,961 2019 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses 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 Changes to allowance for credit losses 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 2020 $ 2,444 $ 8,927 (a) $ 4,728 $ (9,096) $ 7,003 2019 $ 3,209 $ 5,795 $ 3,942 $ (10,502) $ 2,444 2018 $ 3,081 $ 6,859 $ 4,092 $ (10,823) $ 3,209 _________________ (a) Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections due to non-payment for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the year ended December 31, 2020 by an incremental $3.3 million. The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 11 . 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): 2020 2019 Materials and supplies $ 85,250 $ 82,809 Fuel 1,531 2,425 Natural gas in storage 30,619 31,938 Total materials, supplies and fuel $ 117,400 $ 117,172 Materials and supplies represent parts and supplies for all of our business segments. Fuel represents diesel oil and gas used by our Electric Utilities 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 for the three months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment at that time. During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. 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 $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time. The following table presents the carrying value of our investments (in thousands), which are included in Other assets, non-current on the Consolidated Balance Sheets, as of December 31: 2020 2019 Investment in privately held oil and gas company $ 1,500 $ 8,359 Cash surrender value of life insurance contracts 13,628 13,056 Other investments 682 514 Total investments $ 15,810 $ 21,929 We changed the classification of our investments on the Consolidated Balance Sheets as of December 31, 2019 to conform with current year presentation. The prior year reclassification of $22 million from Investments to Other assets, non-current did not impact previously reported current or total assets. 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 stored natural gas 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 related to our regulated properties that do not have legal retirement obligations 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. The composite depreciation method is applied to regulated utility 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. See Note 5 for additional information. 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 7 . 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 are 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, which are also its reportable segments. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis requires 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 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, 2020 and 2019, 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 contract intangibles, 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): 2020 2019 2018 Intangible assets, net, beginning balance $ 13,266 $ 14,337 $ 7,559 Additions — — 7,602 Amortization expense (a) (1,322) (1,071) (824) Intangible assets, net, ending balance $ 11,944 $ 13,266 $ 14,337 _________________ (a) Amortization expense for existing intangible assets is expected to be $1.3 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): 2020 2019 Accrued employee compensation, benefits and withholdings $ 77,806 $ 62,837 Accrued property taxes 47,105 44,547 Customer deposits and prepayments 52,185 54,728 Accrued interest 31,520 31,868 Other (none of which is individually significant) 34,996 32,787 Total accrued liabilities $ 243,612 $ 226,767 Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our 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 wholesale electric energy and natural gas commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2). 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 contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the 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 12 and 15 . 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. In addition, certain derivative 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, Regulated Operations . We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on these designated derivatives 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 derivative 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 counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures. See additional information in Notes 11 , 12 and 13 . 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. See additional information in Note 9 . Regulatory Accounting Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory 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, 2020 and 2019, we had total regulatory assets of $278 million and $271 million respectively, and total regulatory liabilities of $533 million and $537 million respectively. See Note 2 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 benefit (expense) 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 17 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): 2020 2019 2018 Net income available for common stock $ 227,608 $ 199,310 $ 258,442 Weighted average shares - basic 62,378 60,662 54,420 Dilutive effect of: Equity Units — — 898 Equity compensation 61 136 168 Weighted average shares - diluted 62,439 60,798 55,486 Net income available for common stock, per share - Diluted $ 3.65 $ 3.28 $ 4.66 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): 2020 2019 2018 Equity compensation 60 1 16 Anti-dilutive shares excluded from computation of earnings per share 60 1 16 Noncontrolling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810 , Consolidation. 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 14 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

Regulatory Matters_

Regulatory Matters:	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Regulatory Matters	REGULATORY MATTERS We had the following regulatory assets and liabilities as of December 31 (in thousands): 2020 2019 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 39,035 $ 34,088 Deferred gas cost adjustments (a) 3,200 1,540 Gas price derivatives (a) 2,226 3,328 Deferred taxes on AFUDC (b) 7,491 7,790 Employee benefit plans and related deferred taxes (c) 116,598 115,900 Environmental (a) 1,413 1,454 Loss on reacquired debt (a) 22,864 24,777 Renewable energy standard adjustment (a) — 1,622 Deferred taxes on flow-through accounting (c) 47,515 41,220 Decommissioning costs (a) 8,988 10,670 Gas supply contract termination (a) 2,524 8,485 Other regulatory assets (a) 26,404 20,470 Total regulatory assets 278,258 271,344 Less current regulatory assets (51,676) (43,282) Regulatory assets, non-current $ 226,582 $ 228,062 Regulatory liabilities Deferred energy and gas costs (a) $ 13,253 $ 17,278 Employee benefit plan costs and related deferred taxes (c) 40,256 43,349 Cost of removal (a) 172,902 166,727 Excess deferred income taxes (c) 285,259 285,438 Other regulatory liabilities (c) 21,050 23,860 Total regulatory liabilities 532,720 536,652 Less current regulatory liabilities (25,061) (33,507) Regulatory liabilities, non-current $ 507,659 $ 503,145 __________ (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 Utilities’ 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 regulatory 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 regulatory commissions. The recovery period for these costs is less than a year. Deferred Gas Cost Adjustment s - 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 regulatory commissions. The recovery period for these costs is less than a year. Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory 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, 2020 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 and Related Deferred Taxes - 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. In addition, this regulatory asset 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. Environmental - Environmental costs associated with certain former manufactured gas plant sites. These costs are first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the applicable state regulatory commission and therefore, the recovery period is unknown at this time. 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 provides funding for various renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard. These programs include incentives for our Colorado Electric customers to install renewable energy equipment at their location. These project costs and program incentives are recovered over time through the Renewable Energy Standard Adjustment 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 and result in lower utility rates in the year in which the tax benefits are realized. 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 as a regulatory asset and received approval in 2020 to begin recovering those costs over three years. Gas Supply Contract Termination - As part of our acquisition of SourceGas in 2016, we acquired agreements that required the Company to purchase all of the natural gas produced over the productive life of specific leaseholds in the Bowdoin Field in Montana. The majority of these purchases were committed to certain 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 SourceGas Transaction 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 and gas costs that have been over-recovered through customer rates and will be returned to customers in future periods. 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. See Note 17 for additional information. Regulatory Activity 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 our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018 and 2019, the Company successfully delivered several of these tax benefits from the TCJA to its utility customers. In 2020, regulatory proceedings resolved the last of the Company’s open dockets seeking approval of its TCJA plans. As a result, the Company relieved certain TCJA-related liabilities, which resulted in an increase to net income for the year ended December 31, 2020 of $4.0 million. On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related customer billing credits to its customers. The billing credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, will be delivered to customers in February 2021. These billing credits will be offset by a reduction in income tax expense and will result in a minimal impact to Net income. On Janaury 26, 2021, NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related customer billing credits to its customers. The billing credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, is expected to be delivered to customers in the second quarter of 2021. These billing credits will be offset by a reduction in income tax and and will result in a minimal impact to Net income. 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 in 2019 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, 2020 the annual revenue requirement was $27 million and included estimated weighted average capital additions of $33 million for 2019 and 2020 combined. The annual transmission revenue requirement has a true-up mechanism that is recorded in June of each year. Black Hills Wyoming and Wyoming Electric Wygen 1 FERC Filing On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years. Gas Utilities Regulatory Activity Colorado Gas Jurisdictional Consolidation and Rate Reviews On September 11, 2020, Colorado Gas filed a rate review with the CPUC seeking recovery on significant infrastructure investments in its 7,000-mile natural gas pipeline system. The rate review requests $13.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.95%. The request seeks to implement new rates in the second quarter of 2021. On January 6, 2021 the CPUC issued an order dismissing the rate rev iew. On January 26, 2021, Colorado Gas filed an application for rehearing, reargument or reconsideration in response to the Commission’s January 6 order. On September 11, 2020, in accordance with the final order from the earlier rate review discussed below, Colorado Gas also filed a new SSIR proposal that would recover safety and integrity focused investments in its system over five years. A decision from the CPUC is expected by mid-2021. On February 1, 2019, Colorado Gas filed a rate review with the CPUC requesting $2.5 million in new revenue to recover investments in safety, reliability and system integrity and approval to consolidate rates, tariffs, and services of its two existing gas distribution territories. Colorado Gas also requested a new rider mechanism to recover future safety and integrity investments in its system. On May 19, 2020, the CPUC issued a final order which denied the system integrity recovery mechanism and consolidation of rate territories. In addition, the order resulted in an annual revenue decrease of $0.6 million and a return on equity of 9.2%. New rates were effective July 3, 2020. RMNG SSIR On October 30, 2020, RMNG filed the tariff adjusting rates to include 2021 projects with an expected capital investment of $33 million under the current SSIR. The new tariff rates went into effect January 1, 2021 and the current approved SSIR expires December 31, 2021. Nebraska Gas Jurisdictional Consolidation and Rate Review On January 26, 2021, Nebraska Gas received approval from the NPSC to consolidate rate schedules into a new, single statewide structure and recover significant infrastructure investments in its 13,000-mile natural gas pipeline system. Final rates will be enacted on March 1, 2021, to replace interim rates enacted September 1, 2020. The approval will shift $4.6 million of SSIR revenue to base rates and is expected to generate $6.5 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.5%. The approval also includes an extension of the SSIR for five years and an expansion of this mechanism for consolidated utility alignment. Wyoming Gas Jurisdictional Consolidation and Rate Review Wyoming Gas’s new single statewide rate structure became effective March 1, 2020. Wyoming Gas received approval from the WPSC on December 11, 2019, to consolidate the rates, tariffs and services of its four existing gas distribution territories. New rates are expected to generate $13 million in new annual 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.

Commitment, Contingencies And G

Commitment, Contingencies And Guarantees:	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Commitments, Contingencies and Guarantees	COMMITMENTS, CONTINGENCIES AND GUARANTEES Power Purchase and Transmission Services Agreements Through our subsidiaries, we have the following significant long-term power purchase contracts and transmission services agreement (TSA) with non-affiliated third-parties: Subsidiary Contract Type Counterparty Fuel Type Quantity (MW) Expiration Date Colorado Electric (a) PPA PRPA Wind 60 May 31, 2030 Colorado Electric PPA PRPA Coal 25 June 30, 2024 South Dakota Electric PPA PacifiCorp Coal 50 December 31, 2023 South Dakota Electric (b) TSA PacifiCorp N/A 50 December 31, 2023 South Dakota Electric PPA PRPA Wind 12 September 30, 2029 South Dakota Electric PPA Fall River Solar, LLC Solar 80 Pending Completion (c) Wyoming Electric (d) PPA Happy Jack Wind 30 September 3, 2028 Wyoming Electric (e) PPA Silver Sage Wind 30 September 30, 2029 _____________ (a) Colorado Electric sells the wind energy purchased under this PPA to City of Colorado Springs as discussed below. (b) This is a firm point-to-point transmission service agreement that provides 50 MW of capacity and energy to be transmitted annually. (c) This agreement relates to a new solar facility currently being constructed and will expire 20 years after construction completion, which is expected by the end of 2022. (d) Under a separate intercompany PSA, Wyoming Electric sells 50% of the facility output to South Dakota Electric. (e) Under a separate intercompany PSA, Wyoming Electric sells 67% of the facility output to South Dakota Electric. Costs under these agreements for the years ended December 31 were as follows (in thousands): Subsidiary Contract Type Counterparty Fuel Type 2020 2019 2018 Colorado Electric PPA PRPA Wind $ 2,791 $ — $ — Colorado Electric PPA PRPA Coal $ 4,524 $ 1,802 $ — South Dakota Electric PPA PacifiCorp Coal $ 5,897 $ 7,477 $ 13,681 South Dakota Electric TSA PacifiCorp N/A $ 1,776 $ 1,741 $ 1,742 South Dakota Electric PPA PRPA Wind $ 715 $ 688 $ 223 Wyoming Electric PPA Happy Jack Wind $ 4,531 $ 3,936 $ 3,884 Wyoming Electric PPA Silver Sage Wind $ 6,203 $ 5,366 $ 5,376 Power Purchase Agreements - Related Parties Wyoming Electric currently 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 October 15, 2020, the FERC approved a settlement agreement in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I facility. The new agreement will commence on January 1, 2022, replace the existing PPA and continue for 11 years. Black Hills Electric Generation provides the wind energy generated from Busch Ranch II to Colorado Electric through a PPA, which expires in November 2044. Black Hills Electric Generation provides its 14.5 MW share of energy generated from Busch Ranch I 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. At the segment level, we recognize the associated revenues, costs and assets on an accrual basis, rather than as a finance lease. See Note 18 for additional information. 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, 2020, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): Northern Natural Gas - Ventura Northwest Pipeline - Wyoming ONEOK - Oklahoma Southern Star Central Gas Pipeline Panhandle Eastern Pipe Line 2021 3,650,000 1,510,000 5,475,000 113,130 4,680 2022 1,810,000 1,510,000 5,475,000 — — 2023 1,840,000 1,510,000 5,475,000 — — 2024 1,820,000 910,000 5,490,000 — — 2025 — — 4,560,000 — — Thereafter — — — — — Purchases under these contracts totaled $25 million, $6.7 million and $27 million for 2020, 2019 and 2018, respectively. 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. 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 (a) Natural gas transportation and storage agreements 2021 $ 24,452 $ 116,563 2022 $ 11,678 $ 121,819 2023 $ 11,678 $ 100,282 2024 $ 2,738 $ 67,089 2025 $ — $ 50,709 Thereafter $ — $ 167,100 _____________ (a) This schedule does not reflect renewable energy PPA obligations since these agreements vary based on weather conditions. Power Sales Agreements Through our subsidiaries, we have the following significant long-term power sales contracts with non-affiliated third-parties: • On July 1, 2020, Colorado Electric entered into a PSA with the City of Colorado Springs to sell up to 60 MW of wind energy purchased from PRPA under a separate 60 MW PPA discussed above. This PSA with the City of Colorado Springs expires June 30, 2025. • 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 its other generating facilities or from system purchases with reimbursement of costs by the City of Gillette. Under this agreement, which has an initial term through September 3, 2034 and would be renewed annually on September 3 thereafter, 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 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. • 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 PSA 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. 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 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 7 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 $1.2 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 $1.4 million regulatory asset for manufactured gas processing sites; see Note 2 for additional information. As of December 31, 2020, we had $2.6 million accrued for remediation of Iowa’s manufactured gas processing site as the landowner. As of December 31, 2020, we had $0.6 million accrued for remediation of Nebraska’s manufactured gas processing site as the land owner. These liabilities are 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. 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 We have entered into various agreements providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. The agreements, which are off-balance sheet commitments, include indemnification for reclamation and surety bonds. 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. We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2020 Expiration Indemnification for subsidiary reclamation/surety bonds $ 53,769 Ongoing

Revenue_

Revenue:	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue	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, Regulated Operations, 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. Certain energy sale and purchase transactions with the same counterparty and at the same delivery point are netted to reflect the economic substance of the arrangement. • 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 reportable segments, for the years ended December 31, 2020, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 610,721 $ 765,922 $ — $ 58,567 $ (31,478) $ 1,403,732 Transportation — 154,581 — — (526) 154,055 Wholesale 17,848 — 103,258 — (97,169) 23,937 Market - off-system sales 24,309 260 — — (8,797) 15,772 Transmission/Other 58,965 43,658 — — (19,315) 83,308 Revenue from contracts with customers 711,843 964,421 103,258 58,567 (157,285) 1,680,804 Other revenues 2,201 10,249 1,789 2,508 (610) 16,137 Total revenues $ 714,044 $ 974,670 $ 105,047 $ 61,075 $ (157,895) $ 1,696,941 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 58,567 $ (31,478) $ 27,089 Services transferred over time 711,843 964,421 103,258 — (125,807) 1,653,715 Revenue from contracts with customers $ 711,843 $ 964,421 $ 103,258 $ 58,567 $ (157,285) $ 1,680,804 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 Mining Inter-company Revenues 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 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, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative revenue programs revenue under ASC 980, Regulated Operations . 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, 2020
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): 2020 2019 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,417,951 40 $ 1,348,049 41 32 46 Electric transmission 517,794 49 483,640 51 44 51 Electric distribution 959,453 46 861,042 47 46 48 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 259,010 28 259,266 28 26 29 Total electric plant in service 3,159,078 2,956,867 Construction work in progress 89,402 102,268 Total electric plant 3,248,480 3,059,135 Less accumulated depreciation (666,669) (670,861) Electric plant net of accumulated depreciation $ 2,581,811 $ 2,388,274 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 10 years remaining. 2020 2019 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 $ 15,603 40 $ 13,000 35 24 46 Gas transmission 578,278 54 516,172 50 22 71 Gas distribution 2,115,082 53 1,857,233 43 45 59 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciable (a) 39,184 N/A 44,443 N/A N/A N/A Storage 55,481 38 46,977 31 24 52 General 438,217 19 437,054 20 12 23 Total gas plant in service 3,245,384 2,918,418 Construction work in progress 67,229 63,080 Total gas plant 3,312,613 2,981,498 Less accumulated depreciation (323,679) (336,721) Gas plant net of accumulated depreciation $ 2,988,934 $ 2,644,777 _____________ (a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 529,927 $ 4,876 $ 534,803 $ (167,787) $ 367,016 31 2 40 Mining $ 186,552 $ 988 $ 187,540 $ (126,537) $ 61,003 14 2 59 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion 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 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,692 $ 16,402 $ 22,094 $ (1,144) $ 20,950 10 10 22 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,721 $ 23,334 $ 29,055 $ (964) $ 28,091 10 3 30

Jointly Owned Facilities_

Jointly Owned Facilities:	12 Months Ended
	Dec. 31, 2020
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. Wyodak Plant 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. Transmission Tie 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 Power Cooperative owns the remaining ownership percentage. South Dakota Electric is committed to pay its proportionate share of the additions and replacements and operating and maintenance expenses of the transmission tie. Wygen III 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. Wygen I 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, 2020, 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 $ 2,249 $ (67,762) $ 50,561 Transmission Tie $ 26,176 $ 509 $ (7,103) $ 19,582 Wygen III $ 142,739 $ 582 $ (24,783) $ 118,538 Wygen I $ 114,975 $ 318 $ (49,459) $ 65,834 Jointly Owned Facilities - Related Party Busch Ranch I 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. Colorado Electric retains responsibility for operations of the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037. Cheyenne Prairie Cheyenne Prairie serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 37 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 100.4 MW unit that is jointly-owned by South Dakota Electric (58 MW) and Wyoming Electric (42.4 MW). BHSC is responsible for plant operations. Corriedale Corriedale serves as the dedicated wind energy supply for Renewable Ready customers in South Dakota and Wyoming. The 52.5 MW wind farm is jointly-owned by South Dakota Electric (32.5 MW) and Wyoming Electric (20 MW). BHSC is responsible for operations of the wind farm.

Asset Retirement Obligations_

Asset Retirement Obligations:	12 Months Ended
	Dec. 31, 2020
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, 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, 2019 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2020 Electric Utilities (a) $ 9,329 $ 1,217 $ — $ 407 $ — $ 10,953 Gas Utilities (b) 36,085 4,782 (132) 1,539 — 42,274 Power Generation 4,739 — — 206 — 4,945 Mining (c) 14,052 — (185) 617 (1,225) 13,259 Total 64,205 $ 5,999 $ (317) $ 2,769 $ (1,225) $ 71,431 December 31, 2018 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2019 Electric Utilities (d) $ 6,258 $ — $ — $ 385 $ 2,686 $ 9,329 Gas Utilities 34,627 — — 1,458 — 36,085 Power Generation (a) 300 3,445 — 158 836 4,739 Mining (c) 15,615 — (380) 740 (1,923) 14,052 Total $ 56,800 $ 3,445 $ (380) $ 2,741 $ 1,599 $ 64,205 _____________________ (a) Liabilities incurred were related to new wind assets. (b) Liabilities incurred were driven by an increase in gas pipeline miles; which increases our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The Mining Revisions to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process. (d) The Electric Utilities Revisions to Prior Estimates was primarily driven by an increase in the estimated cost to decommission certain regulated wind farm 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.

