Black Hills (BKH) 10-K 12 Feb 25 2024 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2024	Jan. 31, 2025	Jun. 28, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Current Fiscal Year End Date	--12-31
Document Period End Date	Dec. 31, 2024
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
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 3,763,633,082
Entity Common Stock, Shares Outstanding		71,617,490
Documents Incorporated by Reference	Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2025 Annual Meeting of Stockholders to be held on April 23, 2025 , are incorporated by reference in Part III of this Form 10-K
Entity Central Index Key	0001130464
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	FY
Auditor Opinion [Text Block]	Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 12, 2025, expressed an unqualified opinion on the Company's internal control over financial reporting.

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2024
Audit Information [Abstract]
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Location	Minneapolis, Minnesota
Auditor Firm ID	34

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenue:
Revenue	$ 2,127.7	$ 2,331.3	$ 2,551.8
Operating expenses:
Fuel, purchased power and cost of natural gas sold	730.3	982.9	1,230.6
Operations and maintenance	557	552	548.4
Depreciation and amortization	270.1	256.8	250.9
Taxes other than income taxes	67.2	66.9	66.7
Total operating expenses	1,624.6	1,858.6	2,096.6
Operating income	503.1	472.7	455.2
Other income (expense):
Interest expense incurred net of amounts capitalized	(195.2)	(180)	(162.6)
Interest income	13.5	12.1	1.6
Other income (expense), net	(1.4)	(3.2)	1.8
Total other income (expense)	(183.1)	(171.1)	(159.2)
Income before income taxes	320	301.6	296
Income tax (expense)	(36.3)	(25.6)	(25.2)
Net income	283.7	276	270.8
Net income attributable to non-controlling interest	(10.6)	(13.8)	(12.4)
Net income available for common stock	$ 273.1	$ 262.2	$ 258.4
Earnings per share of common stock:
Earnings per share, Basic (usd per share)	$ 3.91	$ 3.91	$ 3.98
Earnings per share, Diluted (usd per share)	$ 3.91	$ 3.91	$ 3.97
Weighted average common shares outstanding:
Basic (in shares)	69.8	67	64.9
Diluted (in shares)	69.9	67.1	65

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Net income	$ 283.7	$ 276	$ 270.8
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $(0.2), $0, and $(1.5), respectively)	0.8	(0.3)	4.6
Reclassification adjustment of benefit plan liability - net loss (net of tax of $(0.1), $0, and $(0.2), respectively)	0.1	0.2	0.5
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $0, $0, and $0, respectively)			(0.1)
Net unrealized gains (losses) on commodity derivatives (net of tax of $0.1, $1.1, and $0.2, respectively)	(0.5)	(3.6)	(0.6)
Other comprehensive income (loss), net of tax	5.4	0.8	4.5
Comprehensive income	289.1	276.8	275.3
Less: comprehensive income attributable to non-controlling interest	(10.6)	(13.8)	(12.4)
Comprehensive income available for common stock	278.5	263	262.9
Interest rate swaps
Other comprehensive income (loss), net of tax:
Other comprehensive income (loss), cash flow hedge, gain (loss), reclassification, after tax	2.3	2.2	2.1
Commodity derivatives
Other comprehensive income (loss), net of tax:
Other comprehensive income (loss), cash flow hedge, gain (loss), reclassification, after tax	$ 2.7	$ 2.3	$ (2)

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parentheticals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
(Tax) benefit on benefit plan liability adjustments - net gain (loss)	$ (0.2)	$ 0	$ (1.5)
(Tax) benefit on benefit plan liability adjustments - prior service costs	0	0	0
(Tax) benefit on reclassification adjustment of benefit plan liability - net loss	(0.1)	0	(0.2)
Interest Rate Swap
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification,Tax (Benefit)	(0.6)	(0.7)	(0.7)
Commodity Contract
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification,Tax (Benefit)	(0.8)	(0.7)	0.7
(Tax) benefit on net unrealized gains (losses) on commodity derivatives	$ 0.1	$ 1.1	$ 0.2

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Current assets:
Cash and cash equivalents	$ 16.1	$ 86.6
Restricted cash and equivalents	7.3	6.4
Accounts receivable, net	351.2	350.3
Materials, supplies and fuel	153.9	160.9
Income tax receivable, net	19.8	18.5
Regulatory assets, current	154.8	175.7
Other current assets	39.2	28.2
Total current assets	742.3	826.6
Property, plant and equipment	9,566.5	8,917.2
Less accumulated depreciation and depletion	(1,936.6)	(1,797.9)
Total property, plant and equipment, net	7,629.9	7,119.3
Other assets:
Goodwill	1,299.5	1,299.5
Intangible assets, net	7.6	8.4
Regulatory assets, non-current	272.9	304.4
Other assets, non-current	70.4	62.2
Total other assets, non-current	1,650.4	1,674.5
TOTAL ASSETS	10,022.6	9,620.4
Current liabilities:
Accounts payable	229.1	186.4
Accrued liabilities	302.2	293.3
Derivative liabilities, current	4.2	6.5
Regulatory liabilities, current	94.1	98.9
Notes payable	133.8	0
Current maturities of long-term debt	0	600
Total current liabilities	763.4	1,185.1
Long-term debt, net of current maturities	4,250.2	3,801.2
Deferred credits and other liabilities:
Deferred income tax liabilities, net	625.1	548
Regulatory liabilities, non-current	474.6	467.7
Benefit plan liabilities	122.9	123.9
Other deferred credits and other liabilities	201.2	188.7
Total deferred credits and other liabilities	1,423.8	1,328.3
Commitments, contingencies and guarantees (Note 3)
Equity:
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 71,676,756 and 68,265,042, respectively	71.7	68.3
Additional paid-in capital	2,193.4	2,007.7
Retained earnings	1,249.1	1,158.2
Treasury stock at cost - 56,608 and 68,073, respectively	(3.3)	(4.1)
Accumulated other comprehensive income (loss)	(9.4)	(14.8)
Total stockholders’ equity	3,501.5	3,215.3
Non-controlling interest	83.7	90.5
Total equity	3,585.2	3,305.8
TOTAL LIABILITIES AND TOTAL EQUITY	$ 10,022.6	$ 9,620.4

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2024	Dec. 31, 2023
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	71,676,756	68,265,042
Treasury stock, shares	56,608	68,073

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating activities:
Net income	$ 283.7	$ 276	$ 270.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	270.1	256.8	250.9
Deferred financing cost amortization	10.7	10.1	9.8
Stock compensation	10.6	7	8.6
Deferred income taxes	52	25.4	25.6
Employee benefit plans	11.2	11.5	5.5
Other adjustments, net	(4.1)	2.7	(4.7)
Change in certain operating assets and liabilities:
Materials, supplies and fuel	13.2	51.4	(75.4)
Accounts receivable and other current assets	(25.7)	204.5	(184.5)
Accounts payable and other current liabilities	28.8	(109.9)	89.4
Regulatory assets	90	236.8	203.9
Other operating activities, net	(21.2)	(27.9)	(15.1)
Net cash provided by operating activities	719.3	944.4	584.8
Investing activities:
Property, plant and equipment additions	(744.2)	(555.6)	(604.4)
Other investing activities	(1.8)	18.9	0.5
Net cash (used in) investing activities	(746)	(536.7)	(603.9)
Financing activities:
Dividends paid on common stock	(182.3)	(168.1)	(156.7)
Common stock issued	181.4	118.3	90.1
Net borrowings (payments) of Revolving Credit Facility and CP Program	133.8	(535.6)	115.4
Long-term debt - issuance	450	800	0
Long-term debt - repayments	(600)	(525)	0
Distributions to non-controlling interests	(17.4)	(18.3)	(17.4)
Other financing activities	(8.4)	(13)	0.9
Net cash provided by (used in) financing activities	(42.9)	(341.7)	32.3
Net change in cash, restricted cash and cash equivalents	(69.6)	66	13.2
Cash, restricted cash and cash equivalents beginning of year	93	27	13.8
Cash, restricted cash and cash equivalents end of year	23.4	93	27
Supplemental cash flow information:
Interest (net of amounts capitalized)	(174.4)	(157.3)	(152.5)
Income taxes net of transferred tax credits (Note 15)	14.4	(1)	0.8
Accrued property, plant and equipment purchases at December 31	80.2	52.4	59.3
Increase in capitalized assets associated with asset retirement obligations	$ 0.4	$ 3.8	$ 14

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interest
Beginning balance (in shares) at Dec. 31, 2021		64,793,095	54,078
Beginning balance at Dec. 31, 2021	$ 2,887	$ 64.8	$ (3.5)	$ 1,783.4	$ 962.4	$ (20.1)	$ 100
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	270.8				258.4		12.4
Other comprehensive income, net of tax	4.5					4.5
Dividends on common stock	(156.7)				(156.7)
Share-based compensation (in shares)		39,546	(17,352)
Share-based compensation	11.6		$ 1.1	10.5
Issuance of common stock (in shares)		1,307,755
Issuance of common stock	91.2	$ 1.3		89.9
Issuance costs	(1.1)			(1.1)
Distributions to non-controlling interest	(17.4)						(17.4)
Ending balance (in shares) at Dec. 31, 2022		66,140,396	36,726
Ending balance at Dec. 31, 2022	3,089.9	$ 66.1	$ (2.4)	1,882.7	1,064.1	(15.6)	95
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	276				262.2		13.8
Other comprehensive income, net of tax	0.8					0.8
Dividends on common stock	(168.1)				(168.1)
Share-based compensation (in shares)		93,257	31,347
Share-based compensation	7.2	$ 0.1	$ (1.7)	8.8
Issuance of common stock (in shares)		2,031,389
Issuance of common stock	120	$ 2.1		117.9
Issuance costs	(1.7)			(1.7)
Distributions to non-controlling interest	(18.3)						(18.3)
Ending balance (in shares) at Dec. 31, 2023		68,265,042	68,073
Ending balance at Dec. 31, 2023	3,305.8	$ 68.3	$ (4.1)	2,007.7	1,158.2	(14.8)	90.5
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	283.7				273.1		10.6
Other comprehensive income, net of tax	5.4					5.4
Dividends on common stock	(182.3)				(182.3)
Share-based compensation (in shares)		113,824	(11,465)
Share-based compensation	8.6	$ 0.1	$ 0.8	7.6	0.1
Issuance of common stock (in shares)		3,297,890
Issuance of common stock	183.4	$ 3.3		180.1
Issuance costs	(2)			(2)
Distributions to non-controlling interest	$ (17.4)						(17.4)
Ending balance (in shares) at Dec. 31, 2024	71,700,000	71,676,756	56,608
Ending balance at Dec. 31, 2024	$ 3,585.2	$ 71.7	$ (3.3)	$ 2,193.4	$ 1,249.1	$ (9.4)	$ 83.7

Consolidated Statements of Eq_2

Consolidated Statements of Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Stockholders' Equity [Abstract]
Dividends on common stock (usd per share)	$ 2.6	$ 2.5	$ 2.41

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net Income (Loss)	$ 273.1	$ 262.2	$ 258.4

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2024
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false
Rule 10b5-1 Arr Modified [Flag]	false
Non Rule 10b51 Arr Modified [Flag]	false

Cybersecurity Risk Management,

Cybersecurity Risk Management, Strategy and Governance	12 Months Ended
	Dec. 31, 2024
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	ITEM 1C. CYBERSECURITY The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other nation state actors, and individuals. In addition, the advancement of AI has given rise to additional vulnerabilities and potential entry points for cyberattacks. We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure, and other assets. To date, we have not experienced a cybersecurity incident that has had a material impact on our business or results of operations. Risk Management and Strategy Our enterprise risk management program, which includes cybersecurity risks that are identified through our cybersecurity risk management program, is designed to identify, report, and manage relevant material risks and opportunities. Management of the identified risks is embedded into business processes and key decision making at every level of the Company. Our enterprise risk management team works closely with our CSO and IT risk management team to evaluate and address material cybersecurity risks in alignment with our business strategy and operational needs. We have a cybersecurity risk management program that is managed by a team of full-time cybersecurity professionals that utilizes a variety of tools and techniques to identify and assess material cybersecurity threats, their potential impact and opportunities for mitigation. The industry-standard security frameworks that we apply to our cyber environment include various security and risk assessments, such as internal threat assessments and internal control self-assessments. Because we are aware of the risks associated with third-party providers, we conduct third-party provider security assessments and benchmarking before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. These assessments include evaluation of risk profiles through vendor questionnaires, review of System and Organization Controls attestation reports and monitoring on an ongoing basis by our IT risk management team. This approach is designed to mitigate risks related to data breaches or other security incidents originating from third-parties. We regularly engage with third-party assessors and auditors as part of our ongoing cybersecurity risk assessment process to leverage specialized knowledge and insights and to identify areas for continued focus, improvement, compliance, and effectiveness of mitigation. We also utilize government and industry-related security intelligence sources, and actively participate in industry peer groups and public-private partnerships to assist in the identification of potential threats. We conduct ongoing cybersecurity training and monthly email phishing drills for all employees. We also have a cybersecurity incident response plan and procedures to manage cybersecurity incidents. These procedures include steps to identify, classify, communicate, contain, eradicate, and recover from a cybersecurity incident . These procedures also include notification to a cross-functional management team to assess incident materiality and an escalation process to members of our senior management team and our Board of Directors. Governance Our Board of Directors is responsible for the oversight of risks from cybersecurity threats. Our Chief Information Officer provides our Board of Directors quarterly reports that summarize material cybersecurity threats and the countermeasures taken to mitigate the associated risks. These reports address a variety of topics including updates on strategic cyber initiatives, industry trends, threat vulnerability assessments, and efforts to prevent, detect, and respond to internal and external critical threats. From time to time, our Board of Directors also engages third-party consultants to provide further education about cybersecurity risks. Our cybersecurity risk management program, which is discussed above, is led by our CSO, who has 34 years of experience in various roles involving managing information security of large-scale global security operations, including developing cybersecurity strategy and implementing effective information and cybersecurity programs. Our CSO maintains industry certifications, including an ISC2 Certified Information Systems Security Professional certification. Through oversight of the cybersecurity risk management program, our CSO is continually informed about the status of the program, including the effectiveness of the process and controls to monitor, prevent, detect, mitigate, and remediate cybersecurity incidents. The CSO is also made aware of the latest developments in cybersecurity, including potential threats and innovative risk management techniques. The CSO, in his capacity, regularly informs the Chief Information Officer and other members of our senior management team of all aspects related to cybersecurity risks and incidents.
Cybersecurity Risk Management Processes Integrated [Text Block]	Our enterprise risk management program, which includes cybersecurity risks that are identified through our cybersecurity risk management program, is designed to identify, report, and manage relevant material risks and opportunities. Management of the identified risks is embedded into business processes and key decision making at every level of the Company. Our enterprise risk management team works closely with our CSO and IT risk management team to evaluate and address material cybersecurity risks in alignment with our business strategy and operational needs.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Text Block]	To date, we have not experienced a cybersecurity incident that has had a material impact on our business or results of operations.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our Board of Directors is responsible for the oversight of risks from cybersecurity threats.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	. These procedures also include notification to a cross-functional management team to assess incident materiality and an escalation process to members of our senior management team and our Board of Directors.
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Our Chief Information Officer provides our Board of Directors quarterly reports that summarize material cybersecurity threats and the countermeasures taken to mitigate the associated risks. These reports address a variety of topics including updates on strategic cyber initiatives, industry trends, threat vulnerability assessments, and efforts to prevent, detect, and respond to internal and external critical threats.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our cybersecurity risk management program, which is discussed above, is led by our CSO, who has 34 years of experience in various roles involving managing information security of large-scale global security operations, including developing cybersecurity strategy and implementing effective information and cybersecurity programs. Our CSO maintains industry certifications, including an ISC2 Certified Information Systems Security Professional certification.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	We also have a cybersecurity incident response plan and procedures to manage cybersecurity incidents. These procedures include steps to identify, classify, communicate, contain, eradicate, and recover from a cybersecurity incident .
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Business Description And Signif