Leases_

Leases:	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Lease	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 35 years, including options to extend that are reasonably certain to be exercised. We have one immaterial finance lease for communication equipment at the WRDC mine. Most of our leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using our applicable subsidiaries’ incremental borrowing rate (weighted-average of 4.24% as of December 31, 2020). Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the accompanying Consolidated Balance Sheets. Lease expense for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease cost Operations and maintenance $ 978 $ 1,456 Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2020 2019 Assets: Operating lease assets Other assets, non-current $ 4,188 $ 4,629 Total lease assets $ 4,188 $ 4,629 Liabilities: Current: Operating leases Accrued liabilities $ 736 $ 1,179 Noncurrent: Operating leases Other deferred credits and other liabilities 3,807 3,821 Total lease liabilities $ 4,543 $ 5,000 Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2020 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,023 $ 1,263 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 161 $ 2,801 Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2020 2019 Weighted average remaining lease term: Operating leases 8 years 8 years Weighted average discount rate: Operating leases 4.24 % 4.27 % As of December 31, 2020, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases 2021 $ 907 2022 804 2023 779 2024 776 2025 529 Thereafter 1,643 Total lease payments $ 5,438 Less imputed interest 895 Present value of lease liabilities $ 4,543 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 34 years. Lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease income Revenue $ 2,534 $ 2,306 As of December 31, 2020, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2021 $ 2,383 2022 2,122 2023 2,130 2024 2,074 2025 2,090 Thereafter 58,829 Total lease receivables $ 69,628
Lease	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 35 years, including options to extend that are reasonably certain to be exercised. We have one immaterial finance lease for communication equipment at the WRDC mine. Most of our leases do not contain a readily determinable discount rate. Therefore, the present value of future lease payments is generally calculated using our applicable subsidiaries’ incremental borrowing rate (weighted-average of 4.24% as of December 31, 2020). Leases with an initial term of 12 months or less are classified as short-term leases and are not recognized on the accompanying Consolidated Balance Sheets. Lease expense for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease cost Operations and maintenance $ 978 $ 1,456 Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2020 2019 Assets: Operating lease assets Other assets, non-current $ 4,188 $ 4,629 Total lease assets $ 4,188 $ 4,629 Liabilities: Current: Operating leases Accrued liabilities $ 736 $ 1,179 Noncurrent: Operating leases Other deferred credits and other liabilities 3,807 3,821 Total lease liabilities $ 4,543 $ 5,000 Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2020 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,023 $ 1,263 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 161 $ 2,801 Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2020 2019 Weighted average remaining lease term: Operating leases 8 years 8 years Weighted average discount rate: Operating leases 4.24 % 4.27 % As of December 31, 2020, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases 2021 $ 907 2022 804 2023 779 2024 776 2025 529 Thereafter 1,643 Total lease payments $ 5,438 Less imputed interest 895 Present value of lease liabilities $ 4,543 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 34 years. Lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease income Revenue $ 2,534 $ 2,306 As of December 31, 2020, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2021 $ 2,383 2022 2,122 2023 2,130 2024 2,074 2025 2,090 Thereafter 58,829 Total lease receivables $ 69,628

Debt and Credit Facilities_

Debt and Credit Facilities:	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt and Credit Facilities	DEBT AND CREDIT FACILITIES Short-term debt We had the following Notes payable outstanding at the Consolidated Balance Sheets date (in thousands): December 31, 2020 December 31, 2019 Balance Outstanding Letters of Credit (a) Balance Outstanding Letters of Credit (a) Revolving Credit Facility $ — $ 24,730 $ — $ 30,274 CP Program 234,040 — 349,500 — Total $ 234,040 $ 24,730 $ 349,500 $ 30,274 _______________ (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 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, 2020. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2020. 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 2020 were $(115) million. As of December 31, 2020, the weighted average interest rate on short-term borrowings was 0.27%. 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 below for additional details. Long-term debt Long-term debt outstanding was as follows (dollars in thousands): Interest Rate at Balance Outstanding Due Date December 31, 2020 December 31, 2020 December 31, 2019 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 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 2029 October 15, 2029 3.05% 400,000 400,000 Senior unsecured notes, due 2030 June 15, 2030 2.50% 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 2049 October 15, 2049 3.88% 300,000 300,000 Corporate term loan due 2021 June 7, 2021 2.32% 1,436 7,178 Total Corporate debt 3,026,436 2,632,178 Less unamortized debt discount (7,013) (6,462) Total Corporate debt, net 3,019,423 2,625,716 South Dakota Electric Series 94A Debt, variable rate (a) June 1, 2024 N/A — 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 340,000 342,855 Less unamortized debt discount (78) (82) Total South Dakota Electric debt, net 339,922 342,773 Wyoming Electric Industrial development revenue bonds due 2021 (a) (b) September 1, 2021 0.12% 7,000 7,000 Industrial development revenue bonds due 2027 (a) (b) March 1, 2027 0.12% 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 3,561,345 3,170,489 Less current maturities 8,436 5,743 Less unamortized deferred financing costs (c) 24,809 24,650 Long-term debt, net of current maturities and deferred financing costs $ 3,528,100 $ 3,140,096 _______________ (a) Variable interest rate. (b) A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due March 1, 2027 and the 2009B bonds of $7.0 million due September 1, 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. (c) Includes deferred financing costs associated with our Revolving Credit Facility of $1.0 million and $1.7 million as of December 31, 2020 and December 31, 2019, respectively. Scheduled maturities of long-term debt, excluding amortization of premiums or discounts, for future years are (in thousands): 2021 $ 8,436 2022 $ — 2023 $ 525,000 2024 $ — 2025 $ — Thereafter $ 3,035,000 Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2020. See below for additional information. 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. Amortization of 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, 2020 2020 2019 2018 $ 24,809 $ 3,272 $ 3,242 $ 2,829 Debt Transactions On June 17, 2020, we completed a public debt offering which consisted of $400 million of 2.50% 10-year senior unsecured notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes. On March 24, 2020, South Dakota Electric paid off its $2.9 million, Series 94A variable rate notes due June 1, 2024. These notes were tendered by the sole investor on March 17, 2020. On October 3, 2019, we completed a public debt offering of $700 million principal amount in senior unsecured notes. 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. Debt Covenants Revolving Credit Facility 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. We were in compliance with our covenants at December 31, 2020 as shown below: As of December 31, 2020 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 59.9% Less than 65% Wyoming Electric Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2020, we were in compliance with these covenants. 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. 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, 2020: • 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, 2020, the restricted net assets at our Electric and Gas Utilities were approximately $155 million.

Stockholders' Equity_

Stockholders' Equity:	12 Months Ended
	Dec. 31, 2020
Stockholders' Equity Note [Abstract]
Stockholders' Equity	STOCKHOLDERS' EQUITY February 2020 Equity Issuance On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the SEC. At-the-Market Equity Offering Program On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. This forward sales option allows us to sell our shares through the ATM program at the current trading price without actually issuing any shares to satisfy the sale until a future date. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August 3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. We did not issue any common shares under the ATM during the twelve months ended December 31, 2020. During the twelve months ended December 31, 2019, we issued a total of 1,328,332 shares of common stock under the ATM for $99 million, net of $1.2 million in issuance costs. We did not issue any common shares under the ATM during the twelve months ended December 31, 2018. 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, 2020, there were 163,962 shares of unissued stock available for future offering under the DRSPP. 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.

Risk Management And Derivatives

Risk Management And Derivatives:	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management And Derivatives	RISK MANAGEMENT AND DERIVATIVES Market and Credit Risk Disclosures 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, but not limited to, the following market risks: • Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather, market speculation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and • Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic. Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. 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, cash collateral requirements, 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, changes in current market conditions, expected losses and any specific customer collection issue that is identified. Our credit exposure at December 31, 2020 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. We continue to monitor COVID-19 impacts and changes to customer load, consistency in customer payments, requests for deferred or discounted payments, and requests for changes to credit limits to quantify estimated future financial impacts to the allowance for credit losses. During the year ended December 31, 2020, the potential economic impact of the COVID-19 pandemic was considered in forward looking projections related to write-off and recovery rates, and resulted in increases to the allowance for credit losses and bad debt expense of $3.3 million. See Note 1 for further information. Derivatives and Hedging Activity 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 12 . 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 natural gas price volatility. 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 state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income. We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are 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 sales during time frames ranging from January 2021 through May 2022. 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 gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. 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, 2020 December 31, 2019 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 620,000 3 1,450,000 12 Natural gas options purchased, net 3,160,000 3 3,240,000 3 Natural gas basis swaps purchased 900,000 3 1,290,000 12 Natural gas over-the-counter swaps, net (b) 3,850,000 17 4,600,000 24 Natural gas physical commitments, net (c) 17,513,061 22 13,548,235 12 Electric wholesale contracts (c) 219,000 12 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2020, 914,600 of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP. We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At December 31, 2020, the Company posted $1.5 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets. Derivatives 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. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our 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): Balance Sheet Location 2020 2019 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 181 $ 1 Noncurrent commodity derivatives Other assets, non-current 43 3 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (108) (490) Noncurrent commodity derivatives Other deferred credits and other liabilities — (29) Total derivatives designated as hedges $ 116 $ (515) Derivatives not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1,667 $ 341 Noncurrent commodity derivatives Other assets, non-current 151 2 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (1,936) (1,764) Noncurrent commodity derivatives Other deferred credits and other liabilities — (63) Total derivatives not designated as hedges $ (118) $ (1,484) Derivatives Designated as Hedge Instruments The impact of cash flow hedges on our Consolidated Statements of Income is presented below for the years ended December 31, 2020, 2019 and 2018. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. 2020 2019 2018 2020 2019 2018 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in OCI Income Statement Location Amount of Gain/(Loss) Reclassified from AOCI into Income (in thousands) (in thousands) Interest rate swaps $ 2,851 $ 2,851 $ 2,851 Interest expense $ (2,851) $ (2,851) $ (2,851) Commodity derivatives 540 (965) 1,113 Fuel, purchased power and cost of natural gas sold (601) 417 (130) Total $ 3,391 $ 1,886 $ 3,964 $ (3,452) $ (2,434) $ (2,981) As of December 31, 2020, $2.8 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. 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, 2020, 2019 and 2018. 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. 2020 2019 2018 Derivatives Not Designated as Hedging Instruments Income Statement Location Amount of Gain/(Loss) on Derivatives Recognized in Income (in thousands) Commodity derivatives - Electric Fuel, purchased power and cost of natural gas sold $ 144 $ — $ — Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 1,640 (1,100) 1,101 $ 1,784 $ (1,100) $ 1,101 As discussed above, financial instruments used in our regulated Gas 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 these financial instruments in our Gas Utilities were $2.2 million and $3.3 million at December 31, 2020 and 2019, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income.

Fair Value Measurements_

Fair Value Measurements:	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements Derivatives 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. As of December 31, 2020 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in thousands) Assets: Commodity derivatives - Gas Utilities $ — $ 2,504 $ — $ (1,527) $ 977 Commodity derivatives - Electric Utilities — 1,065 — — 1,065 Total $ — $ 3,569 $ — $ (1,527) $ 2,042 Liabilities: Commodity derivatives - Gas Utilities $ — $ 2,675 $ — $ (1,552) $ 1,123 Commodity derivatives - Electric Utilities $ 921 $ — $ 921 Total $ — $ 3,596 $ — $ (1,552) $ 2,044 _______________ (a) As of December 31, 2020, $1.5 million of our commodity derivative gross assets and $1.6 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements. As of December 31, 2019 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total Assets: Commodity derivatives - Gas Utilities $ — 1,433 $ — $ (1,085) $ 348 Total $ — $ 1,433 $ — $ (1,085) $ 348 Liabilities: Commodity derivatives - Gas Utilities $ — $ 5,254 $ — $ (2,909) $ 2,345 Total $ — $ 5,254 $ — $ (2,909) $ 2,345 _______________ (a) As of December 31, 2019, $1.1 million of our commodity derivative assets and $2.9 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements. Pension and Postretirement Plan Assets A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 15 . 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 . Other Fair Value Measurements The carrying amount of cash and cash equivalents, restricted cash and equivalents, and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and since these borrowings are not traded on an exchange, they are classified in Level 2 in the fair value hierarchy. The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets at December 31 (in thousands): 2020 2019 Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current maturities (a) $ 3,536,536 $ 4,208,167 $ 3,145,839 $ 3,479,367 _______________ (a) 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.

Other Comprehensive Income_

Other Comprehensive Income:	12 Months Ended
	Dec. 31, 2020
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, 2020 December 31, 2019 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 (601) 417 (3,452) (2,434) Income tax Income tax benefit (expense) 383 611 Total reclassification adjustments related to cash flow hedges, net of tax $ (3,069) $ (1,823) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 103 $ 77 Actuarial gain (loss) Operations and maintenance (2,387) (745) (2,284) (668) Income tax Income tax benefit (expense) 935 (453) Total reclassification adjustments related to defined benefit plans, net of tax $ (1,349) $ (1,121) Total reclassifications $ (4,418) $ (2,944) 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, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655) Other comprehensive income (loss) before reclassifications — (47) (1,062) (1,109) Amounts reclassified from AOCI 2,564 505 1,349 4,418 As of December 31, 2020 $ (12,558) $ 2 $ (14,790) $ (27,346) 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)

Variable Interest Entity

Variable Interest Entity	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entity	VARIABLE INTEREST ENTITY Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In 2016, Black Hills Electric Generation sold a 49.9%, noncontrolling interest in Black Hills Colorado IPP 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, Consolidation . 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. Net income available for common stock for the years ended December 31, 2020, 2019 and 2018 was reduced by $15 million, $14 million, and $14 million, respectively, attributable to this noncontrolling interest. The net income allocable to the noncontrolling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of net income attributable to this noncontrolling interest are due within 30 days following the end of a quarter, but may be withheld as necessary by Black Hills Electric Generation. 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): 2020 2019 Assets: Current assets $ 13,604 $ 13,350 Property, plant and equipment of variable interest entities, net $ 190,637 $ 193,046 Liabilities: Current liabilities $ 5,318 $ 6,013

Employee Benefits Plans_

Employee Benefits Plans:	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [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, 2020, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 28% to 36% return-seeking assets and 64% to 72% 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: 2020 2019 Equity 21% 20% Real estate 3 3 Fixed income 69 71 Cash 3 1 Hedge funds 4 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 post-65 Medicare-eligible retirees is provided through an individual market healthcare exchange. We fund the Healthcare Plan on a cash basis as benefits are paid. The Healthcare 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): 2020 2019 Defined Contribution Plan Company retirement contributions $ 10,455 $ 9,714 Company matching contributions $ 15,240 $ 14,558 2020 2019 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 12,700 Non-Pension Defined Benefit Postretirement Healthcare Plan $ 6,058 $ 7,033 Supplemental Non-Qualified Defined Benefit Plans $ 2,674 $ 2,344 We do not have required 2021 contributions and currently do not expect to contribute to our Pension Plan. Fair Value Measurements 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, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Common Collective Trust - Cash and Cash Equivalents $ — $ 16,810 $ — $ 16,810 $ — $ 16,810 Common Collective Trust - Equity — 100,311 — 100,311 — 100,311 Common Collective Trust - Fixed Income — 324,845 — 324,845 — 324,845 Common Collective Trust - Real Estate — — — — 14,301 14,301 Hedge Funds — — — — 17,454 17,454 Total investments measured at fair value $ — $ 441,966 $ — $ 441,966 $ 31,755 $ 473,721 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 _____________ (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, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,165 $ — $ — $ 8,165 $ 8,165 Total investments measured at fair value $ 8,165 $ — $ — $ 8,165 $ 8,165 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 Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows: Pension Plan 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 Funds : These funds are 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. 10% of the shares may be redeemed at the end of each month with a 15-day notice and full redemptions are available at the end of each quarter with 60-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. Non-pension Defined Benefit Postretirement Healthcare Plan Cash and Cash Equivalents: This represents 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. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, amounts recognized in the Consolidated Balance Sheets, accumulated benefit obligation, and reconciliation of components of the net periodic expense and elements of AOCI (in thousands): Employee Benefit Plan Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Change in benefit obligation: Projected benefit obligation at beginning of year $ 485,376 $ 445,381 $ 54,088 $ 43,010 $ 65,277 $ 60,817 Service cost (a) 5,411 5,383 1,579 4,995 2,056 1,815 Interest cost 13,426 17,374 1,099 1,295 1,649 2,247 Actuarial (gain) loss 47,064 56,384 962 7,132 5,804 5,976 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Plan participants’ contributions — — — — 1,510 1,455 Projected benefit obligation at end of year $ 514,008 $ 485,376 $ 55,054 $ 54,088 $ 70,238 $ 65,277 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised. Fair Value Employee Benefit Plan Assets Defined Benefit Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan (a) As of December 31, 2020 2019 2020 2019 2020 2019 Change in fair value of plan assets: Beginning fair value of plan assets $ 434,284 $ 390,796 $ — $ — $ 8,305 $ 8,162 Investment income (loss) 64,006 69,934 — — 33 260 Employer contributions 12,700 12,700 2,674 2,344 4,374 5,461 Retiree contributions — — — — 1,511 1,455 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Ending fair value of plan assets $ 473,721 $ 434,284 $ — $ — $ 8,165 $ 8,305 ____________________ (a) Assets of VEBA trusts. In 2012, we froze our Pension Plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, recent capital markets volatility driven by the COVID-19 pandemic did not materially affect our unfunded status. Amounts Recognized in the Consolidated Balance Sheets Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Regulatory assets $ 86,677 $ 88,471 $ — $ — $ 16,102 $ 11,670 Current liabilities $ — $ — $ 1,927 $ 1,420 $ 4,931 $ 4,802 Non-current liabilities $ 40,287 $ 51,093 $ 53,127 $ 51,243 $ 57,142 $ 52,136 Regulatory liabilities $ 3,607 $ 3,524 $ — $ — $ 2,140 $ 4,088 Accumulated Benefit Obligation Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Accumulated Benefit Obligation $ 498,815 $ 470,615 $ 54,779 $ 49,241 $ 70,238 $ 65,277 Components of Net Periodic Expense Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan For the years ended December 31, 2020 2019 2018 2020 2019 2018 2020 2019 2018 Service cost (a) $ 5,411 $ 5,383 $ 6,834 $ 1,579 $ 4,995 $ 1,764 $ 2,056 $ 1,815 $ 2,291 Interest cost 13,426 17,374 15,470 1,099 1,295 1,170 1,649 2,247 2,085 Expected return on assets (22,591) (24,401) (24,741) — — — (182) (230) (315) Net amortization of prior service cost — 26 58 2 2 2 (546) (398) (398) Recognized net actuarial loss (gain) 8,372 3,763 8,632 1,702 535 1,000 20 — 216 Net periodic expense $ 4,618 $ 2,145 $ 6,253 $ 4,382 $ 6,827 $ 3,936 $ 2,997 $ 3,434 $ 3,879 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised. For the years ended December 31, 2020, 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. Change in Accounting Principle - Pension Accounting Asset Method Effective January 1, 2020, the Company changed its method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company used a calculated value for the return-seeking assets (equities) in the portfolio and fair value for the liability-hedging assets (fixed income). The Company considers the fair value method for determining market-related value of liability-hedging assets to be a preferable method of accounting because asset-related gains and losses are subject to amortization into pension cost immediately. Additionally, the fair value for liability-hedging assets allows for the impact of gains and losses on this portion of the asset portfolio to be reflected in tandem with changes in the liability which is linked to changes in the discount rate assumption for re-measurement. We evaluated the effect of this change in accounting method and deemed it immaterial to the historical and current financial statements and therefore did not account for the change retrospectively. Accordingly, the Company calculated the cumulative difference using a calculated value versus fair value to determine market-related value for liability-hedging assets of the portfolio. The cumulative effect of this change, as of January 1, 2020, resulted in a decrease to prior service costs, as recorded in Other income (expense), net, of $0.6 million, an increase in Income tax expense of $0.2 million and an increase to Net income of $0.4 million within the accompanying Consolidated Statements of Income for the year ended December 31, 2020. AOCI Amounts (After-Tax) Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Net (gain) loss $ 5,511 $ 5,322 $ 9,323 $ 9,893 $ 100 $ 90 Prior service cost (gain) — — — 2 (144) (230) Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense $ 5,511 $ 5,322 $ 9,323 $ 9,895 $ (44) $ (140) Assumptions Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine benefit obligations: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate 2.56 % 3.27 % 4.40 % 2.41 % 3.14 % 4.34 % 2.41 % 3.15 % 4.28 % Rate of increase in compensation levels 3.34 % 3.49 % 3.52 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate (a) 3.27 % 4.40 % 3.71 % 3.14 % 4.34 % 3.67 % 3.15 % 4.28 % 3.60 % Expected long-term rate of return on assets (b) 5.25 % 6.00 % 6.25 % N/A N/A N/A 2.35 % 3.00 % 3.93 % Rate of increase in compensation levels 3.49 % 3.52 % 3.43 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 2.56% for the calculation of the 2021 net periodic pension costs. (b) The expected rate of return on plan assets is 4.50% for the calculation of the 2021 net periodic pension cost. The healthcare benefit obligation at December 31 was determined as follows: 2020 2019 Trend Rate - Medical Pre-65 for next year - All Plans 6.10% 6.40% 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% 4.92% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2029 2028 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 2021 $ 25,842 $ 1,927 $ 6,108 2022 $ 26,658 $ 1,968 $ 5,965 2023 $ 27,581 $ 2,033 $ 5,725 2024 $ 28,284 $ 2,231 $ 5,532 2025 $ 29,062 $ 2,690 $ 5,244 2026-2030 $ 144,273 $ 13,117 $ 22,872

Share-based Compensation Plans_

Share-based Compensation Plans:	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Share-based Compensation Plans	SHARE-BASED COMPENSATION PLANS Our 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units, stock options, performance shares and performance share units. We had 561,073 shares available to grant at December 31, 2020. 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, 2020, 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, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31 (in thousands): 2020 2019 2018 Stock-based compensation expense $ 5,373 $ 12,095 $ 12,390 Stock Options The Company has not issued any stock options since 2014 and has 5,000 stock options outstanding at December 31, 2020. The amount of stock options granted 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 three 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, 2020, was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at January 1, 2020 192 $ 65.66 Granted 116 69.49 Vested (90) 63.30 Forfeited (22) 65.30 Balance at December 31, 2020 196 $ 69.05 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) 2020 $ 69.49 $ 6,722 2019 $ 73.66 $ 8,438 2018 $ 57.31 $ 6,776 As of December 31, 2020, there was $10.3 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.2 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 $2.7 million at December 31, 2020 would be reclassified as a liability. Outstanding performance periods at December 31, 2020 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2020 January 1, 2020 - December 31, 2022 36 0% 200% January 1, 2019 January 1, 2019 - December 31, 2021 36 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 49 0% 200% A summary of the status of the Performance Share Plan at December 31, 2020 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2020 (in thousands) (in thousands) Performance Shares balance at beginning of period 67 $ 64.32 67 Granted 19 81.42 19 Forfeited (2) 73.89 (2) Vested (23) 63.52 (23) Performance Shares balance at end of period 61 $ 69.71 61 $ 52.42 _____________________ (a) The grant date fair values for the performance shares granted in 2020, 2019 and 2018 were determined by Monte Carlo simulation using a blended volatility of 18%, 21% and 21%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2020 $ 81.42 December 31, 2019 $ 68.72 December 31, 2018 $ 61.82 Performance plan payouts have been as follows (in thousands): Performance Period Year Paid Stock Issued Cash Paid Total Intrinsic Value January 1, 2017 to December 31, 2019 2020 14 $ 1,100 $ 2,199 January 1, 2016 to December 31, 2018 2019 44 $ 2,860 $ 5,720 January 1, 2015 to December 31, 2017 2018 — — — On January 27, 2021, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2018 through December 31, 2020 performance period was at the 55th percentile of its peer group and confirmed a payout equal to 112.35% of target shares, valued at $3.3 million. The payout was fully accrued at December 31, 2020. As of December 31, 2020, there was $2.0 million of unrecognized compensation expense related to outstanding performance share plans that is expected to be recognized over a weighted-average period of 1.7 years.

Income Taxes_

Income Taxes:	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES CARES Act On March 27, 2020, President Trump signed the CARES Act, which contained, in part, an allowance for deferral of the employer portion of Social Security employment tax liabilities until 2021 and 2022, as well as a COVID-19 employee retention tax credit of up to $5,000 per eligible employee. Eligible employers are taxpayers experiencing either: (1) a full or partial suspension of business operations stemming from a government COVID-19 related order or (2) a more than 50% drop in gross receipts compared to the corresponding calendar quarter in 2019. This 50% employee retention tax credit applies up to $10,000 in qualified wages paid between March 13, 2020 through December 31, 2020, and is refundable to the extent it exceeds the employer portion of payroll tax liability. Eligible wages or employer-paid health benefits must be paid for the period of time during which an employee did not provide services. However, employees do not need to stop providing all services to the employer for the credit to potentially apply. Additionally, the CARES Act accelerates the amount of alternative minimum tax (“AMT”) credits that can be refunded for the 2018 and 2019 annual tax returns. In 2020, we filed for, and received, a refund of approximately $2.4 million of AMT credit carryforwards under this provision. During the year ended December 31, 2020, we utilized the payroll tax deferral provision which allowed us to defer payment of approximately $10 million of Social Security employment tax liabilities. We are currently reviewing the potential future benefits of the CARES Act related to employee retention tax credits to assess the impact on our financial position, results of operations and cash flows. 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, 2020, the Company has amortized $13.3 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2020, 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. Income Tax Expense (Benefit) Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): 2020 2019 2018 Current: Federal $ (6,020) $ (8,578) $ 325 State 847 138 247 Current income tax expense (benefit) (5,173) (8,440) 572 Deferred: Federal 35,672 34,551 (25,022) State 2,419 3,469 783 Deferred income tax expense (benefit) 38,091 38,020 (24,239) Income tax expense (benefit) $ 32,918 $ 29,580 $ (23,667) Effective Tax Rates The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2020 2019 2018 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax (net of federal tax effect) 2.4 1.5 2.3 Non-controlling interest (a) (1.2) (1.2) (1.3) Tax credits (b) (c) (9.2) (3.9) (2.0) Flow-through adjustments (d) (1.6) (2.4) (1.6) Jurisdictional consolidation project (e) — — (28.5) Uncertain Tax Benefits 1.5 — — Valuation Allowance 0.7 — — Other tax differences 0.6 (1.6) (0.1) TCJA corporate rate reduction (f) — — 1.6 Amortization of excess deferred income tax expense (g) (2.3) (1.2) (0.7) Effective Tax Rate 11.9 % 12.2 % (9.3) % _________________________ (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) The current year increase of PTCs reflect full year production of two wind facilities that were acquired/ placed into service during 2019; Top of Iowa purchased February 2019 and Busch Ranch II with an in-service date of November 2019. Additionally, in November 2020, the Corriedale qualifying wind facility was placed in service. (c) In 2020, the Company completed a research and development study which encompassed tax years from 2013 to 2019. (d) 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. (e) In 2018, the Company restructured certain legal entities from earlier acquisitions, which resulted in additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, and deferred tax benefits of $73 million. (f) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. 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. (g) Primarily TCJA - see above. 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): 2020 2019 Deferred tax assets: Regulatory liabilities $ 90,535 $ 89,754 State tax credits 23,339 23,261 Federal NOL 96,155 120,624 State NOL 9,914 13,537 Partnership 15,601 14,030 Credit Carryovers 51,445 27,139 Other deferred tax assets 40,143 33,395 Less: Valuation allowance (13,943) (12,063) Total deferred tax assets 313,189 309,677 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (551,137) (533,292) Regulatory assets (28,007) (23,586) Goodwill (30,590) (15,875) State deferred tax liability (73,910) (72,911) Other deferred tax liabilities (38,169) (24,732) Total deferred tax liabilities (721,813) (670,396) Net deferred tax liability $ (408,624) $ (360,719) Net Operating Loss Carryforwards At December 31, 2020, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal NOL Carryforward $ 378,236 2022 to 2037 Federal NOL Carryforward $ 79,644 No expiration State NOL Carryforward (a) $ 173,867 2021 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, 2020, we had a $1.1 million valuation allowance against the state NOL carryforwards. Our 2020 analysis of the ability to utilize such NOLs resulted in a $0.8 million increase in the valuation allowance reduced by previously reserved expiring NOL of $0.2 million, which results in an increase to tax expense of $0.8 million net of federal income tax and a decrease to the state NOL deferred tax asset of $0.2 million. The valuation allowance adjustment was primarily attributable to statutory rate reduction for years beyond 2020. Unrecognized Tax Benefits 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, 2018 $ 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 Additions for prior year tax positions 3,788 Reductions for prior year tax positions (1,313) Additions for current year tax positions 1,743 Settlements — Ending balance at December 31, 2020 $ 8,383 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $4.3 million. We recognized no interest expense associated with income taxes for the years ended December 31, 2020, December 31, 2019 and December 31, 2018. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2020 and December 31, 2019. 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 2017. As of December 31, 2020, 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, 2021. State tax credits have been generated and are available to offset future state income taxes. At December 31, 2020, 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 $ 278 No expiration As of December 31, 2020, we had a $12.8 million valuation allowance against the state ITC carryforwards. Our 2020 analysis of the ability to utilize such ITC resulted in a $1.3 million increase in the valuation allowance, which resulted in an increase to tax expense of $1.3 million. The valuation allowance adjustment was primarily attributable to changes in forecasted future state taxable income.

Business Segment Information_

Business Segment Information:	12 Months Ended
	Dec. 31, 2020
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. 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. This presentation of segment information does not impact consolidated financial results. Segment information was as follows (in thousands): Total Assets (net of intercompany eliminations) as of December 31, 2020 2019 Electric Utilities $ 3,120,928 $ 2,900,983 Gas Utilities 4,376,204 4,032,339 Power Generation 404,220 417,715 Mining 77,085 77,175 Corporate and Other 110,349 130,245 Total assets $ 8,088,786 $ 7,558,457 Capital Expenditures (a) for the years ended December 31, 2020 2019 Electric Utilities $ 271,104 $ 222,911 Gas Utilities 449,209 512,366 Power Generation 9,329 85,346 Mining 8,250 8,430 Corporate and Other 17,500 20,702 Total capital expenditures $ 755,392 $ 849,755 _________________ (a) Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows . Property, Plant and Equipment as of December 31, 2020 2019 Electric Utilities $ 3,248,480 $ 3,059,135 Gas Utilities 3,312,613 2,981,498 Power Generation 534,803 534,518 Mining 187,540 180,473 Corporate and Other 22,094 29,055 Total property, plant and equipment $ 7,305,530 $ 6,784,679 Consolidating Income Statement Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 687,929 $ 959,696 $ 6,090 $ 27,089 $ — $ — $ 1,680,804 Other revenues 2,201 9,962 1,566 2,408 — — 16,137 690,130 969,658 7,656 29,497 — — 1,696,941 Inter-company operating revenue - Contracts with customers 23,914 4,724 97,169 31,478 167 (157,452) — Other revenues — 288 222 100 352,976 (353,586) — 23,914 5,012 97,391 31,578 353,143 (511,038) — Total revenue 714,044 974,670 105,047 61,075 353,143 (511,038) 1,696,941 Fuel, purchased power and cost of natural gas sold 267,045 354,645 8,993 — 83 (138,362) 492,404 Operations and maintenance, including taxes 196,794 303,577 33,695 39,033 284,501 (305,823) 551,777 Depreciation, depletion and amortization 94,150 100,559 20,247 9,235 25,150 (24,884) 224,457 Adjusted operating income (loss) $ 156,055 $ 215,889 $ 42,112 $ 12,807 $ 43,409 $ (41,969) $ 428,303 Interest expense, net (143,470) Impairment of investment (6,859) Other income (expense), net (2,293) Income tax benefit (expense) (32,918) Income from continuing operations 242,763 (Loss) from discontinued operations, net of tax — Net income 242,763 Net income attributable to noncontrolling interest (15,155) Net income available for common stock $ 227,608 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, including taxes 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 (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 Consolidating Income Statement Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations 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, including taxes 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) 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

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENT In February 2021, a prolonged period of historic cold temperatures across the central United States, which covered all of our Utilities’ service territories, caused a significant increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. Our Utilities have regulatory mechanisms to recover the increased energy costs from this record-breaking cold weather event. However, given the extraordinary impact of these higher costs to our customers, we expect our regulators to undertake a heightened review. We are engaged with our regulators to identify appropriate recovery periods over which to recover costs associated with this event as we continue to address the impacts to our customers’ bills. As a result of this historic event, our natural gas purchases increased by approximately $600 million compared to forecasted base load for the month of February. This amount is a preliminary estimate through February 24, 2021, and does not include certain pipeline transportation charges that remain subject to settlement and payable in late March 2021. To fund February natural gas purchases and pipeline transportation charges and provide additional liquidity, we entered into a nine-month Credit Agreement on February 24, 2021, that provides for an $800 million unsecured term loan facility. The term loan, which matures on November 23, 2021, has an interest rate based on LIBOR plus 75 basis points, carries no prepayment penalty and is subject to the same covenant requirements as our Revolving Credit Facility. We expect to repay a portion of this term loan prior to maturity and refinance the remaining portion in longer-term debt. In the event we are unable to refinance the remaining obligation under the $800 million term loan, we believe it is probable that our current plans to manage liquidity would be sufficient to meet our obligations. Except as described above and the Note 2 disclosures surrounding Colorado Gas’ and Nebraska Gas’ jurisdictional consolidation and rate reviews, there have been no events subsequent to December 31, 2020 which would require recognition in the consolidated financial statements or disclosures.

Business Description And Sign_2

Business Description And Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
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. Both 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 coal mining activities located near Gillette, Wyoming. For further descriptions of our reportable business segments, see Note 18 . 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 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. Unless otherwise noted, the amounts presented in the accompanying Notes to Consolidated Financial Statements relate to the Company’s continuing operations.
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. COVID-19 Pandemic In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations. The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the year ended December 31, 2020, there were no material adverse impacts on the Company’s results of operations.
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 18 . 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 generation facility, wind farm or transmission tie. See Note 6 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 14 .
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 Credit Losses	Accounts Receivable and Allowance for Credit Losses Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses. Accounts receivable for our Power Generation and Mining business segments consists of amounts due from sales of electric energy and capacity and coal primarily to affiliates or regional utilities. We maintain an allowance for credit losses 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 credit losses 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, expected losses, 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, 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): 2020 2019 Materials and supplies $ 85,250 $ 82,809 Fuel 1,531 2,425 Natural gas in storage 30,619 31,938 Total materials, supplies and fuel $ 117,400 $ 117,172 Materials and supplies represent parts and supplies for all of our business segments. Fuel represents diesel oil and gas used by our Electric Utilities 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 for the three months ended September 30, 2019, which was the difference between the carrying amount and the fair value of the investment at that time. During the first quarter of 2020, we assessed our investment for impairment as a result of continued adverse changes in future natural gas prices and liquidity concerns at the privately held oil and gas company. We performed an internal analysis to compute the fair value of our investment, utilizing a consistent methodology as applied during the third quarter of 2019. 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 $6.9 million for the three months ended March 31, 2020, which was the difference between the carrying value and the fair value of the investment at that time.
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 stored natural gas 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 related to our regulated properties that do not have legal retirement obligations 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. The composite depreciation method is applied to regulated utility 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. See Note 5 for additional information.
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. 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 7 .
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 are 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, which are also its reportable segments. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis requires 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.
Fair Value Measurements	Fair Value Measurements Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our 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 wholesale electric energy and natural gas commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2). 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 contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the 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 12 and 15 .
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. In addition, certain derivative 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, Regulated Operations . We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on these designated derivatives 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 derivative 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 counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures. See additional information in Notes 11 , 12 and 13 .
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. See additional information in Note 9 .
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 regulatory 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, 2020 and 2019, we had total regulatory assets of $278 million and $271 million respectively, and total regulatory liabilities of $533 million and $537 million respectively. See Note 2 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 benefit (expense) 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 17 for additional information.
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 , Consolidation. 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 14 for additional detail on noncontrolling interests.
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. See additional information in Note 16 . Change in Accounting Principle - Pension Accounting Asset Method Effective January 1, 2020, we changed our method of accounting for net periodic benefit cost. Prior to the change, the Company used a calculated value for determining market-related value of plan assets which amortized the effects of gains and losses over a five-year period. Effective with the accounting change, the Company will continue to use a calculated value for the return-seeking assets (equities) in the portfolio but was changed to fair value for the liability-hedging assets (fixed income). See Note 15 for additional information.
Recently Issued and Adopted Accounting Standards	Recently Issued Accounting Standards Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting , which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2022. We are currently evaluating if we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements and the potential impact on our financial position, results of operations and cash flows. 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. Adoption of this standard is not anticipated to have a material impact on our financial position, results of operations and cash flows. Recently Adopted Accounting Standards Financial Instruments -- Credit Losses: Measurement of Credit Losses on Financial Instruments, ASU 2016-13 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. 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 credit losses, primarily associated with the inclusion of expected losses on unbilled revenue. The cumulative effect of the adoption, net of tax impact, was $0.2 million, which was recorded as an adjustment to retained earnings. 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. We adopted this standard prospectively on January 1, 2020. Adoption of this guidance did not have any impact on our financial position, results of operations or 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. 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.
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, Regulated Operations, 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. Certain energy sale and purchase transactions with the same counterparty and at the same delivery point are netted to reflect the economic substance of the arrangement. • 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, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative revenue programs revenue under ASC 980, Regulated Operations . 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 .

Business Description And Sign_3

Business Description And Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
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): 2020 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net Electric Utilities $ 45,841 $ 32,915 $ (1,269) $ 77,487 Gas Utilities 95,592 93,150 (5,734) 183,008 Power Generation 1,837 — — 1,837 Mining 2,511 — — 2,511 Corporate 1,118 — — 1,118 Total $ 146,899 $ 126,065 $ (7,003) $ 265,961 2019 Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses 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
Financing Receivable, Current, Allowance for Credit Loss	Changes to allowance for credit losses 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 2020 $ 2,444 $ 8,927 (a) $ 4,728 $ (9,096) $ 7,003 2019 $ 3,209 $ 5,795 $ 3,942 $ (10,502) $ 2,444 2018 $ 3,081 $ 6,859 $ 4,092 $ (10,823) $ 3,209 _________________ (a) Due to the COVID-19 pandemic, all of our jurisdictions temporarily suspended disconnections due to non-payment for a period of time, which increased our accounts receivable arrears balances. As a result, we increased our allowance for credit losses and bad debt expense for the year ended December 31, 2020 by an incremental $3.3 million. The ongoing credit evaluation of our customers during the COVID-19 pandemic is further discussed in the Credit Risk section of Note 11 .
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): 2020 2019 Materials and supplies $ 85,250 $ 82,809 Fuel 1,531 2,425 Natural gas in storage 30,619 31,938 Total materials, supplies and fuel $ 117,400 $ 117,172
Investments	The following table presents the carrying value of our investments (in thousands), which are included in Other assets, non-current on the Consolidated Balance Sheets, as of December 31: 2020 2019 Investment in privately held oil and gas company $ 1,500 $ 8,359 Cash surrender value of life insurance contracts 13,628 13,056 Other investments 682 514 Total investments $ 15,810 $ 21,929
Goodwill	As of December 31, 2020 and 2019, 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): 2020 2019 2018 Intangible assets, net, beginning balance $ 13,266 $ 14,337 $ 7,559 Additions — — 7,602 Amortization expense (a) (1,322) (1,071) (824) Intangible assets, net, ending balance $ 11,944 $ 13,266 $ 14,337 _________________ (a) Amortization expense for existing intangible assets is expected to be $1.3 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): 2020 2019 Accrued employee compensation, benefits and withholdings $ 77,806 $ 62,837 Accrued property taxes 47,105 44,547 Customer deposits and prepayments 52,185 54,728 Accrued interest 31,520 31,868 Other (none of which is individually significant) 34,996 32,787 Total accrued liabilities $ 243,612 $ 226,767
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): 2020 2019 2018 Net income available for common stock $ 227,608 $ 199,310 $ 258,442 Weighted average shares - basic 62,378 60,662 54,420 Dilutive effect of: Equity Units — — 898 Equity compensation 61 136 168 Weighted average shares - diluted 62,439 60,798 55,486 Net income available for common stock, per share - Diluted $ 3.65 $ 3.28 $ 4.66
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): 2020 2019 2018 Equity compensation 60 1 16 Anti-dilutive shares excluded from computation of earnings per share 60 1 16

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities as of December 31 (in thousands): 2020 2019 Regulatory assets Deferred energy and fuel cost adjustments (a) $ 39,035 $ 34,088 Deferred gas cost adjustments (a) 3,200 1,540 Gas price derivatives (a) 2,226 3,328 Deferred taxes on AFUDC (b) 7,491 7,790 Employee benefit plans and related deferred taxes (c) 116,598 115,900 Environmental (a) 1,413 1,454 Loss on reacquired debt (a) 22,864 24,777 Renewable energy standard adjustment (a) — 1,622 Deferred taxes on flow-through accounting (c) 47,515 41,220 Decommissioning costs (a) 8,988 10,670 Gas supply contract termination (a) 2,524 8,485 Other regulatory assets (a) 26,404 20,470 Total regulatory assets 278,258 271,344 Less current regulatory assets (51,676) (43,282) Regulatory assets, non-current $ 226,582 $ 228,062 Regulatory liabilities Deferred energy and gas costs (a) $ 13,253 $ 17,278 Employee benefit plan costs and related deferred taxes (c) 40,256 43,349 Cost of removal (a) 172,902 166,727 Excess deferred income taxes (c) 285,259 285,438 Other regulatory liabilities (c) 21,050 23,860 Total regulatory liabilities 532,720 536,652 Less current regulatory liabilities (25,061) (33,507) Regulatory liabilities, non-current $ 507,659 $ 503,145 __________ (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.