Business Description And Significant Accounting Policies	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Business Description and Significant Accounting Policies	(1) 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 and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. All intercompany balances and transactions have been eliminated in consolidation. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned facility. See Note 6 for additional information. Non-controlling 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 non-controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the non-controlling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 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, non-controlling 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 non-controlling 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 Note 12 for additional information. Cash, 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. Revenue Recognition 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 segment has 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. The majority of our revenue contracts are based on variable quantities delivered. Typically, our customers are billed monthly with payment due within 20 days. Any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration 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 tables in Note 4 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 substantially all of our revenue contracts provides an unconditional right to consideration upon service delivery. Customer billings (and subsequent customer payments of those bills) occur after service delivery. Therefore, customer contract assets or liabilities do not exist. The unconditional right to consideration is represented by the balance in our Accounts receivable, which is further discussed below. See Note 4 for additional information. Accounts Receivable and Allowance for Credit Losses Accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses, and do not bear interest. 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 collectability. 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 setoff exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Following is a summary of accounts receivable as of December 31: 2024 2023 (in millions) Billed Accounts Receivable $ 201.5 $ 198.5 Unbilled Revenue 151.8 154.0 Less Allowance for Credit Losses ( 2.1 ) ( 2.2 ) Accounts Receivable, net $ 351.2 $ 350.3 Changes to allowance for credit losses for the years ended December 31, were as follows: Balance at Additions Recoveries and Write-offs and Balance at (in millions) 2024 $ 2.2 $ 5.6 $ 4.2 $ ( 9.9 ) $ 2.1 2023 $ 3.0 $ 8.7 $ 4.1 $ ( 13.6 ) $ 2.2 2022 $ 2.1 $ 9.1 $ 3.5 $ ( 11.7 ) $ 3.0 Materials, Supplies, and Fuel Materials and supplies represent parts and supplies for our business operations. Fuel represents diesel oil and gas used by our electric generating facilities 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. The following amounts by major classification are included in Materials, supplies, and fuel on the accompanying Consolidated Balance Sheets as of December 31: 2024 2023 (in millions) Materials and supplies $ 106.1 $ 105.9 Fuel 7.5 7.7 Natural gas in storage 40.3 47.3 Total materials, supplies, and fuel $ 153.9 $ 160.9 Property, Plant, and Equipment Property, plant, and equipment are stated at cost, which includes construction-related direct labor and material costs, indirect construction costs including labor and related costs of departments associated with supporting construction activities, and AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost. We also classify our Cushion Gas as Property, plant, and equipment. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are expensed as incurred. We receive CIACs from third parties that are generally intended to defray all or a portion of the costs for certain capital projects. Such CIAC costs are recorded as a reduction to Property, plant, and equipment. The cost of regulated utility property, plant, and equipment retired, or otherwise disposed 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 operating assets which result in gains or losses are recognized within Operations and maintenance expense. See Note 5 for additional information. Depreciation 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. Depreciation studies are conducted periodically to update composite rates and are approved by state utility commissions and/or the FERC when required. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-regulated power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. AFUDC 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. The following table presents AFUDC amounts for the years ended December 31: Income Statement Location 2024 2023 2022 (in millions) AFUDC Debt Interest expense incurred, net of amounts capitalized $ 8.7 $ 6.0 $ 5.6 AFUDC Equity Other income (expense), net 4.0 0.4 0.6 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. 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, and regulated operations without a corresponding recovery mechanism, is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations with a regulatory mechanism 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. See Note 7 for additional information. 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, or components of an operating segment. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. We believe that goodwill reflects the inherent value of the relatively stable, long-lived cash flows of our Utilities businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our Utilities, and those businesses vertically integrated. Goodwill amounts have not changed since 2016. As of December 31, 2024, and 2023, Goodwill balances were as follows: Electric Utilities Gas Utilities Total (in millions) Goodwill $ 257.3 $ 1,042.2 $ 1,299.5 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 1 years to 17 years. C hanges to intangible assets for the years ended December 31, were as follows: 2024 2023 2022 (in millions) Intangible assets, net, beginning balance $ 8.4 $ 9.6 $ 10.8 Additions 0.3 — — Amortization expense (a) ( 1.1 ) ( 1.2 ) ( 1.2 ) Intangible assets, net, ending balance $ 7.6 $ 8.4 $ 9.6 (a) Amortization expense for existing intangible assets is expected to b e $ 1.2 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: 2024 2023 (in millions) Accrued employee compensation, benefits and withholdings $ 85.5 $ 74.8 Accrued property taxes 54.7 52.7 Customer deposits and prepayments 55.6 76.0 Accrued interest 56.4 46.3 Other (none of which is individually significant) 50.0 43.5 Total accrued liabilities $ 302.2 $ 293.3 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 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 credit valuation adjustment 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. See Notes 10 and 13 for additional information. 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 pricing is clearly and closely related to the asset being purchased or sold. 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 setoff 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 setoff exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures. The cash impacts of settled derivatives are recorded as operating activities on the Consolidated Statements of Cash Flows. See Notes 9 , 10, and 11 for additional information. Debt Discounts, Premiums, and Deferred Financing Costs Deferred financing costs include loan origination fees, underwriter fees, legal fees, and other costs directly attributable to the issuance of debt. Debt discounts, premiums, and deferred financing costs are amortized over the estimated useful life of the related debt. Unamortized discounts, premiums, and deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. See Note 8 for additional information. Regulatory Accounting Our regulated Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our 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. See Note 2 for additional information. Income Taxes The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. The Company and its subsidiaries file consolidated federal income tax returns. Each subsidiary records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) on the Consolidated Statements of Income. We have elected to account for transferable renewable tax credits, including PTCs and ITCs, as a reduction to income taxes payable under the scope of ASC 740 Income Taxes . We include the discount from the sale of our tax credits as a component of income tax expense. The sale of tax credits is presented within Operating activities in the Consolidated Statement of Cash Flows consistent with the presentation of cash taxes paid. For renewable tax credits subject to future transfer, a valuation allowance is recorded for the difference between the tax value of the credits and the expected sales price. Tax credits and any related valuation allowances are derecognized when control of the tax credits is transferred to other corporate taxpayers. See Notes 3 and 15 for further discussion of the transfer of renewable tax credits to other corporate taxpayers, including related indemnification requirements and valuation allowances, respectively. We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information. Earnings per Share of Common Stock Basic earnings per share is computed by dividing Net income available for common stock 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, as calculated using the treasury stock method. 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: 2024 2023 2022 (in millions, except per share amounts) Net income available for common stock $ 273.1 $ 262.2 $ 258.4 Weighted average shares - basic 69.8 67.0 64.9 Dilutive effect of equity compensation 0.1 0.1 0.1 Weighted average shares - diluted 69.9 67.1 65.0 Net income available for common stock, per share - Diluted $ 3.91 $ 3.91 $ 3.97 Anti-dilutive shares excluded from the diluted earnings per share computation were not material for the years ended December 31, 2024, 2023, and 2022. 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 Note 14 for additional information. Pension and Other Retiree Plans We recognize on our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other retiree plans with current-year changes in actuarial gains or losses recognized in AOCI, except for those plans at certain of our regulated utilities that can recover portions of their pension and retiree obligations through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of ASC 715, Compensation-Retirement Benefit s, which require a year-end measurement date of plan assets and obligations for all defined benefit plans. Recently Issued Accounting Standards Improvements to Income Tax Disclosures, ASU 2023-09 In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which expands public entities’ annual disclosures by requiring disclosure of tax rate reconciliation amoun

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2024
Regulated Operations [Abstract]
Regulatory Matters	(2) REGULATORY MATTERS We had the following regulatory assets and liabilities as of December 31: 2024 2023 (in millions) Regulatory assets Winter Storm Uri (a) $ 109.5 $ 199.6 Deferred energy and fuel cost adjustments (b) 62.8 55.1 Deferred gas cost adjustments (b) 14.5 4.1 Gas price derivatives (b) 2.9 5.1 Deferred taxes on AFUDC (b) 8.0 7.1 Employee benefit plans and related deferred taxes (c) 89.0 89.3 Environmental (b) 10.7 2.9 Loss on reacquired debt (b) 15.7 17.4 Deferred taxes on flow-through accounting (b) 87.7 74.7 Decommissioning costs (b) 2.4 2.4 Other regulatory assets (b) 24.5 22.4 Total regulatory assets 427.7 480.1 Less current regulatory assets ( 154.8 ) ( 175.7 ) Regulatory assets, non-current $ 272.9 $ 304.4 Regulatory liabilities Deferred energy and gas costs (b) $ 91.9 $ 88.9 Employee benefit plans and related deferred taxes (c) 36.7 36.2 Cost of removal (b) 197.0 181.9 Excess deferred income taxes (c) 238.5 247.1 Other regulatory liabilities (c) 4.6 12.5 Total regulatory liabilities 568.7 566.6 Less current regulatory liabilities ( 94.1 ) ( 98.9 ) Regulatory liabilities, non-current $ 474.6 $ 467.7 (a) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below. (b) Recovery/repayment of costs, but we are not 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. Winter Storm Uri - Our Utilities received commission approval to recover incremental fuel, purchased power, and natural gas costs associated with Winter Storm Uri. In certain jurisdictions, we also received commission approval to recover carrying costs. As of December 31, 2024, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period o f 1.6 years. 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. 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 monthly, quarterly, semi-annual, and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions. 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, 2024 , are hedged over a maximum forward term of two years . Deferred Taxes on AFUDC - The equity component of AFUDC is considered a temporary difference for tax purposes with the tax detriment 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 are 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. 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 net 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. 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 Plans 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 ASC 715, Compensation-Retirement Benefits . In addition, this regulatory liability includes the income tax effect of the adjustment required under ASC 715, Compensation-Retirement Benefits , 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 excess deferred income taxes to be refunded to customers primarily using the normalization principles as prescribed in 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. Recent Rate Review Activity Arkansas Gas On December 4, 2023, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200 -mile natural gas pipeline system. On October 1, 2024, Arkansas Gas received final approval for a settlement agreement for a general rate increase which is expected to generate $ 25.4 million of new annual revenue and shift $ 3.7 million of rider revenue to base rates. The approval allows a capital structure of 46 % equity and 54 % debt and a return on equity of 9.9 %. New rates were effective October 14, 2024. Colorado Electric On June 14, 2024, Colorado Electric filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 3,200 -mile electric distribution and 600 -mile electric transmission systems. The rate review requested $ 36.7 million in new annual revenue with a capital structure of 53 % equity and 47 % debt and a return on equity of 10.5 %. On November 22, 2024, Colorado Electric submitted rebuttal testimony, which updated its request to $ 25.1 million in new annual review with a capital structure of 53 % equity and 47 % debt and a return on equity of 9.8 %. A final CPUC decision on the request is expected first quarter or early second quarter of 2025. Timing and implementation of new rates will be subject to a final decision. Colorado Gas On May 9, 2023, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 10,000 -mile natural gas pipeline system. In March 2024, Colorado Gas received final approval for a settlement agreement for a general rate increase which is expected to generate $ 20.2 million of new annual revenue with a capital structure of 51 % equity and 49 % debt and a return on equity of 9.3 %. Final rates were enacted on May 1, 2024, which replaced interim rates. Iowa Gas On May 1, 2024, Iowa Gas filed a rate review with the IUC seeking recovery of significant infrastructure investments in its 5,000 -mile natural gas pipeline system. On December 2 , 2024, Iowa Gas received final approval from the IUC for a settlement agreement for a general rate increase. T he approved Black-box Settlement is expected to generate $ 15.0 million of new annual revenue based on a weighted average cost of capital of 7.2 %. New rates were enacted on January 1, 2025, which replaced interim rates. Kansas Gas On February 3, 2025, Kansas Gas filed a rate review with the KCC seeking recovery of significant infrastructure investments in its 4,765 -mile natural gas pipeline system. The rate review requests $ 17.2 million in new annual revenue with a capital structure of 50 % equity and 50 % debt and a return on equity of 10.5 %. The request seeks to implement new rates in the second half of 2025. Wyoming Gas On May 18, 2023, Wyoming Gas filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 6,400 -mile natural gas pipeline system. On January 17, 2024, the WPSC approved a settlement agreement for a general rate increase which is expected to generate $ 13.9 million in new annual revenue with a capital structure of 51 % equity and 49 % debt and a return on equity of 9.85 %. New rates were effective February 1, 2024. The agreement also included approval of a four-year extension of the Wyoming Integrity Rider.

Commitment, Contingencies And G

Commitment, Contingencies And Guarantees	12 Months Ended
	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
Commitments, Contingencies and Guarantees	(3) COMMITMENTS, CONTINGENCIES, AND GUARANTEES Unconditional Purchase Obligations We have various PPAs and transmission service agreements, which extend to 2044, to support our Electric Utilities' capacity and energy needs beyond our regulated power plants' generation. Our Utilities 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: PPAs (a) Transmission Services Agreements Natural gas supply, transportation and storage agreements (in millions) Future commitments for the year ending December 31, 2025 $ — $ 12.3 $ 193.8 2026 — — 171.2 2027 — — 136.5 2028 — — 86.6 2029 — — 23.0 Thereafter — — 109.0 Total future commitments $ — $ 12.3 $ 720.1 ____________________ (a) This schedule does not reflect renewable energy PPA future obligations since these agreements vary based on weather conditions. Lease Agreements Lessee We lease from third parties certain office and operation ce nter facilities, communication tower sites, equipment, and materials storage. Our leases have remaining terms ranging from less than one year to 31 years , including options to extend that are reasonably certain to be exercised. Our operating and finance leases were not material to the Company’s Consolidated Financial statements. 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 31 years . Le ase revenue was not material for the years ended December 31, 2024, 2023, and 2022. As of December 31, 2024, scheduled maturities of operating lease payments to be received in future years were as follows: Operating Leases (in millions) 2025 $ 2.1 2026 3.1 2027 1.8 2028 1.8 2029 1.8 Thereafter 48.4 Total lease receivables $ 59.0 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 Liabilities For our Pueblo Airport Generation site, we posted a bond 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 Plants In 20 08, we acquired whole and partial liabilities for former manufactured gas plant sites in Nebraska and Iowa, which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $ 1.5 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. In 2024, we increased our Iowa manufactured gas plant site remediation cost estimate by $ 7.4 million based on recent site investigations and remediation work completed, which resulted in a corresponding increase in our Accrued liabilities and Regulatory assets. As of December 31, 2024, we had an Accrued liability of $ 9.7 million and a Regulatory asset of $ 10.7 million on our Consolidated Balance Sheets for the remediation of the manufactured gas plant site in Iowa. S ee Note 2 for additional information. As of December 31, 2024, we had $ 0.6 million accrued for remediation of the manufactured gas plant sites in Nebraska, which are included in Other deferre d credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimates could change materially due to results of further investigations, actions of environmental agencies, or the financial viability of other responsible parties. Contingencies and 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. We record gain contingencies when realized and expected recoveries under applicable insurance contracts when we are assured of recovery. GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (U.S. District Court for the City and County of Denver, Colorado) On April 13, 2022, a jury awarded $ 41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3 million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. GTR retained rights to receive a royalty interest on any hydrocarbon production from the concession upon the occurrence of contingent events. GTR contended that BHC and its subsidiaries failed to adequately pursue the opportunity and failed to transfer the concession to GTR. We appealed this verdict to the Colorado Court of Appeals. On October 19, 2023, the Appellate Court reversed and remanded the case with directions limiting any retrial to the narrow issue of whether there was improper interference with the prospective conveyance of the concession. We continue to believe this lawsuit has no merit and will vigorously defend it. At this time, we do not believe any losses from this matter will have a material impact on our financial position, results of operations and cash flows. Indemnification 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. Transfers of Renewable Tax Credits In June 2024, we entered into an agreement with a third party to sell our 2023 generated PTCs. In January 2025, we entered into a similar agreement with the same third party to sell our 2024 generated PTCs. In each of these agreements, we provided indemnifications associated with the proceeds for PTCs transferred to the third party in the event of an adverse interpretation of tax law, including whether the related tax credits meet the qualification requirements. Additionally, in our agreement for the sale of our 2024 generated PTCs, we provided indemnifications in the event of a change in tax law. We believe the likelihood of having to make any material cash payments under these indemnifications is remote. See Note 15 for additional information. Guarantees We have entered into various parent company-level guarantees providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. These guarantees do not represent incremental consolidated obligations, but rather, represent guarantees of subsidiary obligations to allow those subsidiaries to conduct business without posting other forms of assurance. The agreements, which are off-balance sheet commitments, include support for business operations, 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 these guarantees, such liabilities are included in our Consolidated Balance Sheets. We had the following guarantees in place as of: Maximum Exposure at Nature of Guarantee December 31, 2024 (in millions) Indemnification for reclamation/surety bonds $ 75.6 Guarantees supporting business transactions 499.8 Total guarantees $ 575.4

Revenue

Revenue	12 Months Ended
	Dec. 31, 2024
Revenue from Contract with Customer [Abstract]
Revenue	(4) 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, 2024, 2023, and 2022. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2024 Electric Utilities Gas Utilities Inter-segment Eliminations Total Customer types: (in millions) Retail $ 698.6 $ 1,022.6 $ — $ 1,721.2 Transportation — 178.2 ( 0.4 ) 177.8 Wholesale 26.8 — — 26.8 Market - off-system sales 34.8 0.1 — 34.9 Transmission 52.2 0.7 — 52.9 Other revenues 58.7 43.1 ( 17.4 ) 84.4 Revenue from contracts with customers 871.1 1,244.7 ( 17.8 ) 2,098.0 Alternative revenue and other 5.0 24.7 — 29.7 Total revenues $ 876.1 $ 1,269.4 $ ( 17.8 ) $ 2,127.7 Timing of revenue recognition: Services transferred at a point in time $ 34.7 $ — $ — $ 34.7 Services transferred over time 836.4 1,244.7 ( 17.8 ) 2,063.3 Revenue from contracts with customers $ 871.1 $ 1,244.7 $ ( 17.8 ) $ 2,098.0 Year ended December 31, 2023 Electric Utilities Gas Utilities Inter-segment Eliminations Total Customer types: (in millions) Retail $ 666.1 $ 1,248.8 $ — $ 1,914.9 Transportation — 176.8 ( 0.5 ) 176.3 Wholesale 34.2 — — 34.2 Market - off-system sales 50.9 0.4 — 51.3 Transmission 47.1 0.7 — 47.8 Other revenues 55.9 38.7 ( 17.4 ) 77.2 Revenue from contracts with customers 854.2 1,465.4 ( 17.9 ) 2,301.7 Alternative revenue and other 10.8 18.8 — 29.6 Total revenues $ 865.0 $ 1,484.2 $ ( 17.9 ) $ 2,331.3 Timing of revenue recognition: Services transferred at a point in time $ 31.5 $ — $ — $ 31.5 Services transferred over time 822.7 1,465.4 ( 17.9 ) 2,270.2 Revenue from contracts with customers $ 854.2 $ 1,465.4 $ ( 17.9 ) $ 2,301.7 Year ended December 31, 2022 Electric Utilities Gas Utilities Inter-segment Eliminations Total Customer types: (in millions) Retail $ 709.2 $ 1,453.3 $ — $ 2,162.5 Transportation — 173.3 ( 0.4 ) 172.9 Wholesale 44.8 — — 44.8 Market - off-system sales 48.6 0.8 — 49.4 Transmission 40.5 0.8 — 41.3 Other revenues 51.5 37.1 ( 16.6 ) 72.0 Revenue from contracts with customers 894.6 1,665.3 ( 17.0 ) 2,542.9 Alternative revenue and other 5.6 3.8 ( 0.5 ) 8.9 Total revenues $ 900.2 $ 1,669.1 $ ( 17.5 ) $ 2,551.8 Timing of revenue recognition: Services transferred at a point in time $ 30.4 $ — $ — $ 30.4 Services transferred over time 864.2 1,665.3 ( 17.0 ) 2,512.5 Revenue from contracts with customers $ 894.6 $ 1,665.3 $ ( 17.0 ) $ 2,542.9

Property, Plant And Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	(5) PROPERTY, PLANT, AND EQUIPMENT Property, plant, and equipment at December 31 consisted of the following: 2024 2023 Lives Electric Utilities Property, Plant and Equipment Weighted Average Useful Life Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum (dollars in millions, life in years) (in years) Electric plant: Production $ 1,508.5 39 $ 1,492.8 40 32 44 Electric transmission 793.7 48 737.4 48 42 51 Electric distribution 1,238.5 47 1,146.9 47 45 50 Integrated Generation 724.0 30 720.0 30 19 38 Plant acquisition adjustment (a) 4.9 32 4.9 32 32 32 General 306.6 26 291.7 27 23 27 Total electric plant in service 4,576.2 4,393.7 Construction work-in-progress 259.4 123.1 Total electric plant 4,835.6 4,516.8 Less accumulated depreciation ( 1,280.3 ) ( 1,207.7 ) Electric plant net of accumulated depreciation $ 3,555.3 $ 3,309.1 ____________________ (a) The plant acquisition adjustment, which relates to the acquisition of our ownership interest in Wyodak Plant, is included in rate base and is being recovered w ith 6 years remaining. 2024 2023 Lives Gas Utilities Property, Plant and Equipment Weighted Average Useful Life Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum (dollars in millions, life in years) (in years) Gas plant: Production $ 21.6 43 $ 21.0 45 24 45 Gas transmission 817.5 58 759.5 58 32 73 Gas distribution 3,107.3 57 2,860.0 57 48 61 Cushion gas - not depreciable (a) 52.1 N/A 58.2 N/A N/A N/A Storage 78.8 42 71.4 42 36 48 General 599.4 22 571.8 22 20 24 Total gas plant in service 4,676.7 4,341.9 Construction work-in-progress 43.5 39.2 Total gas plant 4,720.2 4,381.1 Less accumulated depreciation ( 656.3 ) ( 588.3 ) Gas plant net of accumulated depreciation $ 4,063.9 $ 3,792.8 ____________________ (a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. 2024 2023 Lives Corporate Property, Plant and Equipment Weighted Average Useful Life Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum (dollars in millions, life in years) (in years) Total plant in service $ 0.4 10 $ 5.7 10 4 21 Construction work-in-progress 10.3 13.6 Total gross property, plant and equipment 10.7 19.3 Less accumulated depreciation — ( 1.9 ) Total net of accumulated depreciation $ 10.7 $ 17.4

Jointly Owned Facilities

Jointly Owned Facilities	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Jointly Owned Facilities	(6) JOINTLY OWNED FACILITIES Our consolidated financial statements include our share of several jointly-owned facilities as described below. Our share of the facilities’ expenses is 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. At December 31, 2024, our interests in jointly-owned generating facilities and transmission systems were: Ownership Interest Plant in Service Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation (in millions) Wyodak Plant (a) 20 % $ 123.0 $ — $ ( 76.8 ) $ 46.2 Transmission Tie 35 % $ 24.5 $ 0.3 $ ( 8.3 ) $ 16.5 Wygen III (b) 52 % $ 144.8 $ 0.3 $ ( 33.0 ) $ 112.1 Wygen I (c) 76.5 % $ 116.3 $ 1.9 $ ( 61.6 ) $ 56.6 (a) In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our mine supplies PacifiCorp’s share of the coal under a separate long-term agreement through December 31, 2026, with an annual renewal option for one-year extensions. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves. (b) South Dakota Electric retains responsibility for plant operations. WRDC supplies fuel to Wygen III for the life of the plant. (c) Black Hills Wyoming retains responsibility for plant operations. WRDC supplies fuel to Wygen I for the life of the plant.

Asset Retirement Obligations_

Asset Retirement Obligations:	12 Months Ended
	Dec. 31, 2024
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	(7) ASSET RETIREMENT OBLIGATIONS We have identified legal obligations related to reclamation of mining sites; removal of fuel tanks, transformers containing polychlorinated biphenyls, an evaporation pond; and reclamation of wind turbine sites at our Electric Utilities segment. In addition, we have identified legal obligations related to retirement of gas pipelines, wells, and compressor stations at our Gas Utilities and removal of asbestos at our Utilities. We periodically review and update estimated costs related to these AROs. The actual cost may vary from estimates due to regulatory requirements, changes in technology and increased labor, materials, and equipment costs. The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities: December 31, 2023 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2024 (in millions) Electric Utilities $ 28.7 $ — $ — $ 1.1 $ 0.2 $ 30.0 Gas Utilities 67.5 0.2 — 3.0 — 70.7 Total $ 96.2 $ 0.2 $ — $ 4.1 $ 0.2 $ 100.7 December 31, 2022 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2023 (in millions) Electric Utilities $ 27.6 $ — $ — $ 1.2 $ ( 0.1 ) $ 28.7 Gas Utilities (a) 61.3 6.7 — 2.3 ( 2.8 ) 67.5 Total $ 88.9 $ 6.7 $ — $ 3.5 $ ( 2.9 ) $ 96.2 (a) The Revisions to Prior Estimates were primarily driven by changes in estimates associated with natural gas wells and compressor stations. 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.