Commitment, Contingencies And_2

Commitment, Contingencies And Guarentees (Tables)	12 Months Ended
	Dec. 31, 2020
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 (a) Natural gas transportation and storage agreements 2021 $ 24,452 $ 116,563 2022 $ 11,678 $ 121,819 2023 $ 11,678 $ 100,282 2024 $ 2,738 $ 67,089 2025 $ — $ 50,709 Thereafter $ — $ 167,100 _____________ (a) This schedule does not reflect renewable energy PPA obligations since these agreements vary based on weather conditions.
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 2020-2022 15 MW 7 MW 8 MW 2022-2023 15 MW 8 MW 7 MW 2023-2028 10 MW 5 MW 5 MW
Schedule of Guarantor Obligations	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. We had the following guarantees in place as of (in thousands): Maximum Exposure at Nature of Guarantee December 31, 2020 Expiration Indemnification for subsidiary reclamation/surety bonds $ 53,769 Ongoing
Transmission Service Agreement
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment	Through our subsidiaries, we have the following significant long-term power purchase contracts and transmission services agreement (TSA) with non-affiliated third-parties: Subsidiary Contract Type Counterparty Fuel Type Quantity (MW) Expiration Date Colorado Electric (a) PPA PRPA Wind 60 May 31, 2030 Colorado Electric PPA PRPA Coal 25 June 30, 2024 South Dakota Electric PPA PacifiCorp Coal 50 December 31, 2023 South Dakota Electric (b) TSA PacifiCorp N/A 50 December 31, 2023 South Dakota Electric PPA PRPA Wind 12 September 30, 2029 South Dakota Electric PPA Fall River Solar, LLC Solar 80 Pending Completion (c) Wyoming Electric (d) PPA Happy Jack Wind 30 September 3, 2028 Wyoming Electric (e) PPA Silver Sage Wind 30 September 30, 2029 _____________ (a) Colorado Electric sells the wind energy purchased under this PPA to City of Colorado Springs as discussed below. (b) This is a firm point-to-point transmission service agreement that provides 50 MW of capacity and energy to be transmitted annually. (c) This agreement relates to a new solar facility currently being constructed and will expire 20 years after construction completion, which is expected by the end of 2022. (d) Under a separate intercompany PSA, Wyoming Electric sells 50% of the facility output to South Dakota Electric. (e) Under a separate intercompany PSA, Wyoming Electric sells 67% of the facility output to South Dakota Electric.
Power purchased
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment	Costs under these agreements for the years ended December 31 were as follows (in thousands): Subsidiary Contract Type Counterparty Fuel Type 2020 2019 2018 Colorado Electric PPA PRPA Wind $ 2,791 $ — $ — Colorado Electric PPA PRPA Coal $ 4,524 $ 1,802 $ — South Dakota Electric PPA PacifiCorp Coal $ 5,897 $ 7,477 $ 13,681 South Dakota Electric TSA PacifiCorp N/A $ 1,776 $ 1,741 $ 1,742 South Dakota Electric PPA PRPA Wind $ 715 $ 688 $ 223 Wyoming Electric PPA Happy Jack Wind $ 4,531 $ 3,936 $ 3,884 Wyoming Electric PPA Silver Sage Wind $ 6,203 $ 5,366 $ 5,376
Purchased Gas Cost Obligation
Long-term Purchase Commitment [Line Items]
Long-term Purchase Commitment	At December 31, 2020, the long-term commitments to purchase quantities of natural gas under contracts indexed to the following forward indices were as follows (in MMBtus): Northern Natural Gas - Ventura Northwest Pipeline - Wyoming ONEOK - Oklahoma Southern Star Central Gas Pipeline Panhandle Eastern Pipe Line 2021 3,650,000 1,510,000 5,475,000 113,130 4,680 2022 1,810,000 1,510,000 5,475,000 — — 2023 1,840,000 1,510,000 5,475,000 — — 2024 1,820,000 910,000 5,490,000 — — 2025 — — 4,560,000 — — Thereafter — — — — —

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2020
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 reportable segments, for the years ended December 31, 2020, 2019 and 2018. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Inter-company Revenues Total Customer types: (in thousands) Retail $ 610,721 $ 765,922 $ — $ 58,567 $ (31,478) $ 1,403,732 Transportation — 154,581 — — (526) 154,055 Wholesale 17,848 — 103,258 — (97,169) 23,937 Market - off-system sales 24,309 260 — — (8,797) 15,772 Transmission/Other 58,965 43,658 — — (19,315) 83,308 Revenue from contracts with customers 711,843 964,421 103,258 58,567 (157,285) 1,680,804 Other revenues 2,201 10,249 1,789 2,508 (610) 16,137 Total revenues $ 714,044 $ 974,670 $ 105,047 $ 61,075 $ (157,895) $ 1,696,941 Timing of revenue recognition: Services transferred at a point in time $ — $ — $ — $ 58,567 $ (31,478) $ 27,089 Services transferred over time 711,843 964,421 103,258 — (125,807) 1,653,715 Revenue from contracts with customers $ 711,843 $ 964,421 $ 103,258 $ 58,567 $ (157,285) $ 1,680,804 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 Mining Inter-company Revenues 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

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2020 2019 Lives (in years) Electric Utilities Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) Minimum Maximum Electric plant: Production $ 1,417,951 40 $ 1,348,049 41 32 46 Electric transmission 517,794 49 483,640 51 44 51 Electric distribution 959,453 46 861,042 47 46 48 Plant acquisition adjustment (a) 4,870 32 4,870 32 32 32 General 259,010 28 259,266 28 26 29 Total electric plant in service 3,159,078 2,956,867 Construction work in progress 89,402 102,268 Total electric plant 3,248,480 3,059,135 Less accumulated depreciation (666,669) (670,861) Electric plant net of accumulated depreciation $ 2,581,811 $ 2,388,274 _____________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 10 years remaining. 2020 2019 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 $ 15,603 40 $ 13,000 35 24 46 Gas transmission 578,278 54 516,172 50 22 71 Gas distribution 2,115,082 53 1,857,233 43 45 59 Cushion gas - depreciable (a) 3,539 28 3,539 28 28 28 Cushion gas - not depreciable (a) 39,184 N/A 44,443 N/A N/A N/A Storage 55,481 38 46,977 31 24 52 General 438,217 19 437,054 20 12 23 Total gas plant in service 3,245,384 2,918,418 Construction work in progress 67,229 63,080 Total gas plant 3,312,613 2,981,498 Less accumulated depreciation (323,679) (336,721) Gas plant net of accumulated depreciation $ 2,988,934 $ 2,644,777 _____________ (a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Power Generation $ 529,927 $ 4,876 $ 534,803 $ (167,787) $ 367,016 31 2 40 Mining $ 186,552 $ 988 $ 187,540 $ (126,537) $ 61,003 14 2 59 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation and Depletion 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 2020 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,692 $ 16,402 $ 22,094 $ (1,144) $ 20,950 10 10 22 2019 Lives (in years) Property, Plant and Equipment Construction Work in Progress Total Property Plant and Equipment Less Accumulated Depreciation Net Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum Corporate $ 5,721 $ 23,334 $ 29,055 $ (964) $ 28,091 10 3 30

Jointly Owned Facilities (Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Jointly Owned Utility Plants	At December 31, 2020, 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 $ 2,249 $ (67,762) $ 50,561 Transmission Tie $ 26,176 $ 509 $ (7,103) $ 19,582 Wygen III $ 142,739 $ 582 $ (24,783) $ 118,538 Wygen I $ 114,975 $ 318 $ (49,459) $ 65,834

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2019 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2020 Electric Utilities (a) $ 9,329 $ 1,217 $ — $ 407 $ — $ 10,953 Gas Utilities (b) 36,085 4,782 (132) 1,539 — 42,274 Power Generation 4,739 — — 206 — 4,945 Mining (c) 14,052 — (185) 617 (1,225) 13,259 Total 64,205 $ 5,999 $ (317) $ 2,769 $ (1,225) $ 71,431 December 31, 2018 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2019 Electric Utilities (d) $ 6,258 $ — $ — $ 385 $ 2,686 $ 9,329 Gas Utilities 34,627 — — 1,458 — 36,085 Power Generation (a) 300 3,445 — 158 836 4,739 Mining (c) 15,615 — (380) 740 (1,923) 14,052 Total $ 56,800 $ 3,445 $ (380) $ 2,741 $ 1,599 $ 64,205 _____________________ (a) Liabilities incurred were related to new wind assets. (b) Liabilities incurred were driven by an increase in gas pipeline miles; which increases our legal liability for retirement of gas pipelines, specifically to purge and cap these lines in accordance with Federal regulations. (c) The Mining Revisions to Prior Estimates were primarily driven by changes in estimated costs associated with back-filling the pit with overburden removed during the mining process. (d) The Electric Utilities Revisions to Prior Estimates was primarily driven by an increase in the estimated cost to decommission certain regulated wind farm assets.

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2020
Lessee Disclosure [Abstract]
Lease, Cost	Lease expense for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease cost Operations and maintenance $ 978 $ 1,456
Lessee Supplemental Balance Sheet Information	Supplemental balance sheet information related to leases as of December 31 was as follows (in thousands): Balance Sheet Location 2020 2019 Assets: Operating lease assets Other assets, non-current $ 4,188 $ 4,629 Total lease assets $ 4,188 $ 4,629 Liabilities: Current: Operating leases Accrued liabilities $ 736 $ 1,179 Noncurrent: Operating leases Other deferred credits and other liabilities 3,807 3,821 Total lease liabilities $ 4,543 $ 5,000
Lessee Supplemental Cash Flow Information	Supplemental cash flow information related to leases for the year ended December 31 was as follows (in thousands): 2020 2019 Cash paid included in the measurement of lease liabilities: Operating cash flows from operating leases $ 1,023 $ 1,263 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 161 $ 2,801
Lessee Supplemental Weighted Average Schedule	Weighted average remaining terms and discount rates related to leases as of December 31 were as follows: 2020 2019 Weighted average remaining lease term: Operating leases 8 years 8 years Weighted average discount rate: Operating leases 4.24 % 4.27 %
Finance Lease, Liability, Maturity	As of December 31, 2020, scheduled maturities of lease liabilities for future years were as follows (in thousands): Operating Leases 2021 $ 907 2022 804 2023 779 2024 776 2025 529 Thereafter 1,643 Total lease payments $ 5,438 Less imputed interest 895 Present value of lease liabilities $ 4,543
Lessor Disclosure [Abstract]
Operating Lease, Lease Income	Lease revenue for the year ended December 31 were as follows (in thousands): Income Statement Location 2020 2019 Operating lease income Revenue $ 2,534 $ 2,306
Lessor - Operating And Finance Lease, Liability, Maturity	As of December 31, 2020, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): Operating Leases 2021 $ 2,383 2022 2,122 2023 2,130 2024 2,074 2025 2,090 Thereafter 58,829 Total lease receivables $ 69,628

Debt and Credit Facilities (Tab

Debt and Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Schedule of Short-term Debt	We had the following Notes payable outstanding at the Consolidated Balance Sheets date (in thousands): December 31, 2020 December 31, 2019 Balance Outstanding Letters of Credit (a) Balance Outstanding Letters of Credit (a) Revolving Credit Facility $ — $ 24,730 $ — $ 30,274 CP Program 234,040 — 349,500 — Total $ 234,040 $ 24,730 $ 349,500 $ 30,274 _______________ (a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.
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, 2020 December 31, 2020 December 31, 2019 Corporate Senior unsecured notes due 2023 November 30, 2023 4.25% $ 525,000 $ 525,000 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 2029 October 15, 2029 3.05% 400,000 400,000 Senior unsecured notes, due 2030 June 15, 2030 2.50% 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 2049 October 15, 2049 3.88% 300,000 300,000 Corporate term loan due 2021 June 7, 2021 2.32% 1,436 7,178 Total Corporate debt 3,026,436 2,632,178 Less unamortized debt discount (7,013) (6,462) Total Corporate debt, net 3,019,423 2,625,716 South Dakota Electric Series 94A Debt, variable rate (a) June 1, 2024 N/A — 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 340,000 342,855 Less unamortized debt discount (78) (82) Total South Dakota Electric debt, net 339,922 342,773 Wyoming Electric Industrial development revenue bonds due 2021 (a) (b) September 1, 2021 0.12% 7,000 7,000 Industrial development revenue bonds due 2027 (a) (b) March 1, 2027 0.12% 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 3,561,345 3,170,489 Less current maturities 8,436 5,743 Less unamortized deferred financing costs (c) 24,809 24,650 Long-term debt, net of current maturities and deferred financing costs $ 3,528,100 $ 3,140,096 _______________ (a) Variable interest rate. (b) A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due March 1, 2027 and the 2009B bonds of $7.0 million due September 1, 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. (c) Includes deferred financing costs associated with our Revolving Credit Facility of $1.0 million and $1.7 million as of December 31, 2020 and December 31, 2019, 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): 2021 $ 8,436 2022 $ — 2023 $ 525,000 2024 $ — 2025 $ — Thereafter $ 3,035,000
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, 2020 2020 2019 2018 $ 24,809 $ 3,272 $ 3,242 $ 2,829
Credit Facility and Short Term Debt Covenants	We were in compliance with our covenants at December 31, 2020 as shown below: As of December 31, 2020 Covenant Requirement Consolidated Indebtedness to Capitalization Ratio 59.9% Less than 65%

Risk Management And Derivativ_2

Risk Management And Derivatives (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 December 31, 2019 Notional (MMBtus) Maximum Term (months) (a) Notional (MMBtus) Maximum Term (months) (a) Natural gas futures purchased 620,000 3 1,450,000 12 Natural gas options purchased, net 3,160,000 3 3,240,000 3 Natural gas basis swaps purchased 900,000 3 1,290,000 12 Natural gas over-the-counter swaps, net (b) 3,850,000 17 4,600,000 24 Natural gas physical commitments, net (c) 17,513,061 22 13,548,235 12 Electric wholesale contracts (c) 219,000 12 — 0 __________ (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2020, 914,600 of natural gas over-the-counter swaps purchased were designated as cash flow hedges. (c) Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP.
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): Balance Sheet Location 2020 2019 Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 181 $ 1 Noncurrent commodity derivatives Other assets, non-current 43 3 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (108) (490) Noncurrent commodity derivatives Other deferred credits and other liabilities — (29) Total derivatives designated as hedges $ 116 $ (515) Derivatives not designated as hedges: Asset derivative instruments: Current commodity derivatives Derivative assets - current $ 1,667 $ 341 Noncurrent commodity derivatives Other assets, non-current 151 2 Liability derivative instruments: Current commodity derivatives Derivative liabilities - current (1,936) (1,764) Noncurrent commodity derivatives Other deferred credits and other liabilities — (63) Total derivatives not designated as hedges $ (118) $ (1,484)
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, 2020, 2019 and 2018. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. 2020 2019 2018 2020 2019 2018 Derivatives in Cash Flow Hedging Relationships Amount of Gain/(Loss) Recognized in OCI Income Statement Location Amount of Gain/(Loss) Reclassified from AOCI into Income (in thousands) (in thousands) Interest rate swaps $ 2,851 $ 2,851 $ 2,851 Interest expense $ (2,851) $ (2,851) $ (2,851) Commodity derivatives 540 (965) 1,113 Fuel, purchased power and cost of natural gas sold (601) 417 (130) Total $ 3,391 $ 1,886 $ 3,964 $ (3,452) $ (2,434) $ (2,981) As of December 31, 2020, $2.8 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. 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, 2020, 2019 and 2018. 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. 2020 2019 2018 Derivatives Not Designated as Hedging Instruments Income Statement Location Amount of Gain/(Loss) on Derivatives Recognized in Income (in thousands) Commodity derivatives - Electric Fuel, purchased power and cost of natural gas sold $ 144 $ — $ — Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold 1,640 (1,100) 1,101 $ 1,784 $ (1,100) $ 1,101

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
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. As of December 31, 2020 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in thousands) Assets: Commodity derivatives - Gas Utilities $ — $ 2,504 $ — $ (1,527) $ 977 Commodity derivatives - Electric Utilities — 1,065 — — 1,065 Total $ — $ 3,569 $ — $ (1,527) $ 2,042 Liabilities: Commodity derivatives - Gas Utilities $ — $ 2,675 $ — $ (1,552) $ 1,123 Commodity derivatives - Electric Utilities $ 921 $ — $ 921 Total $ — $ 3,596 $ — $ (1,552) $ 2,044 _______________ (a) As of December 31, 2020, $1.5 million of our commodity derivative gross assets and $1.6 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements. As of December 31, 2019 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total Assets: Commodity derivatives - Gas Utilities $ — 1,433 $ — $ (1,085) $ 348 Total $ — $ 1,433 $ — $ (1,085) $ 348 Liabilities: Commodity derivatives - Gas Utilities $ — $ 5,254 $ — $ (2,909) $ 2,345 Total $ — $ 5,254 $ — $ (2,909) $ 2,345 _______________ (a) As of December 31, 2019, $1.1 million of our commodity derivative assets and $2.9 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.
Fair Value, by Balance Sheet Grouping	The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets at December 31 (in thousands): 2020 2019 Carrying Amount Fair Value Carrying Amount Fair Value Long-term debt, including current maturities (a) $ 3,536,536 $ 4,208,167 $ 3,145,839 $ 3,479,367 _______________ (a) 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.

Other Comprehensive Income (Tab

Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 December 31, 2019 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 (601) 417 (3,452) (2,434) Income tax Income tax benefit (expense) 383 611 Total reclassification adjustments related to cash flow hedges, net of tax $ (3,069) $ (1,823) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ 103 $ 77 Actuarial gain (loss) Operations and maintenance (2,387) (745) (2,284) (668) Income tax Income tax benefit (expense) 935 (453) Total reclassification adjustments related to defined benefit plans, net of tax $ (1,349) $ (1,121) Total reclassifications $ (4,418) $ (2,944)
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, 2019 $ (15,122) $ (456) $ (15,077) $ (30,655) Other comprehensive income (loss) before reclassifications — (47) (1,062) (1,109) Amounts reclassified from AOCI 2,564 505 1,349 4,418 As of December 31, 2020 $ (12,558) $ 2 $ (14,790) $ (27,346) 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)

Variable Interest Entity (Table

Variable Interest Entity (Tables)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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): 2020 2019 Assets: Current assets $ 13,604 $ 13,350 Property, plant and equipment of variable interest entities, net $ 190,637 $ 193,046 Liabilities: Current liabilities $ 5,318 $ 6,013

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2020
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: 2020 2019 Equity 21% 20% Real estate 3 3 Fixed income 69 71 Cash 3 1 Hedge funds 4 5 Total 100% 100%
Schedule of Employer Contribution to Employee Benefit Plans	Contributions for the years ended December 31 were as follows (in thousands): 2020 2019 Defined Contribution Plan Company retirement contributions $ 10,455 $ 9,714 Company matching contributions $ 15,240 $ 14,558 2020 2019 Defined Benefit Plans Defined Benefit Pension Plan $ 12,700 $ 12,700 Non-Pension Defined Benefit Postretirement Healthcare Plan $ 6,058 $ 7,033 Supplemental Non-Qualified Defined Benefit Plans $ 2,674 $ 2,344
Schedule of Changes in Projected Benefit Obligations	The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, amounts recognized in the Consolidated Balance Sheets, accumulated benefit obligation, and reconciliation of components of the net periodic expense and elements of AOCI (in thousands): Employee Benefit Plan Obligations Defined Benefit Pension Plan Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Change in benefit obligation: Projected benefit obligation at beginning of year $ 485,376 $ 445,381 $ 54,088 $ 43,010 $ 65,277 $ 60,817 Service cost (a) 5,411 5,383 1,579 4,995 2,056 1,815 Interest cost 13,426 17,374 1,099 1,295 1,649 2,247 Actuarial (gain) loss 47,064 56,384 962 7,132 5,804 5,976 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Plan participants’ contributions — — — — 1,510 1,455 Projected benefit obligation at end of year $ 514,008 $ 485,376 $ 55,054 $ 54,088 $ 70,238 $ 65,277 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised.
Schedule of Changes in Fair Value of Plan Assets	Defined Benefit Supplemental Non-qualified Defined Non-pension Defined Benefit Postretirement Healthcare Plan (a) As of December 31, 2020 2019 2020 2019 2020 2019 Change in fair value of plan assets: Beginning fair value of plan assets $ 434,284 $ 390,796 $ — $ — $ 8,305 $ 8,162 Investment income (loss) 64,006 69,934 — — 33 260 Employer contributions 12,700 12,700 2,674 2,344 4,374 5,461 Retiree contributions — — — — 1,511 1,455 Benefits paid (37,269) (39,146) (2,674) (2,344) (6,058) (7,033) Ending fair value of plan assets $ 473,721 $ 434,284 $ — $ — $ 8,165 $ 8,305 ____________________ (a) Assets of VEBA trusts.
Schedule of Amounts Recognized in Balance Sheet	Amounts Recognized in the Consolidated Balance Sheets Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Regulatory assets $ 86,677 $ 88,471 $ — $ — $ 16,102 $ 11,670 Current liabilities $ — $ — $ 1,927 $ 1,420 $ 4,931 $ 4,802 Non-current liabilities $ 40,287 $ 51,093 $ 53,127 $ 51,243 $ 57,142 $ 52,136 Regulatory liabilities $ 3,607 $ 3,524 $ — $ — $ 2,140 $ 4,088
Schedule of Accumulated and Projected Benefit Obligations	Accumulated Benefit Obligation Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Accumulated Benefit Obligation $ 498,815 $ 470,615 $ 54,779 $ 49,241 $ 70,238 $ 65,277
Components of net periodic benefit cost	Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan For the years ended December 31, 2020 2019 2018 2020 2019 2018 2020 2019 2018 Service cost (a) $ 5,411 $ 5,383 $ 6,834 $ 1,579 $ 4,995 $ 1,764 $ 2,056 $ 1,815 $ 2,291 Interest cost 13,426 17,374 15,470 1,099 1,295 1,170 1,649 2,247 2,085 Expected return on assets (22,591) (24,401) (24,741) — — — (182) (230) (315) Net amortization of prior service cost — 26 58 2 2 2 (546) (398) (398) Recognized net actuarial loss (gain) 8,372 3,763 8,632 1,702 535 1,000 20 — 216 Net periodic expense $ 4,618 $ 2,145 $ 6,253 $ 4,382 $ 6,827 $ 3,936 $ 2,997 $ 3,434 $ 3,879 ____________________ (a) For the year ended December 31, 2020, Service Cost for the Supplemental Non-qualified Defined Benefit Plans includes a $1.4 million correction of a prior year overstatement of Projected benefit obligation. Due to the immaterial nature of this correction, the prior year information was not revised.
Schedule of Net Periodic Benefit Cost Not yet Recognized	Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan As of December 31, 2020 2019 2020 2019 2020 2019 Net (gain) loss $ 5,511 $ 5,322 $ 9,323 $ 9,893 $ 100 $ 90 Prior service cost (gain) — — — 2 (144) (230) Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense $ 5,511 $ 5,322 $ 9,323 $ 9,895 $ (44) $ (140)
Schedule of Assumptions Used	Assumptions Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine benefit obligations: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate 2.56 % 3.27 % 4.40 % 2.41 % 3.14 % 4.34 % 2.41 % 3.15 % 4.28 % Rate of increase in compensation levels 3.34 % 3.49 % 3.52 % 5.00 % 5.00 % 5.00 % N/A N/A N/A Defined Benefit Supplemental Non-pension Defined Benefit Postretirement Healthcare Plan Weighted-average assumptions used to determine net periodic benefit cost for plan year: 2020 2019 2018 2020 2019 2018 2020 2019 2018 Discount rate (a) 3.27 % 4.40 % 3.71 % 3.14 % 4.34 % 3.67 % 3.15 % 4.28 % 3.60 % Expected long-term rate of return on assets (b) 5.25 % 6.00 % 6.25 % N/A N/A N/A 2.35 % 3.00 % 3.93 % Rate of increase in compensation levels 3.49 % 3.52 % 3.43 % 5.00 % 5.00 % 5.00 % N/A N/A N/A _____________________________ (a) The estimated discount rate for the Defined Benefit Pension Plan is 2.56% for the calculation of the 2021 net periodic pension costs. (b) The expected rate of return on plan assets is 4.50% for the calculation of the 2021 net periodic pension cost.
Schedule of Health Care Cost Trend Rates	The healthcare benefit obligation at December 31 was determined as follows: 2020 2019 Trend Rate - Medical Pre-65 for next year - All Plans 6.10% 6.40% 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% 4.92% Post-65 Ultimate trend rate - Black Hills Corp 4.50% 4.50% Trend Year 2029 2028
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 2021 $ 25,842 $ 1,927 $ 6,108 2022 $ 26,658 $ 1,968 $ 5,965 2023 $ 27,581 $ 2,033 $ 5,725 2024 $ 28,284 $ 2,231 $ 5,532 2025 $ 29,062 $ 2,690 $ 5,244 2026-2030 $ 144,273 $ 13,117 $ 22,872
Pension Plan
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, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments Common Collective Trust - Cash and Cash Equivalents $ — $ 16,810 $ — $ 16,810 $ — $ 16,810 Common Collective Trust - Equity — 100,311 — 100,311 — 100,311 Common Collective Trust - Fixed Income — 324,845 — 324,845 — 324,845 Common Collective Trust - Real Estate — — — — 14,301 14,301 Hedge Funds — — — — 17,454 17,454 Total investments measured at fair value $ — $ 441,966 $ — $ 441,966 $ 31,755 $ 473,721 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 _____________ (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, 2020 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments Cash and Cash Equivalents $ 8,165 $ — $ — $ 8,165 $ 8,165 Total investments measured at fair value $ 8,165 $ — $ — $ 8,165 $ 8,165 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