Financing

Financing	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Financing	(8) FINANCING Shelf Registration Statement We maintain an effective shelf registration statement (Registration No. 333-272739) with the SEC under which we may issue, from time to time, an unspecified amount of senior debt securities, subordinate debt securities, common stock, preferred stock, warrants, and other securities. Short-term debt Revolving Credit Facility and CP Program On May 31, 2024, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $ 750 million and extending the term through May 31, 2029, with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us to increase total commitments up to $ 1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment. Borrowings continue to be available under a base rate or various SOFR 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 and Moody's for our senior unsecured long-term debt. Based on our current credit ratings, the margins for base rate borrowings, SOFR borrowings and letters of credit were 0.125 %, 1.125 %, and 1.125 %, respectively, at December 31, 2024 . Based on our credit ratings, the commitment fee on unused amounts was 0.175 %. 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 Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following borrowings, outstanding letters of credit, and available capacity at December 31: 2024 2023 (dollars in millions) Amount outstanding $ 133.8 $ — Letters of credit (a) 3.5 3.7 Available capacity 612.7 746.3 Weighted average interest rates 4.74 % N/A (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 borrowing activity for the years ended December 31 was as follows: 2024 2023 (dollars in millions) Maximum amount outstanding (based on daily outstanding balances) $ 140.6 $ 548.7 Average amount outstanding (based on daily outstanding balances) 17.1 81.7 Weighted average interest rates 4.86 % 4.91 % Deferred Financing Costs on the Revolving Credit Facility Total accumulated deferred financing costs on the Revolving Credit Facility of $ 11.0 million a re 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: Interest Rate at Balance Outstanding Due Date December 31, 2024 December 31, 2024 December 31, 2023 (in millions) Corporate Senior unsecured notes due 2024 August 23, 2024 N/A $ — $ 600.0 Senior unsecured notes due 2026 January 15, 2026 3.95 % 300.0 300.0 Senior unsecured notes due 2027 January 15, 2027 3.15 % 400.0 400.0 Senior unsecured notes due 2028 March 15, 2028 5.95 % 350.0 350.0 Senior unsecured notes, due 2029 October 15, 2029 3.05 % 400.0 400.0 Senior unsecured notes, due 2030 June 15, 2030 2.50 % 400.0 400.0 Senior unsecured notes due 2033 May 1, 2033 4.35 % 400.0 400.0 Senior unsecured notes due 2034 May 15, 2034 6.15 % 450.0 450.0 Senior unsecured notes due 2035 January 15, 2035 6.00 % 450.0 — Senior unsecured notes, due 2046 September 15, 2046 4.20 % 300.0 300.0 Senior unsecured notes, due 2049 October 15, 2049 3.88 % 300.0 300.0 Total Corporate debt 3,750.0 3,900.0 Less unamortized debt discount ( 8.6 ) ( 8.9 ) Total Corporate debt, net 3,741.4 3,891.1 South Dakota Electric First Mortgage Bonds due 2032 (a) August 15, 2032 7.23 % 75.0 75.0 First Mortgage Bonds due 2039 (a) November 1, 2039 6.13 % 180.0 180.0 First Mortgage Bonds due 2044 (a) October 20, 2044 4.43 % 85.0 85.0 Total South Dakota Electric debt 340.0 340.0 Less unamortized debt discount ( 0.1 ) ( 0.1 ) Total South Dakota Electric debt, net 339.9 339.9 Wyoming Electric Industrial development revenue bonds due 2027 (b) (c) March 1, 2027 3.68 % 10.0 10.0 First Mortgage Bonds due 2037 (a) November 20, 2037 6.67 % 110.0 110.0 First Mortgage Bonds due 2044 (a) October 20, 2044 4.53 % 75.0 75.0 Total Wyoming Electric debt 195.0 195.0 Less unamortized debt discount — — Total Wyoming Electric debt, net 195.0 195.0 Total long-term debt 4,276.3 4,426.0 Less current maturities — ( 600.0 ) Less unamortized deferred financing costs (d) ( 26.1 ) ( 24.8 ) Long-term debt, net of current maturities and deferred financing costs $ 4,250.2 $ 3,801.2 (a) 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. (b) Variable interest rate. (c) A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the $ 10 million bonds due March 1, 2027. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. (d) Includes deferred financing costs associated with our Revolving Credit Facilit y of $ 2.4 million and $ 1.1 million as of December 31, 2024, and December 31, 2023 , respectively. Scheduled maturities of long-term debt and associated interest payments by year are shown below: Payments Due by Period 2025 2026 2027 2028 2029 Thereafter Total (in millions) Principal payments on Long-term debt including current maturities (a) $ — $ 300.0 $ 410.0 $ 350.0 $ 400.0 $ 2,825.0 $ 4,285.0 Interest payments on Long-term debt (a) 199.5 189.2 176.6 159.9 149.4 1,078.3 1,952.9 (a) Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2024. We believe it is probable that we will be able to successfully re-finance our $ 300 million, 3.95 %, senior unsecured notes due on January 15, 2026, at or before maturity date. Debt Transactions On May 16, 2024, we completed a public debt offering of $ 450 million, 6.00 % senior unsecured notes due January 15, 2035. Proceeds from the offering, which were net of $ 5.2 million of deferred financing costs, along with available cash and short-term borrowings under our existing facilities were used to repay all $ 600 million principal amount outstanding of our 1.04 % senior unsecured notes on their August 23, 2024, maturity date and for other general corporate purposes. Financial Covenants Revolving Credit Facility We were in compliance with all of our Revolving Credit Facility covenants as of December 31, 2024 . We are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Subject to applicable cure periods, a violation of this covenant would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. As of December 31, 2024, our Consolidated Indebtedness to Capitalization Ratio was 0.56 to 1.00. Wyoming Electric Wyoming Electric was in compliance with all covenants within its financing agreements as of December 31, 2024 . Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2024, Wyoming Electric's debt to capitalization ratio was 0.51 to 1.00. Dividend Restrictions Our Revolving 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. 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, 2024, the amount of restricted net assets at our Utilities that may not be distributed to our utility holding company in the form of a loan or dividend was approximat ely $ 152.2 million. South Dakota Electric and Wyoming Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements. Equity Although our aforementioned shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2024, we had 71.7 million shares of common stock outstanding and no shar es of preferred stock outstanding. At-the-Market Equity Offering Program 400 million, from time to time, through our ATM program utilizing our shelf registration statement. On June 16, 2023, we also terminated our August 4, 2020, Equity Distribution Sales Agreement, which had similar terms and conditions to our new agreement. ATM activity for the years ended December 31 was as follows: December 31, 2024 December 31, 2023 December 31, 2022 (in millions, except per share amounts) August 4, 2020 ATM Program Proceeds, (net of issuance costs of $ 0.0 , $( 0.5 ), and $( 0.9 ), respectively) $ — $ 48.5 $ 90.3 Number of shares issued — 0.8 1.3 June 16, 2023 ATM Program Proceeds, (net of issuance costs of $( 1.8 ), $( 0.7 ), and $ 0 , respectively $ 181.6 $ 70.2 $ — Number of shares issued 3.3 1.2 — Total activity under both ATM Programs Proceeds, (net of issuance costs of $( 1.8 ), $( 1.2 ), and $( 0.9 ), respectively) $ 181.6 $ 118.7 $ 90.3 Number of shares issued 3.3 2.0 1.3 Average price per share $ 55.63 $ 59.04 $ 69.74

Risk Management And Derivatives

Risk Management And Derivatives	12 Months Ended
	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management And Derivatives	(9) RISK MANAGEMENT AND DERIVATIVES Market and Credit Risk Disclosures Our activities in the energy industry 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. 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 weather, wildfires, geopolitical events, pandemics, market speculation, recession, inflation, 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. 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 periodic 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. 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 10 . 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. Through Black Hills Energy Services, our non-regulated natural gas commodity supplier, we buy, sell, and deliver natural gas in Nebraska and Wyoming 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 2025 through September 2026. 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, 2024 December 31, 2023 Units Notional Amounts Maximum Term (months) (a) Notional Amounts Maximum Term (months) (a) Natural gas futures purchased MMBtus 660,000 3 650,000 3 Natural gas options purchased, net MMBtus 2,780,000 3 2,850,000 3 Natural gas basis swaps purchased MMBtus 1,080,000 3 1,050,000 3 Natural gas over-the-counter swaps, net (b) MMBtus 3,480,000 20 3,890,000 21 Natural gas physical commitments, net (c) MMBtus 20,276,230 10 12,582,415 10 (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2024 , 1,427,000 MMBtus 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, 2024, the Company poste d $ 0.3 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets. Derivatives by Balance Sheet Classification The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31: Balance Sheet Location 2024 2023 (in millions) Derivatives designated as hedges: Liability derivative instruments: Current commodity derivatives Derivative liabilities - current $ ( 0.7 ) $ ( 2.7 ) Noncurrent commodity derivatives Other deferred credits and other liabilities — ( 0.2 ) Total derivatives designated as hedges $ ( 0.7 ) $ ( 2.9 ) Derivatives not designated as hedges: Liability derivative instruments: Current commodity derivatives Derivative liabilities - current $ ( 3.5 ) $ ( 3.8 ) Noncurrent commodity derivatives Other deferred credits and other liabilities — ( 0.1 ) Total derivatives not designated as hedges $ ( 3.5 ) $ ( 3.9 ) Derivatives Designated as Hedge Instruments The impact of cash flow hedges on our Consolidated Statements of Comprehensive Income and Consolidated Statements of Income is presented below for the years ended December 31, 2024, 2023, and 2022. 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. 2024 2023 2022 2024 2023 2022 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 millions) (in millions) Interest rate swaps $ 2.9 $ 2.9 $ 2.8 Interest expense $ ( 2.9 ) $ ( 2.9 ) $ ( 2.8 ) Commodity derivatives 2.9 ( 1.6 ) ( 3.5 ) Fuel, purchased power and cost of natural gas sold ( 3.5 ) ( 3.0 ) 2.7 Total $ 5.8 $ 1.3 $ ( 0.7 ) $ ( 6.4 ) $ ( 5.9 ) $ ( 0.1 ) As of December 31, 2024, $ 3.3 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, 2024, 2023, and 2022. 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. 2024 2023 2022 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income (in millions) Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold $ 0.7 $ ( 4.2 ) $ ( 0.8 ) $ 0.7 $ ( 4.2 ) $ ( 0.8 ) 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 a Regulatory asset related to these financial instruments used in our Gas Utilities wer e $ 2.9 million and $ 5.1 million at December 31, 2024, and 2023 , respectively.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2024
Fair Value Disclosures [Abstract]
Fair Value Measurements	(10) FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements Derivatives Valuation methodologies for our derivatives are detailed within Note 1 . 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, 2024 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in millions) Assets: Commodity derivatives $ — $ 2.2 $ — $ ( 2.2 ) $ — Total $ — $ 2.2 $ — $ ( 2.2 ) $ — Liabilities: Commodity derivatives $ — $ 4.8 $ — $ ( 0.6 ) $ 4.2 Total $ — $ 4.8 $ — $ ( 0.6 ) $ 4.2 (a) As of December 31, 2024, $ 2.2 million of our commodity derivative gross assets and $ 0.6 million of o ur commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements. As of December 31, 2023 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in millions) Assets: Commodity derivatives $ — $ 1.9 $ — $ ( 1.9 ) $ — Total $ — $ 1.9 $ — $ ( 1.9 ) $ — Liabilities: Commodity derivatives $ — $ 10.1 $ — $ ( 3.3 ) $ 6.8 Total $ — $ 10.1 $ — $ ( 3.3 ) $ 6.8 (a) As of December 31, 2023, $ 1.9 million of our commodity derivative assets and $ 3.3 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements. Pension and Retiree Plan Assets A discussion of the fair value of our Pension and Retiree Plan assets is included in Note 13 . 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 are not traded on an exchange; therefore, they are classified as 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: 2024 2023 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt, including current maturities (a) $ 4,250.2 $ 4,059.1 $ 4,401.2 $ 4,215.6 (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, 2024
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income	(11) 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: Location on the Consolidated Amount Reclassified from AOCI Statements of Income December 31, 2024 December 31, 2023 (in millions) Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ ( 2.9 ) $ ( 2.9 ) Commodity contracts Fuel, purchased power, and cost of natural gas sold ( 3.5 ) ( 3.0 ) ( 6.4 ) ( 5.9 ) Income tax Income tax benefit (expense) 1.4 1.4 Total reclassification adjustments related to cash flow hedges, net of tax $ ( 5.0 ) $ ( 4.5 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ — $ — Actuarial gain (loss) Operations and maintenance ( 0.2 ) ( 0.2 ) ( 0.2 ) ( 0.2 ) Income tax Income tax benefit (expense) 0.1 — Total reclassification adjustments related to defined benefit plans, net of tax $ ( 0.1 ) $ ( 0.2 ) Total reclassifications $ ( 5.1 ) $ ( 4.7 ) Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows: Derivatives Designated as Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total (in millions) As of December 31, 2022 $ ( 8.3 ) $ ( 1.2 ) $ ( 6.1 ) $ ( 15.6 ) Other comprehensive income (loss) before reclassifications — ( 3.6 ) ( 0.3 ) ( 3.9 ) Amounts reclassified from AOCI 2.2 2.3 0.2 4.7 As of December 31, 2023 $ ( 6.1 ) $ ( 2.5 ) $ ( 6.2 ) $ ( 14.8 ) Other comprehensive income (loss) before reclassifications — ( 0.5 ) 0.8 0.3 Amounts reclassified from AOCI 2.3 2.7 0.1 5.1 As of December 31, 2024 $ ( 3.8 ) $ ( 0.3 ) $ ( 5.3 ) $ ( 9.4 )

Variable Interest Entity

Variable Interest Entity	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entity	(12) 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 %, non-controlling 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. Net income available for common stock for the years ended December 31, 2024, 2023, and 2022 was reduced by $ 10.6 million, $ 13.8 million, and $ 12.4 million, respectively, attributable to this non-controlling interest. The net income allocable to the non-controlling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of net income attributable to this non-controlling 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: 2024 2023 (in millions) Assets: Current assets $ 11.7 $ 15.1 Property, plant and equipment $ 160.4 $ 166.8 Liabilities: Current liabilities $ 8.3 $ 4.8