Share-based Compensation Plans

Share-based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
Schedule of Employee Service Share-based Compensation, Allocation of Recognized Period Costs	Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31 (in thousands): 2020 2019 2018 Stock-based compensation expense $ 5,373 $ 12,095 $ 12,390
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, 2020, was as follows: Restricted Stock Weighted-Average Grant Date Fair Value (in thousands) Balance at January 1, 2020 192 $ 65.66 Granted 116 69.49 Vested (90) 63.30 Forfeited (22) 65.30 Balance at December 31, 2020 196 $ 69.05 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) 2020 $ 69.49 $ 6,722 2019 $ 73.66 $ 8,438 2018 $ 57.31 $ 6,776
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	Outstanding performance periods at December 31, 2020 were as follows (shares in thousands): Possible Payout Range of Target Grant Date Performance Period Target Grant of Shares Minimum Maximum January 1, 2020 January 1, 2020 - December 31, 2022 36 0% 200% January 1, 2019 January 1, 2019 - December 31, 2021 36 0% 200% January 1, 2018 January 1, 2018 - December 31, 2020 49 0% 200% A summary of the status of the Performance Share Plan at December 31, 2020 was as follows: Equity Portion Liability Portion Weighted-Average Grant Date Fair Value (a) Weighted-Average Fair Value at Shares Shares December 31, 2020 (in thousands) (in thousands) Performance Shares balance at beginning of period 67 $ 64.32 67 Granted 19 81.42 19 Forfeited (2) 73.89 (2) Vested (23) 63.52 (23) Performance Shares balance at end of period 61 $ 69.71 61 $ 52.42 _____________________ (a) The grant date fair values for the performance shares granted in 2020, 2019 and 2018 were determined by Monte Carlo simulation using a blended volatility of 18%, 21% and 21%, respectively, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: Weighted Average Grant Date Fair Value December 31, 2020 $ 81.42 December 31, 2019 $ 68.72 December 31, 2018 $ 61.82
Performance Plan Payouts	Performance plan payouts have been as follows (in thousands): Performance Period Year Paid Stock Issued Cash Paid Total Intrinsic Value January 1, 2017 to December 31, 2019 2020 14 $ 1,100 $ 2,199 January 1, 2016 to December 31, 2018 2019 44 $ 2,860 $ 5,720 January 1, 2015 to December 31, 2017 2018 — — —

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
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): 2020 2019 2018 Current: Federal $ (6,020) $ (8,578) $ 325 State 847 138 247 Current income tax expense (benefit) (5,173) (8,440) 572 Deferred: Federal 35,672 34,551 (25,022) State 2,419 3,469 783 Deferred income tax expense (benefit) 38,091 38,020 (24,239) Income tax expense (benefit) $ 32,918 $ 29,580 $ (23,667)
Schedule of Effective Income Tax Rate Reconciliation	Effective Tax Rates The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2020 2019 2018 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax (net of federal tax effect) 2.4 1.5 2.3 Non-controlling interest (a) (1.2) (1.2) (1.3) Tax credits (b) (c) (9.2) (3.9) (2.0) Flow-through adjustments (d) (1.6) (2.4) (1.6) Jurisdictional consolidation project (e) — — (28.5) Uncertain Tax Benefits 1.5 — — Valuation Allowance 0.7 — — Other tax differences 0.6 (1.6) (0.1) TCJA corporate rate reduction (f) — — 1.6 Amortization of excess deferred income tax expense (g) (2.3) (1.2) (0.7) Effective Tax Rate 11.9 % 12.2 % (9.3) % _________________________ (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) The current year increase of PTCs reflect full year production of two wind facilities that were acquired/ placed into service during 2019; Top of Iowa purchased February 2019 and Busch Ranch II with an in-service date of November 2019. Additionally, in November 2020, the Corriedale qualifying wind facility was placed in service. (c) In 2020, the Company completed a research and development study which encompassed tax years from 2013 to 2019. (d) 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. (e) In 2018, the Company restructured certain legal entities from earlier acquisitions, which resulted in additional deferred income tax assets of $73 million, related to goodwill that is amortizable for tax purposes, and deferred tax benefits of $73 million. (f) On December 22, 2017, the TCJA was signed into law reducing the federal corporate rate from 35% to 21% effective January 1, 2018. 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. (g) Primarily TCJA - see above.
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): 2020 2019 Deferred tax assets: Regulatory liabilities $ 90,535 $ 89,754 State tax credits 23,339 23,261 Federal NOL 96,155 120,624 State NOL 9,914 13,537 Partnership 15,601 14,030 Credit Carryovers 51,445 27,139 Other deferred tax assets 40,143 33,395 Less: Valuation allowance (13,943) (12,063) Total deferred tax assets 313,189 309,677 Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences (551,137) (533,292) Regulatory assets (28,007) (23,586) Goodwill (30,590) (15,875) State deferred tax liability (73,910) (72,911) Other deferred tax liabilities (38,169) (24,732) Total deferred tax liabilities (721,813) (670,396) Net deferred tax liability $ (408,624) $ (360,719)
Summary of Operating Loss Carryforwards	At December 31, 2020, we have federal and state NOL carryforwards that will expire at various dates as follows (in thousands): Amounts Expiration Dates Federal NOL Carryforward $ 378,236 2022 to 2037 Federal NOL Carryforward $ 79,644 No expiration State NOL Carryforward (a) $ 173,867 2021 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, 2018 $ 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 Additions for prior year tax positions 3,788 Reductions for prior year tax positions (1,313) Additions for current year tax positions 1,743 Settlements — Ending balance at December 31, 2020 $ 8,383
Summary of State Tax Carryforwards	State tax credits have been generated and are available to offset future state income taxes. At December 31, 2020, 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 $ 278 No expiration

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2020
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, 2020 2019 Electric Utilities $ 3,120,928 $ 2,900,983 Gas Utilities 4,376,204 4,032,339 Power Generation 404,220 417,715 Mining 77,085 77,175 Corporate and Other 110,349 130,245 Total assets $ 8,088,786 $ 7,558,457 Capital Expenditures (a) for the years ended December 31, 2020 2019 Electric Utilities $ 271,104 $ 222,911 Gas Utilities 449,209 512,366 Power Generation 9,329 85,346 Mining 8,250 8,430 Corporate and Other 17,500 20,702 Total capital expenditures $ 755,392 $ 849,755 _________________ (a) Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows . Property, Plant and Equipment as of December 31, 2020 2019 Electric Utilities $ 3,248,480 $ 3,059,135 Gas Utilities 3,312,613 2,981,498 Power Generation 534,803 534,518 Mining 187,540 180,473 Corporate and Other 22,094 29,055 Total property, plant and equipment $ 7,305,530 $ 6,784,679
Segment information included in Consolidated Statements of Income	Consolidating Income Statement Year ended December 31, 2020 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations Total Revenue - Contracts with customers $ 687,929 $ 959,696 $ 6,090 $ 27,089 $ — $ — $ 1,680,804 Other revenues 2,201 9,962 1,566 2,408 — — 16,137 690,130 969,658 7,656 29,497 — — 1,696,941 Inter-company operating revenue - Contracts with customers 23,914 4,724 97,169 31,478 167 (157,452) — Other revenues — 288 222 100 352,976 (353,586) — 23,914 5,012 97,391 31,578 353,143 (511,038) — Total revenue 714,044 974,670 105,047 61,075 353,143 (511,038) 1,696,941 Fuel, purchased power and cost of natural gas sold 267,045 354,645 8,993 — 83 (138,362) 492,404 Operations and maintenance, including taxes 196,794 303,577 33,695 39,033 284,501 (305,823) 551,777 Depreciation, depletion and amortization 94,150 100,559 20,247 9,235 25,150 (24,884) 224,457 Adjusted operating income (loss) $ 156,055 $ 215,889 $ 42,112 $ 12,807 $ 43,409 $ (41,969) $ 428,303 Interest expense, net (143,470) Impairment of investment (6,859) Other income (expense), net (2,293) Income tax benefit (expense) (32,918) Income from continuing operations 242,763 (Loss) from discontinued operations, net of tax — Net income 242,763 Net income attributable to noncontrolling interest (15,155) Net income available for common stock $ 227,608 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, including taxes 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 (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 Consolidating Income Statement Year ended December 31, 2018 Electric Utilities Gas Utilities Power Generation Mining Corporate Inter-Company Eliminations 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, including taxes 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) 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

Business Description And Sign_4

Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounts Receivable [Line Items]
Allowance for credit losses	$ (7,003)	$ (2,444)	$ (3,209)	$ (3,081)
Accounts receivable, net	265,961	255,805
Corporate, Non-Segment
Accounts Receivable [Line Items]
Allowance for credit losses	0	(169)
Accounts receivable, net	1,118	1,102
Electric Utilities
Accounts Receivable [Line Items]
Allowance for credit losses	(1,269)	(592)
Accounts receivable, net	77,487	74,722
Gas Utilities
Accounts Receivable [Line Items]
Allowance for credit losses	(5,734)	(1,683)
Accounts receivable, net	183,008	175,540
Power Generation
Accounts Receivable [Line Items]
Allowance for credit losses	0	0
Accounts receivable, net	1,837	2,164
Mining
Accounts Receivable [Line Items]
Allowance for credit losses	0	0
Accounts receivable, net	2,511	2,277
Billed Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	146,899	144,747
Billed Revenues | Corporate, Non-Segment
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,118	1,271
Billed Revenues | Electric Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	45,841	41,428
Billed Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	95,592	97,607
Billed Revenues | Power Generation
Accounts Receivable [Line Items]
Accounts Receivable, Trade	1,837	2,164
Billed Revenues | Mining
Accounts Receivable [Line Items]
Accounts Receivable, Trade	2,511	2,277
Unbilled Revenues
Accounts Receivable [Line Items]
Accounts Receivable, Trade	126,065	113,502
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	32,915	33,886
Unbilled Revenues | Gas Utilities
Accounts Receivable [Line Items]
Accounts Receivable, Trade	93,150	79,616
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_5

Business Description And Significant Accounting Policies: Allowance for Doubtful Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Accounts Receivable, Allowance for Credit Loss, Current	$ 2,444	$ 3,209	$ 3,081
Additions Charged to Costs and Expenses	8,927	5,795	6,859
Recoveries and Other Additions	4,728	3,942	4,092
Write-offs and Other Deductions	(9,096)	(10,502)	(10,823)
Accounts Receivable, Allowance for Credit Loss, Current	7,003	$ 2,444	$ 3,209
Potential economic impact of the COVID-19 pandemic
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Additions Charged to Costs and Expenses	3,300
Accounts Receivable, Allowance for Credit Loss, Current	$ 3,300

Business Description And Sign_6

Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Inventory, Net [Abstract]
Materials and supplies	$ 85,250	$ 82,809
Fuel	1,531	2,425
Natural gas in storage	30,619	31,938
Total materials, supplies and fuel	$ 117,400	$ 117,172

Business Description And Sign_7

Business Description And Significant Accounting Policies: Investments (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Sep. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	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	$ 20,000	$ 6,900	$ 6,859	$ 19,741	$ 0
Investments			15,810	21,929
Balance Sheet Reclassification from Investments to Other Assets, Non-current				22,000
Investment in privately held oil and gas company
Investment [Line Items]
Investments			1,500	8,359
Cash surrender value of life insurance contracts
Investment [Line Items]
Investments			13,628	13,056
Other investments
Investment [Line Items]
Investments			$ 682	$ 514

Business Description And Sign_8

Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Line Items]
Goodwill	$ 1,299,454	$ 1,299,454
Electric Utilities
Goodwill [Line Items]
Goodwill	248,479
Gas Utilities
Goodwill [Line Items]
Goodwill	1,042,210
Power Generation
Goodwill [Line Items]
Goodwill	$ 8,765

Business Description And Sign_9

Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 13,266	$ 14,337	$ 7,559
Intangible assets, additions	0	0	7,602
Intangible assets, amortization expense	(1,322)	(1,071)	(824)
Intangible assets, net, ending balance	11,944	$ 13,266	$ 14,337
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Future Amortization Expense, Year One	1,300
Future Amortization Expense, Year Two	1,300
Future Amortization Expense, Year Three	1,300
Future Amortization Expense, Year Four	1,300
Future Amortization Expense, Year Five	$ 1,300
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 Sig_10

Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued employee compensation, benefits and withholdings	$ 77,806	$ 62,837
Accrued property taxes	47,105	44,547
Customer deposits and prepayments	52,185	54,728
Accrued interest	31,520	31,868
Other (none of which is individually significant)	34,996	32,787
Total accrued liabilities	$ 243,612	$ 226,767

Business Description And Sig_11

Business Description And Significant Accounting Policies: Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Regulatory assets	$ 278,258	$ 271,344
Regulatory liabilities	$ 532,720	$ 536,652

Business Description And Sig_12

Business Description And Significant Accounting Policies: Earnings per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income available for common stock	$ 227,608	$ 199,310	$ 258,442
Weighted average shares - Basic (in shares)	62,378	60,662	54,420
Dilutive effect of:
Equity Units (in shares)	0	0	898
Equity compensation (in shares)	61	136	168
Weighted average shares - diluted (in shares)	62,439	60,798	55,486
Total earnings (loss) per share of common stock, Diluted (usd per share)	$ 3.65	$ 3.28	$ 4.66

Business Description And Sig_13

Business Description And Significant Accounting Policies: Anti-dilutive shares (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Antidilutive Securities Excluded from Computation of Earnings Per Share
Outstanding securities not included in the computation of diluted earnings per share (in shares)	60	1	16
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)	60	1	16

Business Description And Sig_14

Business Description And Significant Accounting Policies: Recently Adopted Accounting Standards (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Jan. 01, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ 2,662,647		$ 2,464,069	$ 2,287,423	$ 1,820,206
Cumulative Effect, Period of Adoption, Adjustment
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest	$ (207)	$ 200	$ 3,390

Regulatory Matters_ Regulatory

Regulatory Matters: Regulatory Matters (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Regulatory assets	$ 278,258	$ 271,344
Regulatory assets, current	(51,676)	(43,282)
Regulatory assets, non-current	226,582	228,062
Regulatory liabilities	532,720	536,652
Regulatory liabilities, current	(25,061)	(33,507)
Regulatory liabilities, non-current	507,659	503,145
Deferred energy and gas costs
Regulatory liabilities	13,253	17,278
Employee benefit plan costs and related deferred taxes
Regulatory liabilities	40,256	43,349
Cost of removal
Regulatory liabilities	172,902	166,727
Excess deferred income taxes
Regulatory liabilities	285,259	285,438
Other regulatory liabilities
Regulatory liabilities	21,050	23,860
Deferred energy and gas costs
Regulatory assets	39,035	34,088
Deferred gas cost adjustments
Regulatory assets	3,200	1,540
Gas price derivatives
Regulatory assets	2,226	3,328
Deferred taxes on AFUDC
Regulatory assets	7,491	7,790
Employee benefit plan costs and related deferred taxes
Regulatory assets	116,598	115,900
Environmental
Regulatory assets	1,413	1,454
Loss on reacquired debt
Regulatory assets	22,864	24,777
Renewable energy standard adjustment
Regulatory assets	0	1,622
Deferred taxes on flow through accounting
Regulatory assets	47,515	41,220
Decommissioning costs
Regulatory assets	8,988	10,670
Gas supply contract termination
Regulatory assets	2,524	8,485
Other regulatory assets
Regulatory assets	$ 26,404	$ 20,470

Regulatory Matters_ Gas Price D

Regulatory Matters: Gas Price Derivatives (Details)	12 Months Ended
	Dec. 31, 2020
Maximum
Derivative, Term of Contract	2 years

Regulatory Matters_ Decommissio

Regulatory Matters: Decommissioning Costs (Details)	12 Months Ended
	Dec. 31, 2020
Decommissioning costs
Public Utilities, General Disclosures [Line Items]
Regulatory Asset, Amortization Period	3 years

Regulatory Matters_ Gas Supply

Regulatory Matters: Gas Supply Contract Termination (Details)	12 Months Ended
	Dec. 31, 2020$ / Btu
Gas supply contract termination
Regulatory Asset, Amortization Period	5 years
Minimum
Oil and Gas Delivery Commitments and Contracts, Fixed Price	6
Maximum
Oil and Gas Delivery Commitments and Contracts, Fixed Price	8

Regulatory Matters_ Regulator_2

Regulatory Matters: Regulatory Activity (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Jan. 26, 2021	Dec. 30, 2020
Benefit from Relieved TCJA Related Liabilities	$ 4,000
Colorado Public Utilities Commission (CPUC) | Black Hills Energy - Colorado Electric
Settlement of plan to provide TCJA-related customer billing credits to its customers			$ 9,300
Nebraska Public Service Commission (NPSC) | Black Hills Energy - Nebraska Gas | Subsequent Event
Settlement of plan to provide TCJA-related customer billing credits to its customers		$ 2,900

Regulatory Matters_ Electric Ut

Regulatory Matters: Electric Utilities Regulatory Activity (Details) $ in Thousands	Jan. 01, 2022	Jan. 01, 2020USD ($)	Dec. 31, 2020USD ($)	Oct. 15, 2020MW
Black Hills Energy, 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			$ 27,000
Capital Addition Requirements by the FERC Joint-Access Transmission Tariff		$ 33,000
Black Hills Energy, 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
Black Hills Energy, 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
Black Hills Wyoming and Wyoming Electric | Federal Energy Regulatory Commission (FERC)
Public Utilities, General Disclosures [Line Items]
Number of Megawatts Capacity Purchased | MW				60
Black Hills Wyoming and Wyoming Electric | Federal Energy Regulatory Commission (FERC) | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Public Utilities Term of Power Purchase Agreement	11 years

Regulatory Matters_ Gas Utiliti

Regulatory Matters: Gas Utilities Regulatory Activity (Details) $ in Thousands	Mar. 01, 2021	Jan. 26, 2021USD ($)mi	Sep. 11, 2020USD ($)mi	May 19, 2020USD ($)	Dec. 11, 2019USD ($)utility	Feb. 01, 2019USD ($)gas_distribution_territory
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Gas Distribution Territories Consolidating | gas_distribution_territory						2
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 - Length of Natural Gas Pipeline to Receive Infrastructure Investments | mi			7,000
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 13,500			$ 2,500
Public Utilities, Requested Equity Capital Structure, Percentage			50.00%
Public Utilities, Requested Debt Capital Structure, Percentage			50.00%
Public Utilities, Requested Return on Equity, Percentage			9.95%
Public Utilities, Term Extension of System Saftey and Integrity Rider			5 years
Public Utilities, Approved Rate Increase (Decrease), Amount				$ (600)
Public Utilities, Approved Return on Equity, Percentage				9.20%
Colorado Public Utilities Commission (CPUC) | Black Hills Energy, Rocky Mountain Natural Gas | Rate Review Filed with the Regulatory Agency
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 33,000
Wyoming Public Service Commission (WPSC) | Black Hills Energy, Wyoming Gas
Public Utilities, General Disclosures [Line Items]
Public Utilities, Number of Gas Distribution Territories Consolidating | utility					4
Public Utilities, Approved Rate Increase (Decrease), Amount					$ 13,000
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%
Nebraska Publc Service Commission (NPSC) | Black Hills Energy - Nebraska Gas | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Public Utilities, Term Extension of System Saftey and Integrity Rider	5 years
Public Utilities, Approved Return on Equity, Percentage	950.00%
Public Utilities, Approved Equity Capital Structure, Percentage	50.00%
Nebraska Publc Service Commission (NPSC) | Black Hills Energy - Nebraska Gas | Rate Review Filed with the Regulatory Agency | Subsequent Event
Public Utilities, General Disclosures [Line Items]
Public Utilities - Length of Natural Gas Pipeline to Receive Infrastructure Investments | mi		13,000
Public Utilities, Approved Rate Increase (Decrease), Amount		$ 6,500
Public Utilities Amount of System Safety and Integrety Rider Moved to Base Rates		$ 4,600

Commitment, Contingencies And_3

Commitment, Contingencies And Guarentees: Power Purchase and Transmission Services Agreements (Details) $ in Thousands	Dec. 31, 2022	Dec. 31, 2020USD ($)MW	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jun. 26, 2019MW
PacifiCorp Transmission
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $		$ 1,776
Colorado Electric | Wind
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW		60
Colorado Electric | Coal
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW		25
Black Hills Energy, South Dakota Electric
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW		50
Black Hills Energy, South Dakota Electric | Wind
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW		12
Black Hills Energy, South Dakota Electric | Coal
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW		50
Black Hills Energy, South Dakota Electric | Solar
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW		80
Wyoming Electric | Wind
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW		30
Fall River Solar | Black Hills Energy, South Dakota Electric | Subsequent Event
Long-term Purchase Commitment [Line Items]
Purchase Power Agreement Set to Expire after a Certain Number of Years Following Completion of the Facility	20 years
Platte River Power Authority - Unit Contingent Energy | Wind
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $		$ 2,791	$ 0	$ 0
Platte River Power Authority - Unit Contingent Energy | Coal
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $		4,524	1,802	0
PacifiCorp Purchase Power Agreement | Coal
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $		5,897	7,477	13,681
PacifiCorp Transmission
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $			1,741	1,742
Platte River Power Authority Wind Power Agreement
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased | MW					60
Platte River Power Authority Wind Power Agreement | Wind
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $		715	688	223
Happy Jack Wind Purchase Power Agreement | Wind
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $		$ 4,531	3,936	3,884
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 | Wind
Long-term Purchase Commitment [Line Items]
Cost of Purchased Power | $		$ 6,203	$ 5,366	$ 5,376
Silver Sage Wind Power Purchase 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		67.00%

Commitment, Contingencies And_4

Commitment, Contingencies And Guarentees: Power Purchase Agreement - Related Party (Details) - MW	Jan. 01, 2022	Dec. 31, 2020	Oct. 15, 2020
Federal Energy Regulatory Commission (FERC) | Black Hills Wyoming and Wyoming Electric
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract			60
Number of Megawatts Capacity Purchased			60
Federal Energy Regulatory Commission (FERC) | Black Hills Wyoming and Wyoming Electric | Subsequent Event
Long-term Purchase Commitment [Line Items]
Public Utilities Term of Power Purchase Agreement	11 years
Black Hills Wyoming and Wyoming Electric
Long-term Purchase Commitment [Line Items]
Megawatts Sold Under Long-Term Contract		60
Black Hills Electric Generation and Colorado Electric | Busch Ranch I Wind Farm
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased		14.5
Colorado Electric and Black Hills Colorado IPP
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased		200

Commitment, Contingencies And_5

Commitment, Contingencies And Guarentees: Purchase Commitment (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)MMBTU	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Maximum
Long-term Purchase Commitment [Line Items]
We maintain natural gas supply contracts with several vendors that generally cover a period up to:	1 year
Natural Gas, Distribution
Long-term Purchase Commitment [Line Items]
Natural Gas Purchases | $	$ 25	$ 6.7	$ 27
Northern Natural Gas - Ventura
Long-term Purchase Commitment [Line Items]
2021	3,650,000
2022	1,810,000
2023	1,840,000
2024	1,820,000
2025	0
Thereafter	0
Northwest Pipeline - Wyoming
Long-term Purchase Commitment [Line Items]
2021	1,510,000
2022	1,510,000
2023	1,510,000
2024	910,000
2025	0
Thereafter	0
ONEOK - Oklahoma
Long-term Purchase Commitment [Line Items]
2021	5,475,000
2022	5,475,000
2023	5,475,000
2024	5,490,000
2025	4,560,000
Thereafter	0
Southern Star Central Gas Pipeline
Long-term Purchase Commitment [Line Items]
2021	113,130
2022	0
2023	0
2024	0
2025	0
Thereafter	0
Panhandle Eastern Pipe Line
Long-term Purchase Commitment [Line Items]
2021	4,680
2022	0
2023	0
2024	0
2025	0
Thereafter	0
Gas Utilities
Long-term Purchase Commitment [Line Items]
Term of Evergreen Contracts	60 days

Commitment, Contingencies And_6

Commitment, Contingencies And Guarentees: Unconditional Purchase Obligations (Details) $ in Thousands	Dec. 31, 2020USD ($)
Power purchase and transmission services agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2021	$ 24,452
2022	11,678
2023	11,678
2024	2,738
2025	0
Thereafter	0
Natural gas transportation and storage agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2021	116,563
2022	121,819
2023	100,282
2024	67,089
2025	50,709
Thereafter	$ 167,100

Commitment, Contingencies And_7

Commitment, Contingencies And Guarentees: Power Sales Agreements (Details) - MW	12 Months Ended
	Dec. 31, 2020	Jul. 01, 2020	Jun. 26, 2019	Sep. 03, 2014
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]
Megawatts Sold Under Long-Term Contract	20
2020-2022	15
2022-2023	15
2023-2028	10
Purchase Power Contract, MEAN, for up to 20 Megawatts | Contingent Capacity Amounts on Wygen III
Long-term Purchase Commitment [Line Items]
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]
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
City of Colorado Springs | Colorado Electric
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased		60
Platte River Power Authority Wind Power Agreement
Long-term Purchase Commitment [Line Items]
Number of Megawatts Capacity Purchased			60
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

Commitment, Contingencies And_8

Commitment, Contingencies And Guarentees: Reclamation Liability (Details) $ in Millions	Dec. 31, 2020USD ($)
Electric Utilities
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies - Pueblo Airport Generation Site	$ 4.1

Commitment, Contingencies And_9

Commitment, Contingencies And Guarentees: Manufactured Gas Processing (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Loss Contingencies [Line Items]
Regulatory assets	$ 278,258	$ 271,344
Environmental
Loss Contingencies [Line Items]
Regulatory assets	1,413	$ 1,454
Manufactured Gas Plant | Gas Utilities
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1,200
Manufactured Gas Plant | Gas Utilities | Black Hills Energy - Iowa Gas
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	2,600
Manufactured Gas Plant | Gas Utilities | Black Hills Energy - Nebraska Gas
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	600
Manufactured Gas Plant | Gas Utilities | Environmental
Loss Contingencies [Line Items]
Regulatory assets	$ 1,400

Commitment, Contingencies An_10

Commitment, Contingencies And Guarentees: Guarantees (Details) $ in Thousands	Dec. 31, 2020USD ($)
Surety Bond
Guarantor Obligations [Line Items]
Guarantor, Maximum Exposure	$ 53,769

Revenue_ Disaggregation of Reve

Revenue: Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Revenue from contracts with customers	$ 1,680,804	$ 1,726,392	$ 1,748,542
Revenue	1,696,941	1,734,900	1,754,268
Services transferred at a point in time
Revenue from contracts with customers	27,089	27,180	33,609
Services transferred over time
Revenue from contracts with customers	1,653,715	1,699,212	1,714,933
Other revenues
Revenue	16,137	8,508	5,726
Intercompany Eliminations
Revenue from contracts with customers	(157,285)	(149,205)	(141,428)
Revenue	(157,895)	(150,769)	(142,974)
Intercompany Eliminations | Services transferred at a point in time
Revenue from contracts with customers	(31,478)	(32,053)	(32,194)
Intercompany Eliminations | Services transferred over time
Revenue from contracts with customers	(125,807)	(117,152)	(109,234)
Intercompany Eliminations | Other revenues
Revenue	(610)	(1,564)	(1,546)
Electric Utilities
Revenue from contracts with customers	711,843	707,561	709,024
Revenue	714,044	712,752	711,451
Electric Utilities | Services transferred at a point in time
Revenue from contracts with customers	0	0	0
Electric Utilities | Services transferred over time
Revenue from contracts with customers	711,843	707,561	709,024
Electric Utilities | Other revenues
Revenue	2,201	5,191	2,427
Gas Utilities
Revenue from contracts with customers	964,421	1,009,646	1,024,352
Revenue	974,670	1,010,030	1,025,307
Gas Utilities | Services transferred at a point in time
Revenue from contracts with customers	0	0	0
Gas Utilities | Services transferred over time
Revenue from contracts with customers	964,421	1,009,646	1,024,352
Gas Utilities | Other revenues
Revenue	10,249	384	955
Power Generation
Revenue from contracts with customers	103,258	99,157	90,791
Revenue	105,047	101,258	92,451
Power Generation | Services transferred at a point in time
Revenue from contracts with customers	0	0	0
Power Generation | Services transferred over time
Revenue from contracts with customers	103,258	99,157	90,791
Power Generation | Other revenues
Revenue	1,789	2,101	1,660
Mining
Revenue from contracts with customers	58,567	59,233	65,803
Revenue	61,075	61,629	68,033
Mining | Services transferred at a point in time
Revenue from contracts with customers	58,567	59,233	65,803
Mining | Services transferred over time
Revenue from contracts with customers	0	0	0
Mining | Other revenues
Revenue	2,508	2,396	2,230
Retail
Revenue from contracts with customers	1,403,732	1,450,776	1,461,317
Retail | Intercompany Eliminations
Revenue from contracts with customers	(31,478)	(32,053)	(32,194)
Retail | Electric Utilities
Revenue from contracts with customers	610,721	605,756	594,329
Retail | Gas Utilities
Revenue from contracts with customers	765,922	817,840	833,379
Retail | Power Generation
Revenue from contracts with customers	0	0	0
Retail | Mining
Revenue from contracts with customers	58,567	59,233	65,803
Transportation
Revenue from contracts with customers	154,055	142,348	139,357
Transportation | Intercompany Eliminations
Revenue from contracts with customers	(526)	(1,042)	(1,348)
Transportation | Electric Utilities
Revenue from contracts with customers	0	0	0
Transportation | Gas Utilities
Revenue from contracts with customers	154,581	143,390	140,705
Transportation | Power Generation
Revenue from contracts with customers	0	0	0
Transportation | Mining
Revenue from contracts with customers	0	0	0
Wholesale
Revenue from contracts with customers	23,937	28,464	39,521
Wholesale | Intercompany Eliminations
Revenue from contracts with customers	(97,169)	(91,577)	(84,957)
Wholesale | Electric Utilities
Revenue from contracts with customers	17,848	20,884	33,687
Wholesale | Gas Utilities
Revenue from contracts with customers	0	0	0
Wholesale | Power Generation
Revenue from contracts with customers	103,258	99,157	90,791
Wholesale | Mining
Revenue from contracts with customers	0	0	0
Market - off-system sales
Revenue from contracts with customers	15,772	16,772	17,563
Market - off-system sales | Intercompany Eliminations
Revenue from contracts with customers	(8,797)	(7,736)	(8,102)
Market - off-system sales | Electric Utilities
Revenue from contracts with customers	24,309	23,817	24,799
Market - off-system sales | Gas Utilities
Revenue from contracts with customers	260	691	866
Market - off-system sales | Power Generation
Revenue from contracts with customers	0	0	0
Market - off-system sales | Mining
Revenue from contracts with customers	0	0	0
Transmission/Other
Revenue from contracts with customers	83,308	88,032	90,784
Transmission/Other | Intercompany Eliminations
Revenue from contracts with customers	(19,315)	(16,797)	(14,827)
Transmission/Other | Electric Utilities
Revenue from contracts with customers	58,965	57,104	56,209
Transmission/Other | Gas Utilities
Revenue from contracts with customers	43,658	47,725	49,402
Transmission/Other | Power Generation
Revenue from contracts with customers	0	0	0
Transmission/Other | Mining
Revenue from contracts with customers	$ 0	$ 0	$ 0

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 7,305,530	$ 6,784,679
Less accumulated depreciation and depletion	(1,285,816)	(1,281,493)
Property, plant and equipment of variable interest entities, net	6,019,714	5,503,186
Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	22,094	29,055
Less accumulated depreciation and depletion	(1,144)	(964)
Property, plant and equipment of variable interest entities, net	20,950	28,091
Property, Plant and Equipment	5,692	5,721
Construction in progress, gross	$ 16,402	$ 23,334
Weighted Average | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	10 years	10 years
Minimum | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	10 years	3 years
Maximum | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life	22 years	30 years
Electric Utilities
Property, Plant and Equipment [Line Items]
Total plant in service before construction work in progress	$ 3,159,078	$ 2,956,867
Construction work in progress	89,402	102,268
Property, plant and equipment	3,248,480	3,059,135
Less accumulated depreciation and depletion	(666,669)	(670,861)
Property, plant and equipment of variable interest entities, net	$ 2,581,811	2,388,274
Depreciation, depletion and amortization, remaining amortization period	10 years
Electric Utilities | Production, Electric
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 1,417,951	$ 1,348,049
Electric Utilities | Production, Electric | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 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	$ 517,794	$ 483,640
Electric Utilities | Electric transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	49 years	51 years
Electric Utilities | Electric transmission | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	44 years
Electric Utilities | Electric transmission | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	51 years
Electric Utilities | Electric distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 959,453	$ 861,042
Electric Utilities | Electric distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	46 years	47 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	48 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	$ 259,010	$ 259,266
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	29 years
Gas Utilities
Property, Plant and Equipment [Line Items]
Total plant in service before construction work in progress	$ 3,245,384	$ 2,918,418
Construction work in progress	67,229	63,080
Property, plant and equipment	3,312,613	2,981,498
Less accumulated depreciation and depletion	(323,679)	(336,721)
Property, plant and equipment of variable interest entities, net	2,988,934	2,644,777
Gas Utilities | Production, Gas
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 15,603	$ 13,000
Gas Utilities | Production, Gas | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	40 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	46 years
Gas Utilities | Gas transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 578,278	$ 516,172
Gas Utilities | Gas transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	54 years	50 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	71 years
Gas Utilities | Gas distribution
Property, Plant and Equipment [Line Items]
Distribution	$ 2,115,082	$ 1,857,233
Gas Utilities | Gas distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	53 years	43 years
Gas Utilities | Gas distribution | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	45 years
Gas Utilities | Gas distribution | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	59 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	$ 39,184	$ 44,443
Gas Utilities | Gas, Storage
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 55,481	$ 46,977
Gas Utilities | Gas, Storage | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	38 years	31 years
Gas Utilities | Gas, Storage | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	24 years
Gas Utilities | Gas, Storage | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	52 years
Gas Utilities | General
Property, Plant and Equipment [Line Items]
General	$ 438,217	$ 437,054
Gas Utilities | General | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	19 years	20 years
Gas Utilities | General | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	12 years
Gas Utilities | General | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	23 years
Power Generation
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 534,803	$ 534,518
Less accumulated depreciation and depletion	(167,787)	(154,362)
Property, plant and equipment of variable interest entities, net	367,016	380,156
Property, Plant and Equipment	529,927	532,397
Construction in progress, gross	$ 4,876	$ 2,121
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	$ 187,540	$ 180,473
Less accumulated depreciation and depletion	(126,537)	(118,585)
Property, plant and equipment of variable interest entities, net	61,003	61,888
Property, Plant and Equipment	186,552	179,198
Construction in progress, gross	$ 988	$ 1,275
Mining | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	14 years	13 years
Mining | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life	2 years	2 years
Mining | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life	59 years	59 years

Jointly Owned Facilities (Detai

Jointly Owned Facilities (Details) $ in Thousands	Dec. 31, 2020USD ($)
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	2,249
Less Accumulated Depreciation	(67,762)
Plant Net of Accumulated Depreciation	$ 50,561
Transmission Tie | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	35.00%
Plant in Service	$ 26,176
Construction Work in Progress	509
Less Accumulated Depreciation	(7,103)
Plant Net of Accumulated Depreciation	$ 19,582
Wygen III Generating Facility | Electric Utilities
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	52.00%
Plant in Service	$ 142,739
Construction Work in Progress	582
Less Accumulated Depreciation	(24,783)
Plant Net of Accumulated Depreciation	$ 118,538
Wygen I Generating Facility | Power Generation
Jointly Owned Utility Plant Interests [Line Items]
Ownership Share Percentage	76.50%
Plant in Service	$ 114,975
Construction Work in Progress	318
Less Accumulated Depreciation	(49,459)
Plant Net of Accumulated Depreciation	$ 65,834

Jointly Owned Facilities - Rela

Jointly Owned Facilities - Related Party (Details)	Dec. 31, 2020MW
Black Hills Energy, Wyoming Electric | Cheyenne Prairie, Simple-Cycle Combustion Turbine
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity	37
Cheyenne Prairie | Black Hills Energy, Wyoming Electric | Cheyenne Prairie, Combined Cycle
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity	42.4
Cheyenne Prairie | Black Hills Energy, South Dakota Electric | Cheyenne Prairie, Combined Cycle
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity	58
Cheyenne Prairie | South Dakota Electric and Wyoming Electric | Cheyenne Prairie, Combined Cycle
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity	100.4
Corriedale Wind Project | Black Hills Energy, Wyoming Electric
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity	20
Corriedale Wind Project | Black Hills Energy, South Dakota Electric
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity	32.5
Corriedale Wind Project | South Dakota Electric and Wyoming Electric
Jointly Owned Utility Plant Interests [Line Items]
Utility Plant, Megawatt Capacity	52.5
Electric Utilities | Busch Ranch I Wind Farm
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%
Power Generation | Busch Ranch I Wind Farm
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share	50.00%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 64,205	$ 56,800
Liabilities Incurred	5,999	3,445
Liabilities Settled	(317)	(380)
Accretion	2,769	2,741
Revisions to Prior Estimates	(1,225)	1,599
Ending Balance	71,431	64,205
Electric Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	9,329	6,258
Liabilities Incurred	1,217	0
Liabilities Settled	0	0
Accretion	407	385
Revisions to Prior Estimates	0	2,686
Ending Balance	10,953	9,329
Gas Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	36,085	34,627
Liabilities Incurred	4,782	0
Liabilities Settled	(132)	0
Accretion	1,539	1,458
Revisions to Prior Estimates	0	0
Ending Balance	42,274	36,085
Power Generation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	4,739	300
Liabilities Incurred	0	3,445
Liabilities Settled	0	0
Accretion	206	158
Revisions to Prior Estimates	0	836
Ending Balance	4,945	4,739
Mining
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	14,052	15,615
Liabilities Incurred	0	0
Liabilities Settled	(185)	(380)
Accretion	617	740
Revisions to Prior Estimates	(1,225)	(1,923)
Ending Balance	$ 13,259	$ 14,052

Operating Leases (Details)

Operating Leases (Details) - lease	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Number of Finance Leases	1
Discount Rate - Operating leases	4.24%	4.27%
Minimum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	35 years

Lessee - Lease Costs (Details)

Lessee - Lease Costs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operations and maintenance
Operating lease cost	$ 978	$ 1,456

Lessee - Supplemental Balance S

Lessee - Supplemental Balance Sheet Information (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating lease assets	$ 4,188	$ 4,629
Total lease liabilities	4,543	5,000
Other assets, non-current
Lessee, Lease, Description [Line Items]
Operating lease assets	4,188	4,629
Accrued liabilities
Lessee, Lease, Description [Line Items]
Operating lease liability, current	736	1,179
Other deferred credits and other liabilities
Lessee, Lease, Description [Line Items]
Operating lease, liability, noncurrent	$ 3,807	$ 3,821

Lessee - Supplemental Cash Flow

Lessee - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating cash flows from operating leases	$ 1,023	$ 1,263
Operating leases	$ 161	$ 2,801

Lessee - Weighted Average Infor

Lessee - Weighted Average Information (Details)	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Lease Term - Operating leases	8 years	8 years
Discount Rate - Operating leases	4.24%	4.27%

Lessee - Future Minimum Payment

Lessee - Future Minimum Payments (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
2021	$ 907
2022	804
2023	779
2024	776
2025	529
Thereafter	1,643
Total lease payments	5,438
Less imputed interest	895
Total lease liabilities	$ 4,543	$ 5,000

Lessor (Details)