Employee Benefits Plans

Employee Benefits Plans	12 Months Ended
	Dec. 31, 2024
Retirement Benefits [Abstract]
Employee Benefit Plans	(13) 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, 2024, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 20 % to 28 % return-seeking assets and 72 % to 80 % liability-he dging assets. For 2025, the expected rate of return on pension plan assets is based on the targeted asset allocation range of 26 % to 34 % return-seeking assets and 66 % to 74 % liability-he dging 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: Return-seeking Assets 2024 2023 Equity 19 % 14 % Real estate 5 % 5 % Hedge funds 3 % 3 % Fixed income 3 % 2 % Total 30 % 24 % Liability-hedging Assets 2024 2023 Fixed income 68 % 74 % Cash 2 % 2 % Total 70 % 76 % Total Assets 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 Retiree 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: 2024 2023 (in millions) Defined Contribution Plan Company retirement contributions $ 11.3 $ 12.7 Company matching contributions 17.7 17.1 Defined Benefit Plans Pension Plan $ 2.3 $ — Healthcare Plan 5.7 5.4 Supplemental Plans 4.1 3.5 In 2025,we expect to make contributions of $ 1.8 million, $ 4.7 million and $ 2.8 million to the Pension Plan, Healthcare Plan and Supplemental Plans, respectively . 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: December 31, 2024 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments (in millions) Pension Plan Common Collective Trust - Cash and Cash Equivalents $ — $ 5.4 $ — $ 5.4 $ — $ 5.4 Common Collective Trust - Equity — 51.5 — 51.5 — 51.5 Common Collective Trust - Fixed Income — 190.8 — 190.8 — 190.8 Common Collective Trust - Real Estate — — — — 14.9 14.9 Hedge Funds — — — — 7.6 7.6 Total investments measured at fair value $ — $ 247.7 $ — $ 247.7 $ 22.5 $ 270.2 Healthcare Plan Cash and Cash Equivalents 7.5 — — 7.5 — 7.5 Total investments measured at fair value $ 7.5 $ — $ — $ 7.5 $ — $ 7.5 December 31, 2023 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments (in millions) Pension Plan Common Collective Trust - Cash and Cash Equivalents $ — $ 6.7 $ — $ 6.7 $ — $ 6.7 Common Collective Trust - Equity — 42.7 — 42.7 — 42.7 Common Collective Trust - Fixed Income — 234.5 — 234.5 — 234.5 Common Collective Trust - Real Estate — — — — 16.4 16.4 Hedge Funds — — — — 8.1 8.1 Total investments measured at fair value $ — $ 283.9 $ — $ 283.9 $ 24.5 $ 308.4 Healthcare Plan Cash and Cash Equivalents 8.0 — — 8.0 — 8.0 Total investments measured at fair value $ 8.0 $ — $ — $ 8.0 $ — $ 8.0 (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. 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 Pension 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 Pension 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. Advance written notice of no less than fifteen ( 15 ) business days will generally be required to redeem an investment in these funds. Additionally, the Trustee retains the right to implement trading procedures and restrictions that the Trustee (in its sole and absolute discretion) determines to be necessary or advisable to protect the interest of the Trust. There are no unfunded commitments related to these funds. 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 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. Advance written notice of no less than one hundred and five ( 105 ) calendar days prior to the desired valuation date will generally be required to redeem an investment in these funds. Additionally, the Trustee retains the right to implement trading procedures and restrictions that the Trustee (in its sole and absolute discretion) determines to be necessary or advisable to protect the interests of the Trust. There are no unfunded commitments related to these funds. 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 Retiree 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. Components of Net Periodic Expense The following table provides a reconciliation of components of the net periodic expense: Pension Plan Supplemental Plans Healthcare Plan For the years ended December 31, 2024 2023 2022 2024 2023 2022 2024 2023 2022 (in millions) Service cost $ 2.3 $ 2.5 $ 3.9 $ 3.3 $ 3.1 $ ( 0.8 ) $ 1.6 $ 1.5 $ 1.9 Interest cost 16.4 17.5 10.8 1.4 1.5 0.8 2.4 2.4 1.3 Expected return on assets ( 18.0 ) ( 18.7 ) ( 18.5 ) — — — ( 0.3 ) ( 0.2 ) ( 0.1 ) Net amortization of prior service cost ( 0.1 ) ( 0.1 ) ( 0.1 ) — — — 0.2 — ( 0.3 ) Recognized net actuarial loss (gain) 2.0 2.0 6.1 — — 0.3 — — 0.1 Net periodic expense $ 2.6 $ 3.2 $ 2.2 $ 4.7 $ 4.6 $ 0.3 $ 3.9 $ 3.7 $ 2.9 Service costs are recorded in Operations and maintenance expense while non-service costs are recorded in Other expense on the Consolidated Statements of Income. Actuarial gains and losses are amortized using a straight-line method over the average remaining service period of active plan participants or over the average remaining lifetime of the remaining plan participants if the plan is viewed as “all or almost all” inactive participants. 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 on our Consolidated Balance Sheets, accumulated benefit obligation, and elements of AOCI: Pension Plan Supplemental Plans Healthcare Plan 2024 2023 2024 2023 2024 2023 (in millions) Accumulated benefit obligation at December 31 $ 307.1 $ 341.8 $ 46.1 $ 46.7 $ 48.5 $ 51.1 Change in benefit obligation: Projected benefit obligation at beginning of year $ 348.1 $ 358.4 $ 46.7 $ 45.2 $ 51.1 $ 49.7 Service cost 2.3 2.5 3.3 3.1 1.6 1.5 Interest cost 16.4 17.5 1.4 1.5 2.4 2.4 Actuarial (gain) loss ( 16.0 ) 11.6 ( 1.2 ) 0.3 ( 1.7 ) 1.7 Benefits paid ( 39.2 ) ( 41.9 ) ( 4.1 ) ( 3.4 ) ( 5.7 ) ( 5.3 ) Plan participants’ contributions — — — — 0.8 1.1 Projected benefit obligation at end of year 311.6 348.1 46.1 46.7 48.5 51.1 Change in fair value of plan assets: Fair value of plan assets at beginning of year 308.6 323.1 — — 8.0 7.8 Investment income (loss) ( 1.6 ) 27.4 — — 0.1 0.2 Employer contributions 2.3 — 4.1 3.5 4.2 4.3 Retiree contributions — — — — 0.9 1.1 Benefits paid ( 39.1 ) ( 41.9 ) ( 4.1 ) ( 3.5 ) ( 5.7 ) ( 5.4 ) Fair value of plan assets at end of year 270.2 308.6 — — 7.5 8.0 Funded status - deficiency $ 41.4 $ 39.5 $ 46.1 $ 46.7 $ 41.0 $ 43.1 Amounts recognized on our Consolidated Balance Sheets as of December 31: Regulatory assets $ 81.6 $ 79.9 $ — $ — $ 4.9 $ 4.8 Current liabilities — — 2.8 2.4 4.3 4.2 Non-current assets — — — — — 1.3 Non-current liabilities 41.4 39.4 43.3 44.3 36.7 40.2 Regulatory liabilities 3.1 2.9 — — 7.3 5.5 Amounts recognized in AOCI, net of tax as of December 31: Net (gain) loss $ 5.2 $ 5.0 $ 0.8 $ 1.8 $ ( 0.7 ) $ ( 0.7 ) Prior service cost (gain) — — — — — 0.1 Total amounts included in AOCI, net of tax not yet recognized as components of net periodic expense $ 5.2 $ 5.0 $ 0.8 $ 1.8 $ ( 0.7 ) $ ( 0.6 ) In 2024, actuarial gains related to the pension benefit obligation was primarily due to an increase in the discount rate. In 2023, actuarial losses related to the pension benefit obligation was primarily due to a decrease in the discount rate. Assumptions Pension Plan Supplemental Plans Healthcare Plan 2024 2023 2022 2024 2023 2022 2024 2023 2022 Weighted-average assumptions used to determine benefit obligations: Discount rate 5.63 % 4.99 % 5.17 % 5.56 % 4.93 % 5.13 % 5.60 % 4.97 % 5.14 % Rate of increase in compensation levels 3.04 % 3.04 % 3.06 % — — — N/A N/A N/A Weighted-average assumptions used to determine net periodic benefit cost for plan year: Discount rate (a) 4.99 % 5.17 % 2.88 % 4.93 % 5.13 % 2.77 % 4.97 % 5.14 % 2.79 % Expected long-term rate of return on assets (b) 6.00 % 6.00 % 4.25 % N/A N/A N/A 3.50 % 3.10 % 1.70 % Rate of increase in compensation levels 3.04 % 3.06 % 3.08 % — — — N/A N/A N/A (a) The estimated discount rate for the Defined Benefit Pension Plan is 5.63 % for the calculation of the 2025 net periodic pension costs. (b) The expected rate of return on plan as sets for the Defined Benefit Pension Plan is 6.50 % for the calculation of the 2025 net periodic pension cost. The healthcare benefit obligation at December 31 was determined as follows: 2024 2023 Trend Rate - Medical Pre-65 for next year - All Plans 7.50 % 6.69 % Pre-65 Ultimate trend rate - Black Hills Corp 4.50 % 4.50 % Trend Year 2035 2034 Post-65 for next year - All Plans 6.50 % 5.81 % Post-65 Ultimate trend rate - Black Hills Corp 4.50 % 4.50 % Trend Year 2033 2034 The following benefit payments to employees, which reflect future service, are expected to be paid: Pension Plan Supplemental Plans Healthcare Plan (in millions) 2025 $ 24.4 $ 2.8 $ 5.3 2026 24.8 2.8 5.1 2027 25.1 2.7 5.0 2028 25.1 2.7 4.8 2029 25.6 2.5 4.7 2030 - 2034 $ 123.5 $ 11.3 $ 21.4

Share-based Compensation Plans

Share-based Compensation Plans	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
Share-based Compensation Plans	(14) SHARE-BASED COMPENSATION PLANS Our Amended and Restated 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 1,988,252 shares available to grant at December 31, 2024. 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, 2024 , total unrecognized compensation expense related to non-vested stock awards was $ 13.0 million and is expected to be recognized over a weighted-average period of 2 . 0 years. Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the ye ars ended December 31: 2024 2023 2022 (in millions) Stock-based compensation expense $ 10.6 $ 7.0 $ 8.6 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, 2024, was as follows: Restricted Stock Weighted-Average Grant Date Fair Value Balance at January 1, 2024 164,687 $ 64.81 Granted 180,676 53.58 Vested ( 83,737 ) 65.11 Forfeited ( 29,684 ) 59.13 Balance at December 31, 2024 231,942 $ 56.68 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 millions) 2024 $ 53.58 $ 4.5 2023 $ 63.33 $ 5.9 2022 $ 69.03 $ 6.4 As of December 31, 2024, there was $ 8.6 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 2.1 years. Performance Share Units Beginning in 2021, certain officers of the Company, and its subsidiaries, were granted performance share units which have a three-year vesting period, do not have voting rights until vested, and are subject to three specified conditions. A market condition of relative total shareholder return and two equally weighted performance metrics of average earnings per share and the average cost to serve. Beginning in 2023, the metric of natural gas emissions reduction by 2035 was added, resulting in three equally weighted performance metrics. The units are paid 100 % in common stock should conditions be met and can range from 0 % to 200 % of the target award. Dividend equivalents are accrued during the vesting period and paid out based on the final number of shares awarded. In the event of participant’s death or retirement at age 55 or older, shares awarded vest on a pro-rata basis commensurate with the months of service performed over the three-year period. Performance Share Units - Market Condition The fair value of each share unit is based on the Company’s closing price at December 31 of the year prior to the award and a Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on the Company’s TSR for a three-year performance period relative to the designated peer group beginning January 1 of the award year. The significant assumptions included in the company's Monte Carlo simulations were as follows: 2024 2023 Fair value of share units award $ 55.14 $ 77.95 Risk-free rate 4.12 % 3.84 % Black Hills Corporation’s common stock volatility 24 % 31 % Volatility range for the peer group 12 - 53 % 24 - 39 % Performance Share Units - Performance Condition A performance condition share unit vests at the end of the three-year performance period if the specified performance conditions are achieved. The conditions are based on the Company’s average earnings per share, the average cost to serve and natural gas emissions reductions by 2035. The grant-date fair value for an individual outcome of a performance condition is determined by the closing common share price on the grant date or, beginning in 2023, the average ten-day closing common share price preceding the grant date. The following table summarizes the performance share unit activity for the year ended December 31, 2024: Performance Share Units - Performance Share Units - Share Units Weighted-Average Fair Value per Share Unit Share Units Weighted-Average Fair Value per Share Unit Nonvested at January 1, 2024 110,747 $ 73.31 62,654 $ 67.88 Granted 71,537 55.14 30,663 51.00 Vested ( 30,749 ) 64.97 ( 20,512 ) 61.45 Nonvested at December 31, 2024 151,535 $ 66.43 72,805 $ 62.59 As of December 31, 2024, there was $ 4.3 million of unrecognized compensation expense related to outstanding performance share/units that is expected to be recognized over a weighted-average period of 1 . 7 years. On January 23, 2025, the Compensation Committee of our Board of Directors confirmed a payout equal to 10.32 % of target shares valued at $ 0.4 million. The payout was fully accrued at December 31, 2024 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Income Taxes	(15) INCOME TAXES Transfers of Production Tax Credits In August 2022, President Biden signed H.R. 5376 into law, commonly known as the IRA of 2022, or IRA. The IRA contains a tax credit transferability provision that allows us to transfer (e.g. sell) PTCs produced after December 31, 2022, to third parties. In June 2024, under this transferability provision, we entered into an agreement with a third party to sell $ 16.9 million of our 2023 generated PTCs. In January 2025, we entered into a similar agreement with a third party to sell $ 17.0 million of our 2024 generated PTCs. We expect to continue to explore the ability to efficiently monetize our tax credits through third party transferability agreements. IRS Revenue Procedure 2023-15 On April 14, 2023, the IRS released Revenue Procedure 2023-15 “Amounts paid to improve tangible property.” The Revenue Procedure provides a safe harbor method of accounting that taxpayers may use to determine whether costs to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized. The Revenue Procedure may be adopted in tax years ending after May 1, 2023. We intend to elect the safe harbor for tax year 2024. We do not expect the Revenue Procedure to have a material impact on our tax repairs deduction. Income Tax (Expense) Benefit Income tax (expense) benefit from continuing operations for the years ended December 31 was: 2024 2023 2022 (in millions) Current: Federal $ 16.5 $ 0.8 $ 0.5 State ( 0.8 ) ( 1.0 ) ( 0.1 ) Current income tax benefit (expense) 15.7 ( 0.2 ) 0.4 Deferred: Federal ( 47.2 ) ( 30.9 ) ( 23.2 ) State ( 4.8 ) 5.5 ( 2.4 ) Deferred income tax (expense) ( 52.0 ) ( 25.4 ) ( 25.6 ) Income tax (expense) $ ( 36.3 ) $ ( 25.6 ) $ ( 25.2 ) Effective Tax Rates The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: 2024 2023 2022 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax (net of federal tax effect) (a) 1.3 ( 0.8 ) 0.5 Non-controlling interest (b) ( 0.7 ) ( 1.0 ) ( 0.9 ) Tax credits ( 5.6 ) ( 6.2 ) ( 7.7 ) Flow-through adjustments (c) ( 2.2 ) ( 1.7 ) ( 1.4 ) Amortization of excess deferred income taxes (d) ( 2.4 ) ( 3.0 ) ( 2.5 ) Other ( 0.1 ) 0.2 ( 0.5 ) Effective Tax Rate 11.3 % 8.5 % 8.5 % (a) For the year ended December 31, 2023, we recognized an $ 8.2 million tax benefit from a Nebraska income tax rate decrease. (b) The effective tax rate reflects the income attributable to the non-controlling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (c) 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. (d) Primarily TCJA - see Note 2 for additional information. 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: 2024 2023 (in millions) Deferred tax assets: Regulatory liabilities $ 70.9 $ 74.0 State tax credits 8.4 22.8 Federal NOL 114.9 146.6 State NOL 12.7 16.5 Partnership 11.6 12.2 Credit Carryovers 110.5 110.1 Other deferred tax assets 35.4 33.7 Less: Valuation allowance ( 1.3 ) ( 15.4 ) Total deferred tax assets 363.1 400.5 Deferred tax liabilities: Accelerated depreciation, amortization, and other property-related differences ( 729.2 ) ( 686.2 ) Regulatory assets ( 49.5 ) ( 65.6 ) Goodwill ( 75.9 ) ( 67.8 ) State deferred tax liability ( 88.7 ) ( 84.5 ) Other deferred tax liabilities ( 44.9 ) ( 44.4 ) Total deferred tax liabilities ( 988.2 ) ( 948.5 ) Net deferred tax liability $ ( 625.1 ) $ ( 548.0 ) Net Operating Loss and Tax Credit Carryforwards At December 31, 2024, we have federal NOL and state NOL and tax credit carryforwards that will expire at various dates as follows: Amounts Expiration Dates (in millions) Federal NOL Carryforward $ 547.2 No expiration Federal Tax Credit Carryforward $ 110.5 2030-2044 State NOL Carryforward (a) $ 242.6 2025-2042 State Tax Credit Carryforward $ 8.4 2025-2038 (a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes. As of December 31, 2024, we h ad a $ 0.3 million valuat ion allowance against the state NOL carryforwards. Our 2024 analysis of the ability to utilize such NOLs resulte d in no increa se in the valuation allowance. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense. The valuation allowance was reduced by $ 0.7 million for previously reserved expiring NOL. Refer to Notes 1 and 3 for a discussion of valuation allowances recorded in 2024 related to the expected transfer of renewable tax credits to other corporate taxpayers. As of December 31, 2024 , we did no t have a valuation allowance against the state ITC carryforwards. The valuation allowance was reduced by $ 14.4 million for a previously reserved expiring state ITC. 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: Changes in Uncertain Tax Positions: 2024 2023 2022 (in millions) Beginning balance $ 13.7 $ 11.9 $ 10.6 Additions for prior year tax positions 0.6 — - Reductions for prior year tax positions ( 8.1 ) ( 0.3 ) ( 0.8 ) Additions for current year tax positions 1.6 2.1 2.1 Ending balance $ 7.8 $ 13.7 $ 11.9 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $ 7.5 million. We recognized no interest expense associated with income taxes for the years ended December 31, 2024, 2023, and 2022 . We had no accrued interest (before tax effect) associated with income taxes at December 31, 2024, and 2023. As of December 31, 2024, 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, 2025 . In 2024, we released all uncertain tax positions for tax repairs of gas transmission and distribution property due to a change in a method of accounting provided by Revenue Procedure 2023-15.

Business Segment Information

Business Segment Information	12 Months Ended
	Dec. 31, 2024
Segment Reporting Information, Additional Information [Abstract]
Business Segment Information	(16) BUSINESS SEGMENT INFORMATION We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our reportable segments are presented as Corporate and Other. Our operating segments, which are equivalent to our reportable segments, are based on our method of internal reporting, which is generally segregated by differences in products and services. 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. We also own and operate non-regulated power generation and mining businesses that are vertically integrated with our Electric Utilities. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Corporate and Other consists of certain unallocated expenses for administrative activities that support our operating segments. Corporate and Other also includes business development activities that are not part of our operating segments and inter-segment eliminations. Our Chief Executive Officer, who is considered to be our CODM, reviews financial information presented on an operating segment basis for purposes of making decisions, allocating resources, and assessing financial performance. Our CODM assesses the performance of our operating segments and decides how to allocate resources based on operating income. Our CODM reviews capital expenditures by operating segment rather than any individual or total asset amount. Segment information was as follows: Consolidating Income Statement Year Ended December 31, 2024 Electric Utilities Gas Utilities Corporate Total (in millions) Revenue - External Customers $ 864.4 $ 1,263.3 $ — $ 2,127.7 Inter-segment 11.7 6.1 ( 17.8 ) — Total revenue 876.1 1,269.4 ( 17.8 ) 2,127.7 Fuel, purchased power and cost of natural gas sold 206.4 524.3 ( 0.4 ) 730.3 Operations and maintenance (a) - Direct 127.5 155.4 ( 16.3 ) 266.6 Allocated 125.1 165.3 — 290.4 Depreciation, depletion and amortization 145.3 124.7 0.1 270.1 Taxes other than income taxes 38.8 28.4 — 67.2 Operating income (loss) $ 233.0 $ 271.3 $ ( 1.2 ) $ 503.1 Interest expense, net ( 181.7 ) Other income (expense), net ( 1.4 ) Income tax (expense) ( 36.3 ) Net income 283.7 Net income attributable to non-controlling interest ( 10.6 ) Net income available for common stock $ 273.1 Consolidating Income Statement Year Ended December 31, 2023 Electric Utilities Gas Utilities Corporate Total (in millions) Revenue - External Customers $ 853.6 $ 1,477.7 $ — $ 2,331.3 Inter-segment 11.4 6.5 ( 17.9 ) — Total revenue 865.0 1,484.2 ( 17.9 ) 2,331.3 Fuel, purchased power and cost of natural gas sold 200.1 783.2 ( 0.4 ) 982.9 Operations and maintenance (a) - Direct 112.2 162.2 ( 12.9 ) 261.5 Allocated 124.0 166.5 — 290.5 Depreciation, depletion and amortization 142.6 113.9 0.3 256.8 Taxes other than income taxes 37.3 29.6 — 66.9 Operating income (loss) $ 248.8 $ 228.8 $ ( 4.9 ) $ 472.7 Interest expense, net ( 167.9 ) Other income (expense), net ( 3.2 ) Income tax (expense) ( 25.6 ) Net income 276.0 Net income attributable to non-controlling interest ( 13.8 ) Net income available for common stock $ 262.2 Consolidating Income Statement Year Ended December 31, 2022 Electric Utilities Gas Utilities Corporate Total (in millions) Revenue - External Customers $ 888.4 $ 1,663.4 $ — $ 2,551.8 Inter-segment 11.8 5.7 ( 17.5 ) — Total revenue 900.2 1,669.1 ( 17.5 ) 2,551.8 Fuel, purchased power and cost of natural gas sold 266.3 965.1 ( 0.8 ) 1,230.6 Operations and maintenance (a) - Direct 124.0 158.5 ( 13.7 ) 268.8 Allocated 120.8 158.8 — 279.6 Depreciation, depletion and amortization 135.9 114.7 0.3 250.9 Taxes other than income taxes 38.9 27.8 — 66.7 Operating income (loss) $ 214.3 $ 244.2 $ ( 3.3 ) $ 455.2 Interest expense, net ( 161.0 ) Other income (expense), net 1.8 Income tax (expense) ( 25.2 ) Net income 270.8 Net income attributable to non-controlling interest ( 12.4 ) Net income available for common stock $ 258.4 (a) Direct and Allocated Operations and maintenance expenses for our operating segments are regularly provided to the CODM. Direct expenses represents the costs incurred directly by our operating segments. Allocated expenses represent costs incurred by BHSC for various direct and indirect support services provided to our operating segments. Pursuant to the BHSC Cost Allocation Manual, indirect cost allocations are determined in accordance with PUHCA 2005. Capital Expenditures (a) for the years ended December 31, 2024 2023 2022 (in millions) Electric Utilities $ 381.9 $ 210.7 $ 243.1 Gas Utilities 402.7 371.9 349.5 Corporate and Other 13.0 7.3 5.1 Total capital expenditures $ 797.6 $ 589.9 $ 597.7 (a) Includes accruals for property, plant, and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows .

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2024
Subsequent Events [Abstract]
Subsequent Events	(17) SUBSEQUENT EVENTS Except as described in Notes 2 , 3 and 15 , there have been no events subsequent to December 31, 2024 , 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, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Use of Estimates and Basis of Presentation	Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary, thus controlling the VIE, have been consolidated. All intercompany balances and transactions have been eliminated in consolidation. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned facility. See Note 6 for additional information.
Noncontrolling Interest	Non-controlling 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 non-controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the non-controlling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 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, non-controlling 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 non-controlling 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 Note 12 for additional information.
Cash and Cash Equivalents and Restricted Cash	Cash, 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.
Revenue from Contract with Customer	Revenue Recognition 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 segment has 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. The majority of our revenue contracts are based on variable quantities delivered. Typically, our customers are billed monthly with payment due within 20 days. Any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration 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 tables in Note 4 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 substantially all of our revenue contracts provides an unconditional right to consideration upon service delivery. Customer billings (and subsequent customer payments of those bills) occur after service delivery. Therefore, customer contract assets or liabilities do not exist. The unconditional right to consideration is represented by the balance in our Accounts receivable, which is further discussed below. See Note 4 for additional information.
Accounts Receivable and Allowance for Credit Losses	Accounts Receivable and Allowance for Credit Losses Accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses, and do not bear interest. 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 collectability. 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 setoff exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Following is a summary of accounts receivable as of December 31: 2024 2023 (in millions) Billed Accounts Receivable $ 201.5 $ 198.5 Unbilled Revenue 151.8 154.0 Less Allowance for Credit Losses ( 2.1 ) ( 2.2 ) Accounts Receivable, net $ 351.2 $ 350.3 Changes to allowance for credit losses for the years ended December 31, were as follows: Balance at Additions Recoveries and Write-offs and Balance at (in millions) 2024 $ 2.2 $ 5.6 $ 4.2 $ ( 9.9 ) $ 2.1 2023 $ 3.0 $ 8.7 $ 4.1 $ ( 13.6 ) $ 2.2 2022 $ 2.1 $ 9.1 $ 3.5 $ ( 11.7 ) $ 3.0
Materials, Supplies and Fuel	Materials, Supplies, and Fuel Materials and supplies represent parts and supplies for our business operations. Fuel represents diesel oil and gas used by our electric generating facilities 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. The following amounts by major classification are included in Materials, supplies, and fuel on the accompanying Consolidated Balance Sheets as of December 31: 2024 2023 (in millions) Materials and supplies $ 106.1 $ 105.9 Fuel 7.5 7.7 Natural gas in storage 40.3 47.3 Total materials, supplies, and fuel $ 153.9 $ 160.9
Property, Plant and Equipment	Property, Plant, and Equipment Property, plant, and equipment are stated at cost, which includes construction-related direct labor and material costs, indirect construction costs including labor and related costs of departments associated with supporting construction activities, and AFUDC. Additions to and significant replacements of property are charged to property, plant, and equipment at cost. We also classify our Cushion Gas as Property, plant, and equipment. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are expensed as incurred. We receive CIACs from third parties that are generally intended to defray all or a portion of the costs for certain capital projects. Such CIAC costs are recorded as a reduction to Property, plant, and equipment. The cost of regulated utility property, plant, and equipment retired, or otherwise disposed 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 operating assets which result in gains or losses are recognized within Operations and maintenance expense. See Note 5 for additional information. Depreciation 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. Depreciation studies are conducted periodically to update composite rates and are approved by state utility commissions and/or the FERC when required. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-regulated power plant components, depreciation is computed on a unit-of-production methodology based on plant hours run. AFUDC 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. The following table presents AFUDC amounts for the years ended December 31: Income Statement Location 2024 2023 2022 (in millions) AFUDC Debt Interest expense incurred, net of amounts capitalized $ 8.7 $ 6.0 $ 5.6 AFUDC Equity Other income (expense), net 4.0 0.4 0.6 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.
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, and regulated operations without a corresponding recovery mechanism, is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations with a regulatory mechanism 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. See Note 7 for additional information.
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, or components of an operating segment. Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industries. We believe that goodwill reflects the inherent value of the relatively stable, long-lived cash flows of our Utilities businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our Utilities, and those businesses vertically integrated. Goodwill amounts have not changed since 2016. 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 1 years to 17 years.
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 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 credit valuation adjustment 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. See Notes 10 and 13 for additional information.
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 pricing is clearly and closely related to the asset being purchased or sold. 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 setoff 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 setoff exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures. The cash impacts of settled derivatives are recorded as operating activities on the Consolidated Statements of Cash Flows. See Notes 9 , 10, and 11 for additional information.
Debt Discounts, Premiums and Deferred Financing Costs	Debt Discounts, Premiums, and Deferred Financing Costs Deferred financing costs include loan origination fees, underwriter fees, legal fees, and other costs directly attributable to the issuance of debt. Debt discounts, premiums, and deferred financing costs are amortized over the estimated useful life of the related debt. Unamortized discounts, premiums, and deferred financing costs are presented on the balance sheet as an adjustment to the related debt liabilities. See Note 8 for additional information.
Regulatory Accounting	Regulatory Accounting Our regulated Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our 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. See Note 2 for additional information.
Income Taxes	Income Taxes The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. The Company and its subsidiaries file consolidated federal income tax returns. Each subsidiary records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements. It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax (expense) on the Consolidated Statements of Income. We have elected to account for transferable renewable tax credits, including PTCs and ITCs, as a reduction to income taxes payable under the scope of ASC 740 Income Taxes . We include the discount from the sale of our tax credits as a component of income tax expense. The sale of tax credits is presented within Operating activities in the Consolidated Statement of Cash Flows consistent with the presentation of cash taxes paid. For renewable tax credits subject to future transfer, a valuation allowance is recorded for the difference between the tax value of the credits and the expected sales price. Tax credits and any related valuation allowances are derecognized when control of the tax credits is transferred to other corporate taxpayers. See Notes 3 and 15 for further discussion of the transfer of renewable tax credits to other corporate taxpayers, including related indemnification requirements and valuation allowances, respectively. We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.
Earnings per Share of Common Stock	Earnings per Share of Common Stock Basic earnings per share is computed by dividing Net income available for common stock 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, as calculated using the treasury stock method. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock, and performance shares under our equity compensation plans.
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 Note 14 for additional information.
Pension and Other Retiree Plans	Pension and Other Retiree Plans We recognize on our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other retiree plans with current-year changes in actuarial gains or losses recognized in AOCI, except for those plans at certain of our regulated utilities that can recover portions of their pension and retiree obligations through future rates. All plan assets are recorded at fair value. We follow the measurement date provisions of ASC 715, Compensation-Retirement Benefit s, which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
Recently Issued and Adopted Accounting Standards	Recently Issued Accounting Standards Improvements to Income Tax Disclosures, ASU 2023-09 In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which expands public entities’ annual disclosures by requiring disclosure of tax rate reconciliation amounts and percentages for specific categories, income taxes paid disaggregated by federal and state taxes, and income tax expense disaggregated by federal and state taxes jurisdiction. The ASU is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, with early adoption permitted. We are currently evaluating the impact of ASU 2023-09 on our consolidated financial statement disclosures. Disaggregation of Income Statement Expenses, ASU 2024-03 In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures , and in January 2025, the FASB issued ASU 2025-01, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Clarifying the Effective Date. ASU 2024-03 requires public entities to disclose, in the notes to financial statements, certain costs and expenses, such as purchases of inventory, employee compensation, and costs related to depreciation and amortization. ASU 2024-03, as clarified by ASU 2025-01, is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2027, and subsequent interim periods, with early adoption permitted. We are currently evaluating the impact of these standards on our consolidated financial statement disclosures. Recently Adopted Accounting Standards Improvements to Reportable Segment Disclosures, ASU 2023-07 In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segment Disclosures, which expands public entities’ segment disclosures by requiring disclosure of significant segment expenses that are regularly reviewed by the CODM and included within each reported measure of segment profit or loss, an amount and description of its composition for other segment items, and interim disclosures of a reportable segment’s profit or loss and assets. The ASU also allows, in addition to the measure that is most consistent with GAAP, the disclosure of additional measures of segment profit or loss that are used by the CODM in assessing segment performance and deciding how to allocate resources. We implemented this ASU effective for our Annual Report on Form 10-K for the year ended December 31, 2024. Adoption of this ASU did not have a material impact on our consolidated financial statement disclosures. The additional disclosures required by this ASU are included in Note 16.