Lessor (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessor, Lease, Description [Line Items]
Operating lease income	$ 2,534	$ 2,306
Minimum
Lessor, Lease, Description [Line Items]
Lessor - lease term	1 year
Maximum
Lessor, Lease, Description [Line Items]
Lessor - lease term	34 years

Lessor - Future Minimum Payment

Lessor - Future Minimum Payments (Details) $ in Thousands	Dec. 31, 2020USD ($)
Leases [Abstract]
2021	$ 2,383
2022	2,122
2023	2,130
2024	2,074
2025	2,090
Thereafter	58,829
Total lease receivables	$ 69,628

Short-Term Debt_ (Details)

Short-Term Debt: (Details)	12 Months Ended
	Dec. 31, 2020USD ($)credit_extension	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Jul. 30, 2018USD ($)
Short-term Debt [Line Items]
Notes payable	$ 234,040,000	$ 349,500,000
Letters of Credit Outstanding, Amount	24,730,000	30,274,000
Commercial Paper, Maximum Borrowing Capacity	750,000,000
Net (payments) borrowings of short-term debt	(115,460,000)	163,880,000	$ (25,680,000)
Commercial Paper
Short-term Debt [Line Items]
Notes payable	234,040,000	349,500,000
Letters of Credit Outstanding, Amount	$ 0	0
Debt Instrument, Term	397 days
Debt, Weighted Average Interest Rate	0.27%
Revolving Credit Facility
Short-term Debt [Line Items]
Notes payable	$ 0	0
Letters of Credit Outstanding, Amount	$ 24,730,000	$ 30,274,000
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%

Long-Term Debt (Details)

Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Jun. 17, 2020	Dec. 31, 2019	Oct. 03, 2019
Debt Instrument [Line Items]
Total long-term debt	$ 3,561,345		$ 3,170,489
Less current maturities	8,436		5,743
Less unamortized deferred financing costs	24,809		24,650
Long-term debt, net of current maturities	3,528,100		3,140,096
Revolving Credit Facility
Debt Instrument [Line Items]
Less unamortized deferred financing costs	1,000		1,700
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 2030
Debt Instrument [Line Items]
Stated interest rate (percent)		2.50%
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	3,026,436		2,632,178
Less unamortized debt discount	(7,013)		(6,462)
Total long-term debt	$ 3,019,423		2,625,716
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 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 2029
Debt Instrument [Line Items]
Stated interest rate (percent)	3.05%
Long-term debt	$ 400,000		400,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2030
Debt Instrument [Line Items]
Stated interest rate (percent)	2.50%
Long-term debt	$ 400,000		0
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 2049
Debt Instrument [Line Items]
Stated interest rate (percent)	3.88%
Long-term debt	$ 300,000		300,000
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	$ 1,436		7,178
Black Hills Energy, South Dakota Electric | Electric Utilities
Debt Instrument [Line Items]
Long-term debt	340,000		342,855
Less unamortized debt discount	(78)		(82)
Total long-term debt	339,922		342,773
Black Hills Energy, South Dakota Electric | Electric Utilities | Series 94 A Debt, Due 2024
Debt Instrument [Line Items]
Long-term debt	$ 0		2,855
Black Hills Energy, 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
Black Hills Energy, 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
Black Hills Energy, 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
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 | Industrial Development Revenue Bonds Due 2021
Debt Instrument [Line Items]
Variable interest rate (percent)	0.12%
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)	0.12%
Long-term debt	$ 10,000		10,000
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

Long-Term Debt_ Aggregate Matur

Long-Term Debt: Aggregate Maturities of Long Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Debt Disclosure [Abstract]
Less current maturities	$ 8,436	$ 5,743
2022	0
2023	525,000
2024	0
2025	0
Thereafter	$ 3,035,000

Long-Term Debt_ Amortization Ex

Long-Term Debt: Amortization Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt Disclosure [Abstract]
Deferred Finance Costs Remaining, Noncurrent	$ 24,809
Amortization expense for deferred financing costs	$ 3,272	$ 3,242	$ 2,829

Long-Term Debt_ Debt Transactio

Long-Term Debt: Debt Transactions (Details) - USD ($) $ in Thousands	Jun. 17, 2020	Mar. 24, 2020	Oct. 03, 2019	Jun. 17, 2019	Dec. 31, 2020
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
Black Hills Energy, South Dakota Electric | Series 94 A Debt, Due 2024
Debt Instrument [Line Items]
Extinguishment of Debt, Amount		$ 2,900
Corporate, Non-Segment
Debt Instrument [Line Items]
Proceeds from Issuance of Debt			700,000
Corporate, Non-Segment | Senior Unsecured Notes Due 2030
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 400,000
Stated interest rate (percent)	2.50%
Long-term Debt, Term	10 years
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 | Black Hills Corporation | Senior Unsecured Notes Due 2030
Debt Instrument [Line Items]
Stated interest rate (percent)					2.50%
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Stated interest rate (percent)					3.05%
Corporate, Non-Segment | Black Hills Corporation | Senior Unsecured Notes Due 2049
Debt Instrument [Line Items]
Stated interest rate (percent)					3.88%
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%
Corporate, Non-Segment | Black Hills Corporation | Corporate Term Loan Due July 2020
Debt Instrument [Line Items]
Extinguishment of Debt, Amount				$ 300,000

Debt Covenants (Details)

Debt Covenants (Details)	Dec. 31, 2020
Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital	0.599
Maximum
Debt Instrument [Line Items]
Debt Instrument, Debt to Capitalization Ratio Requirement	0.65
Maximum | Wyoming Electric
Debt Instrument [Line Items]
Debt Instrument, Debt to Capitalization Ratio Requirement	0.60

Long-Term Debt_ Dividend Restri

Long-Term Debt: Dividend Restrictions (Details) $ in Millions	Dec. 31, 2020USD ($)
Utilities Group
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$ 155

Stockholders' Equity_ Equity Is

Stockholders' Equity: Equity Issuance (Details) - Private Placement $ / shares in Units, shares in Thousands, $ in Thousands	Feb. 27, 2020USD ($)$ / sharesshares
Sale of Stock, Number of Shares Issued in Transaction | shares	1,200
Sale of Stock, Price Per Share | $ / shares	$ 81.77
Sale of Stock, Consideration Received on Transaction	$ 99,000
Payments of Stock Issuance Costs	$ 1,000

Equity_ At-the-Market Equity Of

Equity: At-the-Market Equity Offering Program (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Aug. 03, 2020	Jun. 30, 2020
At The Market Equity Offering Program Authorized Aggregate Value		$ 400,000	$ 300,000
Common Stock
At The Market Equity Offering Program Shares Issued	1,328,332
At The Market Equity Program Proceeds from Sale of Stock	$ 99,000
Payments of Stock Issuance Costs	$ 1,200

Equity_ Shareholder Dividend Re

Equity: Shareholder Dividend Reinvestment and Stock Purchase Plan (Details)	Dec. 31, 2020shares
Class of Stock [Line Items]
Unissued Shares Available	163,962
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, 2020shares
Stockholders' Equity Note [Abstract]
Preferred Stock, Shares Authorized	25,000,000
Preferred Stock, Shares Outstanding	0

Risk Management And Derivativ_3

Risk Management And Derivatives: Market and Credit Risk Disclosures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Bad Debt Expense	$ 8,927	$ 5,795	$ 6,859
Allowance for credit losses	7,003	$ 2,444	$ 3,209	$ 3,081
Potential economic impact of the COVID-19 pandemic
Bad Debt Expense	3,300
Allowance for credit losses	$ 3,300

Risk Management Activities_ Uti

Risk Management Activities: Utilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)MMBTUmW	Dec. 31, 2019MMBTUmW
Derivative [Line Items]
Collateral Already Posted, Aggregate Fair Value | $	$ 1,500
Natural Gas, Distribution | Future
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	620,000	1,450,000
Derivative, Remaining Maturity	3 months	12 months
Natural Gas, Distribution | Commodity Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,160,000	3,240,000
Derivative, Remaining Maturity	3 months	3 months
Natural Gas, Distribution | Basis Swap
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	900,000	1,290,000
Derivative, Remaining Maturity	3 months	12 months
Natural Gas, Distribution | Fixed for Float Swaps Purchased
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	3,850,000	4,600,000
Derivative, Remaining Maturity	17 months	24 months
Natural Gas, Distribution | Fixed for Float Swaps Purchased | Cash Flow Hedging | Over the Counter
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	914,600
Natural Gas, Distribution | Natural Gas Physical Purchases
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	17,513,061	13,548,235
Derivative, Remaining Maturity	22 months	12 months
Electricity | Energy Related Derivative
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount | mW	219,000	0
Derivative, Remaining Maturity	12 months	0 months

Risk Management And Derivativ_4

Risk Management And Derivatives: Derivatives by Balance Sheet Classification (Details) - Commodity Contract - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Designated as Hedging Instrument
Fair Value Hedges, Net	$ 116	$ (515)
Not Designated as Hedging Instrument
Fair Value Hedges, Net	(118)	(1,484)
Derivative Assets, Current | Designated as Hedging Instrument
Fair Value Hedge Assets	181	1
Derivative Assets, Current | Not Designated as Hedging Instrument
Fair Value Hedge Assets	1,667	341
Derivative Assets, Noncurrent | Designated as Hedging Instrument
Fair Value Hedge Assets	43	3
Derivative Assets, Noncurrent | Not Designated as Hedging Instrument
Fair Value Hedge Assets	151	2
Derivative Liabilities, Current | Designated as Hedging Instrument
Derivative Liability, Current	(108)	(490)
Derivative Liabilities, Current | Not Designated as Hedging Instrument
Derivative Liability, Current	(1,936)	(1,764)
Derivative Liabilities, Noncurrent | Designated as Hedging Instrument
Derivative Liability, Current	0	(29)
Derivative Liabilities, Noncurrent | Not Designated as Hedging Instrument
Derivative Liability, Current	$ 0	$ (63)

Risk Management Activities_ Cas

Risk Management Activities: Cash Flow Hedges (Details) - Cash Flow Hedging - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Interest Rate Swap and Commodity Derivative
Derivative Instruments, Gain (Loss) [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 2,800
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	(3,452)	$ (2,434)	$ (2,981)
Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Swap | Cash Flow Hedging | 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)	(2,851)
Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract | Cash Flow Hedging | 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	(601)	417	(130)
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	3,391	1,886	3,964
Designated as Hedging Instrument | Interest Rate Swap
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	2,851	2,851	2,851
Designated as Hedging Instrument | Commodity Contract
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ 540	$ (965)	$ 1,113

Risk Management Activities_ Der

Risk Management Activities: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory assets	$ 278,258	$ 271,344
Gas price derivatives
Derivative Instruments, Gain (Loss) [Line Items]
Regulatory assets	2,226	3,328
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1,784	(1,100)	$ 1,101
Not Designated as Hedging Instrument | Fuel, purchased power and cost of natural gas sold
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1,640	(1,100)	1,101
Not Designated as Hedging Instrument | Fuel, purchased power and cost of natural gas sold | Electricity
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 144	$ 0	$ 0

Fair Value Measurements_ Recurr

Fair Value Measurements: Recurring Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Contract Subject to Master Netting Arrangement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 1,500	$ 1,100
Derivative Liability, Fair Value, Gross Liability	1,600	2,900
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	(1,527)	(1,085)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(1,552)	(2,909)
Fair Value, Measurements, Recurring | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Total	2,042	348
Derivative Liabilities, Total	2,044	2,345
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	3,569	1,433
Derivative Liabilities, Total	3,596	5,254
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 | Gas Utilities
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	(1,527)	(1,085)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(1,552)	(2,909)
Fair Value, Measurements, Recurring | Gas Utilities | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	977	348
Derivative, Liabilities, Fair Value Disclosure	1,123	2,345
Fair Value, Measurements, Recurring | Gas Utilities | 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 | Gas Utilities | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	2,504	1,433
Derivative, Liabilities, Fair Value Disclosure	2,675	5,254
Fair Value, Measurements, Recurring | Gas Utilities | 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, Recurring | Electric Utilities
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	0
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	0
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	1,065
Derivative, Liabilities, Fair Value Disclosure	921
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0
Derivative, Liabilities, Fair Value Disclosure
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	1,065
Derivative, Liabilities, Fair Value Disclosure	921
Fair Value, Measurements, Recurring | Electric Utilities | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0
Derivative, Liabilities, Fair Value Disclosure

Fair Value Measurements_ Other

Fair Value Measurements: Other Fair Value Measurements (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt	$ 3,536,536	$ 3,145,839
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, including current maturities - fair value	$ 4,208,167	$ 3,479,367

Other Comprehensive Income (Det

Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense	$ 144,931	$ 139,291	$ 141,616
Fuel, purchased power and cost of natural gas sold	492,404	570,829	625,610
Operations and maintenance	495,404	495,994	481,706
Income before income taxes	275,681	242,902	255,882
Income Tax Expense (Benefit)	(32,918)	(29,580)	23,667
Net income	242,763	213,322	$ 272,662
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income	(4,418)	(2,944)
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	(3,452)	(2,434)
Income Tax Expense (Benefit)	383	611
Net income	(3,069)	(1,823)
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Interest Rate Swap
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense	(2,851)	(2,851)
Cash Flow Hedging | Reclassification out of Accumulated Other Comprehensive Income | Commodity Contract
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Fuel, purchased power and cost of natural gas sold	(601)	417
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	103	77
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	(2,387)	(745)
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	(2,284)	(668)
Income Tax Expense (Benefit)	935	(453)
Net income	$ (1,349)	$ (1,121)

Other Comprehensive Income_ Acc

Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (30,655)	$ (26,916)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(27,346)	(30,655)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(15,077)	(9,937)
Other comprehensive income (loss), before reclassifications	(1,062)	(6,261)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(14,790)	(15,077)
Accumulated Defined Benefit Plans Adjustment | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from AOCI	1,349	1,121
Accumulated Other Comprehensive Income (Loss)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income (loss), before reclassifications	(1,109)	(6,683)
Accumulated Other Comprehensive Income (Loss) | Reclassification out of Accumulated Other Comprehensive Income
Accumulated Other Comprehensive Income (Loss) [Line Items]
Amounts reclassified from AOCI	4,418	2,944
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	(15,122)	(17,307)
Other comprehensive income (loss), before reclassifications	0	0
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(12,558)	(15,122)
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	2,564	2,185
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	(456)	328
Other comprehensive income (loss), before reclassifications	(47)	(422)
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	2	(456)
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	$ 505	$ (362)

Variable Interest Entity_ (Deta

Variable Interest Entity: (Details) $ in Thousands	Apr. 14, 2016	Dec. 31, 2020USD ($)MW	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Net income attributable to noncontrolling interest		$ (15,155)	$ (14,012)	$ (14,220)
Current assets		493,291	473,184
Property, plant and equipment of variable interest entities, net		6,019,714	5,503,186
Current liabilities		696,533	811,294
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Current assets		13,604	13,350
Property, plant and equipment of variable interest entities, net		190,637	193,046
Current liabilities		5,318	6,013
Power Generation
Variable Interest Entity [Line Items]
Net income attributable to noncontrolling interest		(15,000)	(14,000)	$ (14,000)
Property, plant and equipment of variable interest entities, net		$ 367,016	$ 380,156
Pueblo Airport Generation | Subsidiary of Common Parent
Variable Interest Entity [Line Items]
Electric Generation Capacity, Megawatts | MW		200

Defined Contribution Plans (Det

Defined Contribution Plans (Details)	12 Months Ended
	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	50.00%
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	20.00%
Defined Contribution Plan, Employee Vesting Period	5 years
Maximum
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	100.00%

Defined Benefit Pension Plan (D

Defined Benefit Pension Plan (Details) - gas_distribution_territory	Dec. 31, 2020	Dec. 31, 2019
Number of Defined Pension Plans	1
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Investment in privately held oil and gas company
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	21.00%	20.00%
Real Estate
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	3.00%	3.00%
Fixed Income
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	69.00%	71.00%
Cash
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	3.00%	1.00%
Hedge Funds
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	4.00%	5.00%
Minimum | Return Seeking Assets | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	28.00%
Minimum | Hedge Funds | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	64.00%
Maximum | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	72.00%
Maximum | Return Seeking Assets | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	36.00%

Plan Contributions (Details)

Plan Contributions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	$ 12,700	$ 12,700
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	6,058	7,033
Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Payment for Pension and Other Postretirement Benefits	2,674	2,344
Defined Contribution Plan, Company Retirement
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	10,455	9,714
Defined Contribution Plan, 401K
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 15,240	$ 14,558

Fair Value Measurements (Detail

Fair Value Measurements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Hedge Funds | Minimum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	15 days
Hedge Funds | Maximum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	60 days
Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 473,721	$ 434,284	$ 390,796
Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	473,721	434,284
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	441,966	400,495
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	31,755	33,789
Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	8,165	8,305
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	8,165	8,305
Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	8,165	8,305
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	441,966	400,495
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	0	0
Fixed Income | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount		60
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments		60
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets		0
Fixed Income | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount		0
Fixed Income | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount		60
Fixed Income | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount		0
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	16,810	7,054
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	16,810	7,054
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	16,810	7,054
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust, Equity Fund | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	100,311	87,106
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	100,311	87,106
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Common Collective Trust, Equity Fund | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust, Equity Fund | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	100,311	87,106
Common Collective Trust, Equity Fund | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust, Fixed Income Fund | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	324,845	306,275
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	324,845	306,275
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Common Collective Trust, Fixed Income Fund | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust, Fixed Income Fund | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	324,845	306,275
Common Collective Trust, Fixed Income Fund | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Real Estate Funds | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	14,301	14,239
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	0	0
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	14,301	14,239
Real Estate Funds | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Real Estate Funds | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Real Estate Funds | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 0	0
Hedge Funds | Minimum
Percentage Of Monthly Redemption	1000.00%
Hedge Funds | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 17,454	19,550
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	0	0
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	17,454	19,550
Hedge Funds | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Hedge Funds | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Hedge Funds | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Cash | Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	8,165	8,305
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	8,165	8,305
Cash | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	8,165	8,305
Cash | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	0	0
Cash | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Postretirement Health Coverage
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0

Employee Benefit Plans_ Employe

Employee Benefit Plans: Employee Benefit Plan Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Plan
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	$ 485,376	$ 445,381
Service Cost	5,411	5,383	$ 6,834
Interest cost	13,426	17,374	15,470
Actuarial (gain) loss	47,064	56,384
Benefits paid	(37,269)	(39,146)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	514,008	485,376	445,381
Supplemental Employee Retirement Plan
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	54,088	43,010
Service Cost	1,579	4,995
Interest cost	1,099	1,295
Actuarial (gain) loss	962	7,132
Benefits paid	(2,674)	(2,344)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	55,054	54,088	43,010
Supplemental Employee Retirement Plan | Error Correction, Other
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Service Cost	1,400
Other Postretirement Benefits Plan
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	65,277	60,817
Service Cost	2,056	1,815	2,291
Interest cost	1,649	2,247	2,085
Actuarial (gain) loss	5,804	5,976
Benefits paid	(6,058)	(7,033)
Plan participants’ contributions	1,510	1,455
Projected benefit obligation at end of year	$ 70,238	$ 65,277	$ 60,817

Employee Benefit Plans_ Fair Va

Employee Benefit Plans: Fair Value Employee Benefit Plan Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Beginning fair value of plan assets	$ 434,284	$ 390,796
Investment income (loss)	64,006	69,934
Employer contributions	12,700	12,700
Retiree contributions	0	0
Defined Benefit Plan, Plan Assets, Benefits Paid	(37,269)	(39,146)
Ending fair value of plan assets	473,721	434,284
Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Beginning fair value of plan assets	0	0
Investment income (loss)	0	0
Employer contributions	2,674	2,344
Retiree contributions	0	0
Defined Benefit Plan, Plan Assets, Benefits Paid	(2,674)	(2,344)
Ending fair value of plan assets	0	0
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Beginning fair value of plan assets	8,305	8,162
Investment income (loss)	33	260
Employer contributions	4,374	5,461
Retiree contributions	1,511	1,455
Defined Benefit Plan, Plan Assets, Benefits Paid	(6,058)	(7,033)
Ending fair value of plan assets	$ 8,165	$ 8,305

Employee Benefit Plans_ Amounts

Employee Benefit Plans: Amounts Recognized in the Consolidated Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	$ 278,258	$ 271,344
Benefit plan liabilities	150,556	154,472
Regulatory liabilities	532,720	536,652
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	86,677	88,471
Current liabilities	0	0
Benefit plan liabilities	40,287	51,093
Regulatory liabilities	3,607	3,524
Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	0	0
Current liabilities	1,927	1,420
Benefit plan liabilities	53,127	51,243
Regulatory liabilities	0	0
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Regulatory assets	16,102	11,670
Current liabilities	4,931	4,802
Benefit plan liabilities	57,142	52,136
Regulatory liabilities	$ 2,140	$ 4,088

Employee Benefit Plans_ Accumul

Employee Benefit Plans: Accumulated Benefit Obligations (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 498,815	$ 470,615
Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	54,779	49,241
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Accumulated Benefit Obligation	$ 70,238	$ 65,277