Business Description And Sign_3

Business Description And Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Account Receivable Schedule	Following is a summary of accounts receivable as of December 31: 2024 2023 (in millions) Billed Accounts Receivable $ 201.5 $ 198.5 Unbilled Revenue 151.8 154.0 Less Allowance for Credit Losses ( 2.1 ) ( 2.2 ) Accounts Receivable, net $ 351.2 $ 350.3
Financing Receivable, Current, Allowance for Credit Loss	Changes to allowance for credit losses for the years ended December 31, were as follows: Balance at Additions Recoveries and Write-offs and Balance at (in millions) 2024 $ 2.2 $ 5.6 $ 4.2 $ ( 9.9 ) $ 2.1 2023 $ 3.0 $ 8.7 $ 4.1 $ ( 13.6 ) $ 2.2 2022 $ 2.1 $ 9.1 $ 3.5 $ ( 11.7 ) $ 3.0
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: 2024 2023 (in millions) Materials and supplies $ 106.1 $ 105.9 Fuel 7.5 7.7 Natural gas in storage 40.3 47.3 Total materials, supplies, and fuel $ 153.9 $ 160.9
Property, Plant and Equipment (AFUDC)	The following table presents AFUDC amounts for the years ended December 31: Income Statement Location 2024 2023 2022 (in millions) AFUDC Debt Interest expense incurred, net of amounts capitalized $ 8.7 $ 6.0 $ 5.6 AFUDC Equity Other income (expense), net 4.0 0.4 0.6
Goodwill	As of December 31, 2024, and 2023, Goodwill balances were as follows: Electric Utilities Gas Utilities Total (in millions) Goodwill $ 257.3 $ 1,042.2 $ 1,299.5
Intangible Assets	C hanges to intangible assets for the years ended December 31, were as follows: 2024 2023 2022 (in millions) Intangible assets, net, beginning balance $ 8.4 $ 9.6 $ 10.8 Additions 0.3 — — Amortization expense (a) ( 1.1 ) ( 1.2 ) ( 1.2 ) Intangible assets, net, ending balance $ 7.6 $ 8.4 $ 9.6 (a) Amortization expense for existing intangible assets is expected to b e $ 1.2 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: 2024 2023 (in millions) Accrued employee compensation, benefits and withholdings $ 85.5 $ 74.8 Accrued property taxes 54.7 52.7 Customer deposits and prepayments 55.6 76.0 Accrued interest 56.4 46.3 Other (none of which is individually significant) 50.0 43.5 Total accrued liabilities $ 302.2 $ 293.3
Schedule of Earnings Per Share Reconciliation	A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31: 2024 2023 2022 (in millions, except per share amounts) Net income available for common stock $ 273.1 $ 262.2 $ 258.4 Weighted average shares - basic 69.8 67.0 64.9 Dilutive effect of equity compensation 0.1 0.1 0.1 Weighted average shares - diluted 69.9 67.1 65.0 Net income available for common stock, per share - Diluted $ 3.91 $ 3.91 $ 3.97 Anti-dilutive shares

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2024
Regulated Operations [Abstract]
Schedule of Regulatory Assets and Liabilities	We had the following regulatory assets and liabilities as of December 31: 2024 2023 (in millions) Regulatory assets Winter Storm Uri (a) $ 109.5 $ 199.6 Deferred energy and fuel cost adjustments (b) 62.8 55.1 Deferred gas cost adjustments (b) 14.5 4.1 Gas price derivatives (b) 2.9 5.1 Deferred taxes on AFUDC (b) 8.0 7.1 Employee benefit plans and related deferred taxes (c) 89.0 89.3 Environmental (b) 10.7 2.9 Loss on reacquired debt (b) 15.7 17.4 Deferred taxes on flow-through accounting (b) 87.7 74.7 Decommissioning costs (b) 2.4 2.4 Other regulatory assets (b) 24.5 22.4 Total regulatory assets 427.7 480.1 Less current regulatory assets ( 154.8 ) ( 175.7 ) Regulatory assets, non-current $ 272.9 $ 304.4 Regulatory liabilities Deferred energy and gas costs (b) $ 91.9 $ 88.9 Employee benefit plans and related deferred taxes (c) 36.7 36.2 Cost of removal (b) 197.0 181.9 Excess deferred income taxes (c) 238.5 247.1 Other regulatory liabilities (c) 4.6 12.5 Total regulatory liabilities 568.7 566.6 Less current regulatory liabilities ( 94.1 ) ( 98.9 ) Regulatory liabilities, non-current $ 474.6 $ 467.7 (a) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below. (b) Recovery/repayment of costs, but we are not 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 Guarantees (Tables)	12 Months Ended
	Dec. 31, 2024
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: PPAs (a) Transmission Services Agreements Natural gas supply, transportation and storage agreements (in millions) Future commitments for the year ending December 31, 2025 $ — $ 12.3 $ 193.8 2026 — — 171.2 2027 — — 136.5 2028 — — 86.6 2029 — — 23.0 Thereafter — — 109.0 Total future commitments $ — $ 12.3 $ 720.1 ____________________ (a) This schedule does not reflect renewable energy PPA future obligations since these agreements vary based on weather conditions.
Lessor, Operating Lease, Payment to be Received, Fiscal Year Maturity	As of December 31, 2024, scheduled maturities of operating lease payments to be received in future years were as follows: Operating Leases (in millions) 2025 $ 2.1 2026 3.1 2027 1.8 2028 1.8 2029 1.8 Thereafter 48.4 Total lease receivables $ 59.0
Schedule of Guarantor Obligations	We had the following guarantees in place as of: Maximum Exposure at Nature of Guarantee December 31, 2024 (in millions) Indemnification for reclamation/surety bonds $ 75.6 Guarantees supporting business transactions 499.8 Total guarantees $ 575.4

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024, 2023, and 2022. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2024 Electric Utilities Gas Utilities Inter-segment Eliminations Total Customer types: (in millions) Retail $ 698.6 $ 1,022.6 $ — $ 1,721.2 Transportation — 178.2 ( 0.4 ) 177.8 Wholesale 26.8 — — 26.8 Market - off-system sales 34.8 0.1 — 34.9 Transmission 52.2 0.7 — 52.9 Other revenues 58.7 43.1 ( 17.4 ) 84.4 Revenue from contracts with customers 871.1 1,244.7 ( 17.8 ) 2,098.0 Alternative revenue and other 5.0 24.7 — 29.7 Total revenues $ 876.1 $ 1,269.4 $ ( 17.8 ) $ 2,127.7 Timing of revenue recognition: Services transferred at a point in time $ 34.7 $ — $ — $ 34.7 Services transferred over time 836.4 1,244.7 ( 17.8 ) 2,063.3 Revenue from contracts with customers $ 871.1 $ 1,244.7 $ ( 17.8 ) $ 2,098.0 Year ended December 31, 2023 Electric Utilities Gas Utilities Inter-segment Eliminations Total Customer types: (in millions) Retail $ 666.1 $ 1,248.8 $ — $ 1,914.9 Transportation — 176.8 ( 0.5 ) 176.3 Wholesale 34.2 — — 34.2 Market - off-system sales 50.9 0.4 — 51.3 Transmission 47.1 0.7 — 47.8 Other revenues 55.9 38.7 ( 17.4 ) 77.2 Revenue from contracts with customers 854.2 1,465.4 ( 17.9 ) 2,301.7 Alternative revenue and other 10.8 18.8 — 29.6 Total revenues $ 865.0 $ 1,484.2 $ ( 17.9 ) $ 2,331.3 Timing of revenue recognition: Services transferred at a point in time $ 31.5 $ — $ — $ 31.5 Services transferred over time 822.7 1,465.4 ( 17.9 ) 2,270.2 Revenue from contracts with customers $ 854.2 $ 1,465.4 $ ( 17.9 ) $ 2,301.7 Year ended December 31, 2022 Electric Utilities Gas Utilities Inter-segment Eliminations Total Customer types: (in millions) Retail $ 709.2 $ 1,453.3 $ — $ 2,162.5 Transportation — 173.3 ( 0.4 ) 172.9 Wholesale 44.8 — — 44.8 Market - off-system sales 48.6 0.8 — 49.4 Transmission 40.5 0.8 — 41.3 Other revenues 51.5 37.1 ( 16.6 ) 72.0 Revenue from contracts with customers 894.6 1,665.3 ( 17.0 ) 2,542.9 Alternative revenue and other 5.6 3.8 ( 0.5 ) 8.9 Total revenues $ 900.2 $ 1,669.1 $ ( 17.5 ) $ 2,551.8 Timing of revenue recognition: Services transferred at a point in time $ 30.4 $ — $ — $ 30.4 Services transferred over time 864.2 1,665.3 ( 17.0 ) 2,512.5 Revenue from contracts with customers $ 894.6 $ 1,665.3 $ ( 17.0 ) $ 2,542.9

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2024
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, plant, and equipment at December 31 consisted of the following: 2024 2023 Lives Electric Utilities Property, Plant and Equipment Weighted Average Useful Life Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum (dollars in millions, life in years) (in years) Electric plant: Production $ 1,508.5 39 $ 1,492.8 40 32 44 Electric transmission 793.7 48 737.4 48 42 51 Electric distribution 1,238.5 47 1,146.9 47 45 50 Integrated Generation 724.0 30 720.0 30 19 38 Plant acquisition adjustment (a) 4.9 32 4.9 32 32 32 General 306.6 26 291.7 27 23 27 Total electric plant in service 4,576.2 4,393.7 Construction work-in-progress 259.4 123.1 Total electric plant 4,835.6 4,516.8 Less accumulated depreciation ( 1,280.3 ) ( 1,207.7 ) Electric plant net of accumulated depreciation $ 3,555.3 $ 3,309.1 ____________________ (a) The plant acquisition adjustment, which relates to the acquisition of our ownership interest in Wyodak Plant, is included in rate base and is being recovered w ith 6 years remaining. 2024 2023 Lives Gas Utilities Property, Plant and Equipment Weighted Average Useful Life Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum (dollars in millions, life in years) (in years) Gas plant: Production $ 21.6 43 $ 21.0 45 24 45 Gas transmission 817.5 58 759.5 58 32 73 Gas distribution 3,107.3 57 2,860.0 57 48 61 Cushion gas - not depreciable (a) 52.1 N/A 58.2 N/A N/A N/A Storage 78.8 42 71.4 42 36 48 General 599.4 22 571.8 22 20 24 Total gas plant in service 4,676.7 4,341.9 Construction work-in-progress 43.5 39.2 Total gas plant 4,720.2 4,381.1 Less accumulated depreciation ( 656.3 ) ( 588.3 ) Gas plant net of accumulated depreciation $ 4,063.9 $ 3,792.8 ____________________ (a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. 2024 2023 Lives Corporate Property, Plant and Equipment Weighted Average Useful Life Property, Plant and Equipment Weighted Average Useful Life Minimum Maximum (dollars in millions, life in years) (in years) Total plant in service $ 0.4 10 $ 5.7 10 4 21 Construction work-in-progress 10.3 13.6 Total gross property, plant and equipment 10.7 19.3 Less accumulated depreciation — ( 1.9 ) Total net of accumulated depreciation $ 10.7 $ 17.4

Jointly Owned Facilities (Table

Jointly Owned Facilities (Tables)	12 Months Ended
	Dec. 31, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Jointly Owned Utility Plants	At December 31, 2024, our interests in jointly-owned generating facilities and transmission systems were: Ownership Interest Plant in Service Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation (in millions) Wyodak Plant (a) 20 % $ 123.0 $ — $ ( 76.8 ) $ 46.2 Transmission Tie 35 % $ 24.5 $ 0.3 $ ( 8.3 ) $ 16.5 Wygen III (b) 52 % $ 144.8 $ 0.3 $ ( 33.0 ) $ 112.1 Wygen I (c) 76.5 % $ 116.3 $ 1.9 $ ( 61.6 ) $ 56.6

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2024
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: December 31, 2023 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2024 (in millions) Electric Utilities $ 28.7 $ — $ — $ 1.1 $ 0.2 $ 30.0 Gas Utilities 67.5 0.2 — 3.0 — 70.7 Total $ 96.2 $ 0.2 $ — $ 4.1 $ 0.2 $ 100.7 December 31, 2022 Liabilities Incurred Liabilities Settled Accretion Revisions to Prior Estimates December 31, 2023 (in millions) Electric Utilities $ 27.6 $ — $ — $ 1.2 $ ( 0.1 ) $ 28.7 Gas Utilities (a) 61.3 6.7 — 2.3 ( 2.8 ) 67.5 Total $ 88.9 $ 6.7 $ — $ 3.5 $ ( 2.9 ) $ 96.2 (a) The Revisions to Prior Estimates were primarily driven by changes in estimates associated with natural gas wells and compressor stations.