Employee Benefit Plans_ Compone

Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 5,411	$ 5,383	$ 6,834
Interest cost	13,426	17,374	15,470
Expected return on assets	(22,591)	(24,401)	(24,741)
Net amortization of prior service cost	0	26	58
Recognized net actuarial loss (gain)	8,372	3,763	8,632
Net periodic benefit expense	4,618	2,145	6,253
Other Pension, Postretirement and Supplemental Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,579	4,995	1,764
Interest cost	1,099	1,295	1,170
Expected return on assets	0	0	0
Net amortization of prior service cost	2	2	2
Recognized net actuarial loss (gain)	1,702	535	1,000
Net periodic benefit expense	4,382	6,827	3,936
Other Pension, Postretirement and Supplemental Plans | Error Correction, Other
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1,400
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	2,056	1,815	2,291
Interest cost	1,649	2,247	2,085
Expected return on assets	(182)	(230)	(315)
Net amortization of prior service cost	(546)	(398)	(398)
Recognized net actuarial loss (gain)	20	0	216
Net periodic benefit expense	$ 2,997	$ 3,434	$ 3,879

Employee Benefit Plans_ Change

Employee Benefit Plans: Change in Accounting Principal (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Other income (expense), net	$ (2,293)	$ (5,740)	$ (1,180)
Income tax benefit (expense)	(32,918)	(29,580)	23,667
Net income available for common stock	227,608	$ 199,310	$ 258,442
Cumulative Effect, Period of Adoption, Adjustment
Defined Benefit Plan Disclosure [Line Items]
Other income (expense), net	600
Income tax benefit (expense)	200
Net income available for common stock	$ 400

Employee Benefit Plans_ AOCI Am

Employee Benefit Plans: AOCI Amounts (After-Tax) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Net (gain) loss	$ 5,511	$ 5,322
Prior service cost (gain)	0	0
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense	5,511	5,322
Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Net (gain) loss	9,323	9,893
Prior service cost (gain)	0	2
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense	9,323	9,895
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Net (gain) loss	100	90
Prior service cost (gain)	(144)	(230)
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense	$ (44)	$ (140)

Assumptions (Details)

Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Minimum
Defined Benefit Plan Disclosure [Line Items]
Trend Year	2027	2027
Maximum
Defined Benefit Plan Disclosure [Line Items]
Trend Year	2029	2028
Black Hills Corporation | Minimum
Defined Benefit Plan Disclosure [Line Items]
Post-65 for next year - All Plans	6.10%	6.40%
Black Hills Corporation | Maximum
Defined Benefit Plan Disclosure [Line Items]
Post-65 for next year - All Plans	4.92%	4.92%
Black Hills Service Company | Minimum
Defined Benefit Plan Disclosure [Line Items]
Post-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Black Hills Service Company | Maximum
Defined Benefit Plan Disclosure [Line Items]
Post-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.56%	3.27%	4.40%
Rate of increase in compensation levels	3.34%	3.49%	3.52%
Expected long-term rate of return on assets	5.25%	6.00%	6.25%
Rate of increase in compensation levels	3.49%	3.52%	3.43%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year	4.50%
2021	$ 25,842
2022	26,658
2023	27,581
2024	28,284
2025	29,062
2026-2030	$ 144,273
Pension Plan | Black Hills Corporation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.27%	4.40%	3.71%
Pension Plan | Black Hills Corporation Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Post-65 for next year - All Plans	2.56%
Supplemental Employee Retirement Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.41%	3.14%	4.34%
Rate of increase in compensation levels	5.00%	5.00%	5.00%
Rate of increase in compensation levels	5.00%	5.00%	5.00%
2021	$ 1,927
2022	1,968
2023	2,033
2024	2,231
2025	2,690
2026-2030	$ 13,117
Supplemental Employee Retirement Plan | Black Hills Corporation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.14%	4.34%	3.67%
Other Postretirement Benefits Plan
Defined Benefit Plan Disclosure [Line Items]
Discount rate	2.41%	3.15%	4.28%
Expected long-term rate of return on assets	2.35%	3.00%	3.93%
2021	$ 6,108
2022	5,965
2023	5,725
2024	5,532
2025	5,244
2026-2030	$ 22,872
Other Postretirement Benefits Plan | Black Hills Corporation
Defined Benefit Plan Disclosure [Line Items]
Discount Rate	3.15%	4.28%	3.60%

Compensation Related Costs, Sha

Compensation Related Costs, Share Based Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Payment Arrangement [Abstract]
Shares available for grant	561,073
Unrecognized compensation expense	$ 12,000
Weighted-average recognition period	2 years
Stock compensation	$ 5,373	$ 12,095	$ 12,390

Stock Options (Details)

Stock Options (Details) - Employee Stock Option	Dec. 31, 2020shares
Share-based Payment Arrangement [Abstract]
Shares exercisable at end of period	5,000
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares exercisable at end of period	5,000

Restricted Stock (Details)

Restricted Stock (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted Stock and RSUs, total fair value of shares vested	$ 2,199	$ 5,720	$ 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	196	192
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 69.05	$ 65.66
Performance Shares, Granted in Period	116
Granted (usd per share)	$ 69.49	$ 73.66	$ 57.31
Shares Vested	(90)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 63.30
Shares Forfeited	(22)
Forfeited (usd per share)	$ 65.30
Restricted Stock and RSUs, total fair value of shares vested	$ 6,722	$ 8,438	$ 6,776
Unrecognized compensation expense	$ 10,300
Weighted-average recognition period	2 years 2 months 12 days

Performance Share Plan (Details

Performance Share Plan (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense	$ 12,000
Stock Issued During Period, Shares, Treasury Stock Reissued	14	44	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 1,100	$ 2,860	$ 0
Restricted Stock and RSUs, total fair value of shares vested	$ 2,199	$ 5,720	$ 0
Performance Goal - Percentile of Peer Group Performance	5500.00%
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	$ 2,700
Performance Shares, Number of Shares Authorized	36	36	49
Performance Share Award, Percentage of Target	112.35%
Weighted Average Grant Date Fair Value (usd per share)	$ 81.42	$ 68.72	$ 61.82
Blended volatility	18.00%	21.00%	21.00%
Historical volatility	50.00%
Target shares, value	$ 3,300
Weighted-average recognition period	1 year 8 months 12 days
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	$ 2,000
Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	0.00%	0.00%	0.00%
Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	200.00%	200.00%	200.00%
Performance Shares, Equity Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares, Number of Shares Authorized	61	67
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 69.71	$ 64.32
Performance Shares, Granted in Period	19
Shares Forfeited	(2)
Forfeited (usd per share)	$ 73.89
Shares Vested	(23)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 63.52
Performance Shares, Liability Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Shares, Number of Shares Authorized	61	67
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 52.42
Performance Shares, Granted in Period	19
Shares Forfeited	(2)
Shares Vested	(23)

Income Taxes_ CARES Act (Detail

Income Taxes: CARES Act (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)
Income Tax Disclosure [Abstract]
Proceeds from Income Tax Refunds	$ 2,400
Amount of Payroll Tax (Social Security Employment Tax) Deferral Allowed Under the CARES Act	$ 10,000

Income Taxes_ Tax Cut and Jobs

Income Taxes: Tax Cut and Jobs Act (Details) - USD ($) $ in Thousands	12 Months Ended			36 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2020
Tax Cuts and Jobs Act of 2017, Change in Tax Rate, Regulatory Liability			$ 309,000
Increase (Decrease) in Regulatory Liabilities	$ (10,706)	$ (15,158)	18,533
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				$ 13,300

Income Taxes_ Current and Defer

Income Taxes: Current and Deferred Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current:
Federal	$ (6,020)	$ (8,578)	$ 325
State	847	138	247
Total Current	(5,173)	(8,440)	572
Deferred:
Federal	35,672	34,551	(25,022)
State	2,419	3,469	783
Total Deferred	38,091	38,020	(24,239)
Total Current and Deferred	$ 32,918	$ 29,580	$ (23,667)

Income Taxes_ Effective Tax Rat

Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Federal Statutory Rate	21.00%	21.00%	21.00%
State income tax (net of federal tax effect)	2.40%	1.50%	2.30%
Non-controlling interest	(1.20%)	(1.20%)	(1.30%)
Tax Credits	(9.20%)	(3.90%)	(2.00%)
Flow-through adjustments	(1.60%)	(2.40%)	(1.60%)
Jurisdictional simplification project	0.00%	0.00%	(28.50%)
Uncertain Tax Benefits	1.50%	0.00%	0.00%
Valuation Allowance	0.70%	0.00%	0.00%
Other tax differences	0.60%	(1.60%)	(0.10%)
TCJA corporate rate reduction	0	0	0.016
Effective Income Tax Reconciliation, Amortization Of Excess Deferred Income Tax Expense	(2.30%)	(1.20%)	(0.70%)
Effective Income Tax Rate, Continuing Operations	11.90%	12.20%	(9.30%)
Deferred Income Tax Expense (Benefit)	$ (38,091)	$ (38,020)	$ 24,239
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount			4,000
Other Restructuring
Deferred Tax Assets, Goodwill and Intangible Assets			73,000
Deferred Income Tax Expense (Benefit)			$ 73,000

Income Taxes_ Deferred Income T

Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred Tax Assets, Net [Abstract]
Regulatory liabilities	$ 90,535	$ 89,754
State tax credits	23,339	23,261
Federal NOL	96,155	120,624
State NOL	9,914	13,537
Partnership	15,601	14,030
Credit Carryovers	51,445	27,139
Other deferred tax assets	40,143	33,395
Less: Valuation allowance	(13,943)	(12,063)
Total deferred tax assets	313,189	309,677
Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(551,137)	(533,292)
Regulatory assets	(28,007)	(23,586)
Goodwill	(30,590)	(15,875)
State deferred tax liability	(73,910)	(72,911)
Other deferred tax liabilities	(38,169)	(24,732)
Total deferred tax liabilities	(721,813)	(670,396)
Net deferred tax liability	$ (408,624)	$ (360,719)

Income Taxes_ Net Operating Los

Income Taxes: Net Operating Loss Carryforwards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Loss Carryforwards [Line Items]
Deferred Income Tax Expense (Benefit)	$ 38,091	$ 38,020	$ (24,239)
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	9,914	$ 13,537
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	378,236
Operating Loss Carryforwards, With no Expiration Date	79,644
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	173,867
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	1,300
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Valuation Allowance	1,100
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	800
Valuation Allowance Reduction due to Expired NOL	200
Deferred Income Tax Expense (Benefit)	800
Deferred Tax Assets, Operating Loss Carryforwards, State and Local	$ 200

Income Taxes_ Reconciliation of

Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 4,165	$ 3,583	$ 3,263
Additions for prior year tax positions	3,788	446	251
Reductions for prior year tax positions	(1,313)	(862)	(417)
Additions for current year tax positions	1,743	998	486
Settlements	0	0	0
Liability for Uncertain Tax Positions, Noncurrent, Period End	8,383	$ 4,165	$ 3,583
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 4,300

Income Taxes_ Interest, Penalti

Income Taxes: Interest, Penalties and Audits (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits, Interest Expense	$ 0	$ 0	$ 0
Unrecognized Tax Benefits, Interest Accrued	$ 0	$ 0	$ 0

Income Taxes_ Carryforwards, St

Income Taxes: Carryforwards, State and Foreign Tax Credits (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Tax Credit Carryforward [Line Items]
Income Tax Expense (Benefit)	$ 32,918	$ 29,580	$ (23,667)
State and Local Jurisdiction
Tax Credit Carryforward [Line Items]
Tax Credit Carryforward, Valuation Allowance	12,800
Income Tax Expense (Benefit)	1,300
State and Local Jurisdiction | Investment Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	23,060
State and Local Jurisdiction | Research Tax Credit Carryforward
Tax Credit Carryforward [Line Items]
Deferred Tax Assets, State Tax Credits	$ 278

Business Segment Information_ S

Business Segment Information: Segment Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting, Asset Reconciling Item
Total Assets	$ 8,088,786	$ 7,558,457
Corporate, Non-Segment
Segment Reporting, Asset Reconciling Item
Total Assets	110,349	130,245
Electric Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	3,120,928	2,900,983
Gas Utilities
Segment Reporting, Asset Reconciling Item
Total Assets	4,376,204	4,032,339
Power Generation
Segment Reporting, Asset Reconciling Item
Total Assets	404,220	417,715
Mining
Segment Reporting, Asset Reconciling Item
Total Assets	$ 77,085	$ 77,175

Business Segment Information_ C

Business Segment Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Capital Expenditures	$ 755,392	$ 849,755
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital Expenditures	17,500	20,702
Electric Utilities
Segment Reporting Information [Line Items]
Capital Expenditures	271,104	222,911
Gas Utilities
Segment Reporting Information [Line Items]
Capital Expenditures	449,209	512,366
Power Generation
Segment Reporting Information [Line Items]
Capital Expenditures	9,329	85,346
Mining
Segment Reporting Information [Line Items]
Capital Expenditures	$ 8,250	$ 8,430

Business Segment Information_ P

Business Segment Information: Property, Plant and Equipment (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	$ 7,305,530	$ 6,784,679
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	22,094	29,055
Electric Utilities
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	3,248,480	3,059,135
Gas Utilities
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	3,312,613	2,981,498
Power Generation
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	534,803	534,518
Mining
Segment Reporting Information [Line Items]
Property, Plant and Equipment, Gross	$ 187,540	$ 180,473

Business Segment Information_ I

Business Segment Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Sep. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information
Revenue from contracts with customers			$ 1,680,804	$ 1,726,392	$ 1,748,542
Revenue			1,696,941	1,734,900	1,754,268
Fuel, purchased power and cost of natural gas sold			492,404	570,829	625,610
Operations and maintenance, including taxes			551,777	548,909	535,293
Depreciation, depletion and amortization			224,457	209,120	196,328
Operating income			428,303	406,042	397,037
Interest expense			(143,470)	(137,659)	(139,975)
Impairment of investment	$ (20,000)	$ (6,900)	(6,859)	(19,741)	0
Other income (expense), net			(2,293)	(5,740)	(1,180)
Income tax benefit (expense)			(32,918)	(29,580)	23,667
Income from continuing operations			242,763	213,322	279,549
(Loss) from discontinued operations, net of tax			0	0	(6,887)
Net income			242,763	213,322	272,662
Net income attributable to noncontrolling interest			(15,155)	(14,012)	(14,220)
Net income available for common stock			227,608	199,310	258,442
Electric Utilities
Segment Reporting Information
Revenue from contracts with customers			711,843	707,561	709,024
Revenue			714,044	712,752	711,451
Fuel, purchased power and cost of natural gas sold			267,045	268,297	283,840
Operations and maintenance, including taxes			196,794	195,581	186,175
Depreciation, depletion and amortization			94,150	88,577	85,567
Adjusted operating income (loss)			156,055	160,297	155,869
Gas Utilities
Segment Reporting Information
Revenue from contracts with customers			964,421	1,009,646	1,024,352
Revenue			974,670	1,010,030	1,025,307
Fuel, purchased power and cost of natural gas sold			354,645	425,898	462,153
Operations and maintenance, including taxes			303,577	301,844	291,481
Depreciation, depletion and amortization			100,559	92,317	86,434
Adjusted operating income (loss)			215,889	189,971	185,239
Power Generation
Segment Reporting Information
Revenue from contracts with customers			103,258	99,157	90,791
Revenue			105,047	101,258	92,451
Fuel, purchased power and cost of natural gas sold			8,993	9,059	8,592
Operations and maintenance, including taxes			33,695	28,429	25,135
Depreciation, depletion and amortization			20,247	18,991	16,110
Adjusted operating income (loss)			42,112	44,779	42,614
Net income attributable to noncontrolling interest			(15,000)	(14,000)	(14,000)
Mining
Segment Reporting Information
Revenue from contracts with customers			58,567	59,233	65,803
Revenue			61,075	61,629	68,033
Fuel, purchased power and cost of natural gas sold			0	0	0
Operations and maintenance, including taxes			39,033	40,032	43,728
Depreciation, depletion and amortization			9,235	8,970	7,965
Adjusted operating income (loss)			12,807	12,627	16,340
Intercompany Eliminations
Segment Reporting Information
Revenue from contracts with customers			(157,285)	(149,205)	(141,428)
Revenue			(157,895)	(150,769)	(142,974)
Fuel, purchased power and cost of natural gas sold			(138,362)	(132,693)	(129,019)
Operations and maintenance, including taxes			(305,823)	(303,776)	(336,142)
Depreciation, depletion and amortization			(24,884)	(21,800)	(20,909)
Adjusted operating income (loss)			(41,969)	(36,705)	(36,827)
Corporate, Non-Segment
Segment Reporting Information
Revenue			353,143	344,205	379,923
Fuel, purchased power and cost of natural gas sold			83	268	44
Operations and maintenance, including taxes			284,501	286,799	324,916
Depreciation, depletion and amortization			25,150	22,065	21,161
Adjusted operating income (loss)			43,409	35,073	33,802
Other revenues
Segment Reporting Information
Revenue			16,137	8,508	5,726
Other revenues | Electric Utilities
Segment Reporting Information
Revenue			2,201	5,191	2,427
Other revenues | Gas Utilities
Segment Reporting Information
Revenue			10,249	384	955
Other revenues | Power Generation
Segment Reporting Information
Revenue			1,789	2,101	1,660
Other revenues | Mining
Segment Reporting Information
Revenue			2,508	2,396	2,230
Other revenues | Intercompany Eliminations
Segment Reporting Information
Revenue			(610)	(1,564)	(1,546)
External Customers
Segment Reporting Information
Revenue from contracts with customers			1,680,804	1,726,392	1,748,542
Revenue			1,696,941	1,734,900	1,754,268
External Customers | Electric Utilities
Segment Reporting Information
Revenue from contracts with customers			687,929	684,445	686,272
Revenue			690,130	689,636	688,699
External Customers | Gas Utilities
Segment Reporting Information
Revenue from contracts with customers			959,696	1,007,187	1,022,828
Revenue			969,658	1,007,571	1,023,783
External Customers | Power Generation
Segment Reporting Information
Revenue from contracts with customers			6,090	7,580	5,833
Revenue			7,656	9,439	7,246
External Customers | Mining
Segment Reporting Information
Revenue from contracts with customers			27,089	27,180	33,609
Revenue			29,497	28,254	34,540
External Customers | Other revenues
Segment Reporting Information
Revenue			16,137	8,508	5,726
External Customers | Other revenues | Electric Utilities
Segment Reporting Information
Revenue			2,201	5,191	2,427
External Customers | Other revenues | Gas Utilities
Segment Reporting Information
Revenue			9,962	384	955
External Customers | Other revenues | Power Generation
Segment Reporting Information
Revenue			1,566	1,859	1,413
External Customers | Other revenues | Mining
Segment Reporting Information
Revenue			2,408	1,074	931
Intercompany Customers
Segment Reporting Information
Revenue from contracts with customers			0	0	0
Revenue			0	0	0
Intercompany Customers | Electric Utilities
Segment Reporting Information
Revenue from contracts with customers			23,914	23,116	22,752
Revenue			23,914	23,116	22,752
Intercompany Customers | Gas Utilities
Segment Reporting Information
Revenue from contracts with customers			4,724	2,459	1,524
Revenue			5,012	2,459	1,524
Intercompany Customers | Power Generation
Segment Reporting Information
Revenue from contracts with customers			97,169	91,577	84,959
Revenue			97,391	91,819	85,205
Intercompany Customers | Mining
Segment Reporting Information
Revenue from contracts with customers			31,478	32,053	32,194
Revenue			31,578	33,375	33,493
Intercompany Customers | Intercompany Eliminations
Segment Reporting Information
Revenue from contracts with customers			(157,452)	(149,435)	(141,577)
Revenue			(511,038)	(494,974)	(522,897)
Intercompany Customers | Corporate, Non-Segment
Segment Reporting Information
Revenue from contracts with customers			167	230	148
Revenue			353,143	344,205	379,923
Intercompany Customers | Other revenues
Segment Reporting Information
Revenue			0	0	0
Intercompany Customers | Other revenues | Electric Utilities
Segment Reporting Information
Revenue			0	0	0
Intercompany Customers | Other revenues | Gas Utilities
Segment Reporting Information
Revenue			288	0	0
Intercompany Customers | Other revenues | Power Generation
Segment Reporting Information
Revenue			222	242	246
Intercompany Customers | Other revenues | Mining
Segment Reporting Information
Revenue			100	1,322	1,299
Intercompany Customers | Other revenues | Intercompany Eliminations
Segment Reporting Information
Revenue			(353,586)	(345,539)	(381,320)
Intercompany Customers | Other revenues | Corporate, Non-Segment
Segment Reporting Information
Revenue			$ 352,976	$ 343,975	$ 379,775

Subsequent Events (Details)

Subsequent Events (Details) - USD ($)	Feb. 24, 2021	Oct. 03, 2019	Dec. 31, 2020	Dec. 31, 2019
Subsequent Event [Line Items]
Notes payable			$ 234,040,000	$ 349,500,000
Corporate, Non-Segment
Subsequent Event [Line Items]
Proceeds from Issuance of Debt		$ 700,000,000
Subsequent Event
Subsequent Event [Line Items]
Subsequent Event, Estimated Cost of Incremental Gas Purchases, Due to Historic Cold Weather Event	$ 600,000,000
Subsequent Event | Corporate, Non-Segment | Corporate Term Loan Due November 2021 | Black Hills Corporation
Subsequent Event [Line Items]
Proceeds from Issuance of Debt	$ 800,000,000
Interest rate based on LIBOR plus basis points	75.00%
Prepayment penalty	$ 0
Notes payable	$ 800,000,000