Financing (Tables)

Financing (Tables)	12 Months Ended
	Dec. 31, 2024
Debt Disclosure [Abstract]
Schedule of Short-term Debt	Our Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following borrowings, outstanding letters of credit, and available capacity at December 31: 2024 2023 (dollars in millions) Amount outstanding $ 133.8 $ — Letters of credit (a) 3.5 3.7 Available capacity 612.7 746.3 Weighted average interest rates 4.74 % N/A (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 borrowing activity for the years ended December 31 was as follows: 2024 2023 (dollars in millions) Maximum amount outstanding (based on daily outstanding balances) $ 140.6 $ 548.7 Average amount outstanding (based on daily outstanding balances) 17.1 81.7 Weighted average interest rates 4.86 % 4.91 %
Schedule of Long-term Debt Instruments	Long-term debt outstanding was as follows: Interest Rate at Balance Outstanding Due Date December 31, 2024 December 31, 2024 December 31, 2023 (in millions) Corporate Senior unsecured notes due 2024 August 23, 2024 N/A $ — $ 600.0 Senior unsecured notes due 2026 January 15, 2026 3.95 % 300.0 300.0 Senior unsecured notes due 2027 January 15, 2027 3.15 % 400.0 400.0 Senior unsecured notes due 2028 March 15, 2028 5.95 % 350.0 350.0 Senior unsecured notes, due 2029 October 15, 2029 3.05 % 400.0 400.0 Senior unsecured notes, due 2030 June 15, 2030 2.50 % 400.0 400.0 Senior unsecured notes due 2033 May 1, 2033 4.35 % 400.0 400.0 Senior unsecured notes due 2034 May 15, 2034 6.15 % 450.0 450.0 Senior unsecured notes due 2035 January 15, 2035 6.00 % 450.0 — Senior unsecured notes, due 2046 September 15, 2046 4.20 % 300.0 300.0 Senior unsecured notes, due 2049 October 15, 2049 3.88 % 300.0 300.0 Total Corporate debt 3,750.0 3,900.0 Less unamortized debt discount ( 8.6 ) ( 8.9 ) Total Corporate debt, net 3,741.4 3,891.1 South Dakota Electric First Mortgage Bonds due 2032 (a) August 15, 2032 7.23 % 75.0 75.0 First Mortgage Bonds due 2039 (a) November 1, 2039 6.13 % 180.0 180.0 First Mortgage Bonds due 2044 (a) October 20, 2044 4.43 % 85.0 85.0 Total South Dakota Electric debt 340.0 340.0 Less unamortized debt discount ( 0.1 ) ( 0.1 ) Total South Dakota Electric debt, net 339.9 339.9 Wyoming Electric Industrial development revenue bonds due 2027 (b) (c) March 1, 2027 3.68 % 10.0 10.0 First Mortgage Bonds due 2037 (a) November 20, 2037 6.67 % 110.0 110.0 First Mortgage Bonds due 2044 (a) October 20, 2044 4.53 % 75.0 75.0 Total Wyoming Electric debt 195.0 195.0 Less unamortized debt discount — — Total Wyoming Electric debt, net 195.0 195.0 Total long-term debt 4,276.3 4,426.0 Less current maturities — ( 600.0 ) Less unamortized deferred financing costs (d) ( 26.1 ) ( 24.8 ) Long-term debt, net of current maturities and deferred financing costs $ 4,250.2 $ 3,801.2 (a) 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. (b) Variable interest rate. (c) A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the $ 10 million bonds due March 1, 2027. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. (d) Includes deferred financing costs associated with our Revolving Credit Facilit y of $ 2.4 million and $ 1.1 million as of December 31, 2024, and December 31, 2023 , respectively.
Schedule of Maturities of Long-term Debt	Scheduled maturities of long-term debt and associated interest payments by year are shown below: Payments Due by Period 2025 2026 2027 2028 2029 Thereafter Total (in millions) Principal payments on Long-term debt including current maturities (a) $ — $ 300.0 $ 410.0 $ 350.0 $ 400.0 $ 2,825.0 $ 4,285.0 Interest payments on Long-term debt (a) 199.5 189.2 176.6 159.9 149.4 1,078.3 1,952.9 (a) Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2024. We believe it is probable that we will be able to successfully re-finance our $ 300 million, 3.95 %, senior unsecured notes due on January 15, 2026, at or before maturity date.
Summary of ATM Activity	ATM activity for the years ended December 31 was as follows: December 31, 2024 December 31, 2023 December 31, 2022 (in millions, except per share amounts) August 4, 2020 ATM Program Proceeds, (net of issuance costs of $ 0.0 , $( 0.5 ), and $( 0.9 ), respectively) $ — $ 48.5 $ 90.3 Number of shares issued — 0.8 1.3 June 16, 2023 ATM Program Proceeds, (net of issuance costs of $( 1.8 ), $( 0.7 ), and $ 0 , respectively $ 181.6 $ 70.2 $ — Number of shares issued 3.3 1.2 — Total activity under both ATM Programs Proceeds, (net of issuance costs of $( 1.8 ), $( 1.2 ), and $( 0.9 ), respectively) $ 181.6 $ 118.7 $ 90.3 Number of shares issued 3.3 2.0 1.3 Average price per share $ 55.63 $ 59.04 $ 69.74

Risk Management And Derivativ_2

Risk Management And Derivatives (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 December 31, 2023 Units Notional Amounts Maximum Term (months) (a) Notional Amounts Maximum Term (months) (a) Natural gas futures purchased MMBtus 660,000 3 650,000 3 Natural gas options purchased, net MMBtus 2,780,000 3 2,850,000 3 Natural gas basis swaps purchased MMBtus 1,080,000 3 1,050,000 3 Natural gas over-the-counter swaps, net (b) MMBtus 3,480,000 20 3,890,000 21 Natural gas physical commitments, net (c) MMBtus 20,276,230 10 12,582,415 10 (a) Term reflects the maximum forward period hedged. (b) As of December 31, 2024 , 1,427,000 MMBtus 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: Balance Sheet Location 2024 2023 (in millions) Derivatives designated as hedges: Liability derivative instruments: Current commodity derivatives Derivative liabilities - current $ ( 0.7 ) $ ( 2.7 ) Noncurrent commodity derivatives Other deferred credits and other liabilities — ( 0.2 ) Total derivatives designated as hedges $ ( 0.7 ) $ ( 2.9 ) Derivatives not designated as hedges: Liability derivative instruments: Current commodity derivatives Derivative liabilities - current $ ( 3.5 ) $ ( 3.8 ) Noncurrent commodity derivatives Other deferred credits and other liabilities — ( 0.1 ) Total derivatives not designated as hedges $ ( 3.5 ) $ ( 3.9 )
Derivative Instruments, Gain (Loss)	The impact of cash flow hedges on our Consolidated Statements of Comprehensive Income and Consolidated Statements of Income is presented below for the years ended December 31, 2024, 2023, and 2022. 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. 2024 2023 2022 2024 2023 2022 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 millions) (in millions) Interest rate swaps $ 2.9 $ 2.9 $ 2.8 Interest expense $ ( 2.9 ) $ ( 2.9 ) $ ( 2.8 ) Commodity derivatives 2.9 ( 1.6 ) ( 3.5 ) Fuel, purchased power and cost of natural gas sold ( 3.5 ) ( 3.0 ) 2.7 Total $ 5.8 $ 1.3 $ ( 0.7 ) $ ( 6.4 ) $ ( 5.9 ) $ ( 0.1 ) As of December 31, 2024, $ 3.3 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, 2024, 2023, and 2022. 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. 2024 2023 2022 Derivatives Not Designated as Hedging Instruments Location of Gain/(Loss) on Derivatives Recognized in Income Amount of Gain/(Loss) on Derivatives Recognized in Income (in millions) Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold $ 0.7 $ ( 4.2 ) $ ( 0.8 ) $ 0.7 $ ( 4.2 ) $ ( 0.8 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2024
Fair Value Disclosures [Abstract]
Schedule of Fair Value Hierarchy, 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, 2024 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in millions) Assets: Commodity derivatives $ — $ 2.2 $ — $ ( 2.2 ) $ — Total $ — $ 2.2 $ — $ ( 2.2 ) $ — Liabilities: Commodity derivatives $ — $ 4.8 $ — $ ( 0.6 ) $ 4.2 Total $ — $ 4.8 $ — $ ( 0.6 ) $ 4.2 (a) As of December 31, 2024, $ 2.2 million of our commodity derivative gross assets and $ 0.6 million of o ur commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements. As of December 31, 2023 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total (in millions) Assets: Commodity derivatives $ — $ 1.9 $ — $ ( 1.9 ) $ — Total $ — $ 1.9 $ — $ ( 1.9 ) $ — Liabilities: Commodity derivatives $ — $ 10.1 $ — $ ( 3.3 ) $ 6.8 Total $ — $ 10.1 $ — $ ( 3.3 ) $ 6.8 (a) As of December 31, 2023, $ 1.9 million of our commodity derivative assets and $ 3.3 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: 2024 2023 Carrying Amount Fair Value Carrying Amount Fair Value (in millions) Long-term debt, including current maturities (a) $ 4,250.2 $ 4,059.1 $ 4,401.2 $ 4,215.6 (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, 2024
Statement of Comprehensive Income [Abstract]
Reclassification out of Accumulated Other Comprehensive Income	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: Location on the Consolidated Amount Reclassified from AOCI Statements of Income December 31, 2024 December 31, 2023 (in millions) Gains and (losses) on cash flow hedges: Interest rate swaps Interest expense $ ( 2.9 ) $ ( 2.9 ) Commodity contracts Fuel, purchased power, and cost of natural gas sold ( 3.5 ) ( 3.0 ) ( 6.4 ) ( 5.9 ) Income tax Income tax benefit (expense) 1.4 1.4 Total reclassification adjustments related to cash flow hedges, net of tax $ ( 5.0 ) $ ( 4.5 ) Amortization of components of defined benefit plans: Prior service cost Operations and maintenance $ — $ — Actuarial gain (loss) Operations and maintenance ( 0.2 ) ( 0.2 ) ( 0.2 ) ( 0.2 ) Income tax Income tax benefit (expense) 0.1 — Total reclassification adjustments related to defined benefit plans, net of tax $ ( 0.1 ) $ ( 0.2 ) Total reclassifications $ ( 5.1 ) $ ( 4.7 )
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: Derivatives Designated as Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total (in millions) As of December 31, 2022 $ ( 8.3 ) $ ( 1.2 ) $ ( 6.1 ) $ ( 15.6 ) Other comprehensive income (loss) before reclassifications — ( 3.6 ) ( 0.3 ) ( 3.9 ) Amounts reclassified from AOCI 2.2 2.3 0.2 4.7 As of December 31, 2023 $ ( 6.1 ) $ ( 2.5 ) $ ( 6.2 ) $ ( 14.8 ) Other comprehensive income (loss) before reclassifications — ( 0.5 ) 0.8 0.3 Amounts reclassified from AOCI 2.3 2.7 0.1 5.1 As of December 31, 2024 $ ( 3.8 ) $ ( 0.3 ) $ ( 5.3 ) $ ( 9.4 )

Variable Interest Entity (Table

Variable Interest Entity (Tables)	12 Months Ended
	Dec. 31, 2024
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: 2024 2023 (in millions) Assets: Current assets $ 11.7 $ 15.1 Property, plant and equipment $ 160.4 $ 166.8 Liabilities: Current liabilities $ 8.3 $ 4.8

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2024
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: Return-seeking Assets 2024 2023 Equity 19 % 14 % Real estate 5 % 5 % Hedge funds 3 % 3 % Fixed income 3 % 2 % Total 30 % 24 % Liability-hedging Assets 2024 2023 Fixed income 68 % 74 % Cash 2 % 2 % Total 70 % 76 % Total Assets 100 % 100 %
Schedule of Employer Contribution to Employee Benefit Plans	Contributions for the years ended December 31 were as follows: 2024 2023 (in millions) Defined Contribution Plan Company retirement contributions $ 11.3 $ 12.7 Company matching contributions 17.7 17.1 Defined Benefit Plans Pension Plan $ 2.3 $ — Healthcare Plan 5.7 5.4 Supplemental Plans 4.1 3.5
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 on our Consolidated Balance Sheets, accumulated benefit obligation, and elements of AOCI: Pension Plan Supplemental Plans Healthcare Plan 2024 2023 2024 2023 2024 2023 (in millions) Accumulated benefit obligation at December 31 $ 307.1 $ 341.8 $ 46.1 $ 46.7 $ 48.5 $ 51.1 Change in benefit obligation: Projected benefit obligation at beginning of year $ 348.1 $ 358.4 $ 46.7 $ 45.2 $ 51.1 $ 49.7 Service cost 2.3 2.5 3.3 3.1 1.6 1.5 Interest cost 16.4 17.5 1.4 1.5 2.4 2.4 Actuarial (gain) loss ( 16.0 ) 11.6 ( 1.2 ) 0.3 ( 1.7 ) 1.7 Benefits paid ( 39.2 ) ( 41.9 ) ( 4.1 ) ( 3.4 ) ( 5.7 ) ( 5.3 ) Plan participants’ contributions — — — — 0.8 1.1 Projected benefit obligation at end of year 311.6 348.1 46.1 46.7 48.5 51.1 Change in fair value of plan assets: Fair value of plan assets at beginning of year 308.6 323.1 — — 8.0 7.8 Investment income (loss) ( 1.6 ) 27.4 — — 0.1 0.2 Employer contributions 2.3 — 4.1 3.5 4.2 4.3 Retiree contributions — — — — 0.9 1.1 Benefits paid ( 39.1 ) ( 41.9 ) ( 4.1 ) ( 3.5 ) ( 5.7 ) ( 5.4 ) Fair value of plan assets at end of year 270.2 308.6 — — 7.5 8.0 Funded status - deficiency $ 41.4 $ 39.5 $ 46.1 $ 46.7 $ 41.0 $ 43.1 Amounts recognized on our Consolidated Balance Sheets as of December 31: Regulatory assets $ 81.6 $ 79.9 $ — $ — $ 4.9 $ 4.8 Current liabilities — — 2.8 2.4 4.3 4.2 Non-current assets — — — — — 1.3 Non-current liabilities 41.4 39.4 43.3 44.3 36.7 40.2 Regulatory liabilities 3.1 2.9 — — 7.3 5.5 Amounts recognized in AOCI, net of tax as of December 31: Net (gain) loss $ 5.2 $ 5.0 $ 0.8 $ 1.8 $ ( 0.7 ) $ ( 0.7 ) Prior service cost (gain) — — — — — 0.1 Total amounts included in AOCI, net of tax not yet recognized as components of net periodic expense $ 5.2 $ 5.0 $ 0.8 $ 1.8 $ ( 0.7 ) $ ( 0.6 )
Components of Net Periodic Benefit Cost	The following table provides a reconciliation of components of the net periodic expense: Pension Plan Supplemental Plans Healthcare Plan For the years ended December 31, 2024 2023 2022 2024 2023 2022 2024 2023 2022 (in millions) Service cost $ 2.3 $ 2.5 $ 3.9 $ 3.3 $ 3.1 $ ( 0.8 ) $ 1.6 $ 1.5 $ 1.9 Interest cost 16.4 17.5 10.8 1.4 1.5 0.8 2.4 2.4 1.3 Expected return on assets ( 18.0 ) ( 18.7 ) ( 18.5 ) — — — ( 0.3 ) ( 0.2 ) ( 0.1 ) Net amortization of prior service cost ( 0.1 ) ( 0.1 ) ( 0.1 ) — — — 0.2 — ( 0.3 ) Recognized net actuarial loss (gain) 2.0 2.0 6.1 — — 0.3 — — 0.1 Net periodic expense $ 2.6 $ 3.2 $ 2.2 $ 4.7 $ 4.6 $ 0.3 $ 3.9 $ 3.7 $ 2.9
Schedule of Assumptions Used	Assumptions Pension Plan Supplemental Plans Healthcare Plan 2024 2023 2022 2024 2023 2022 2024 2023 2022 Weighted-average assumptions used to determine benefit obligations: Discount rate 5.63 % 4.99 % 5.17 % 5.56 % 4.93 % 5.13 % 5.60 % 4.97 % 5.14 % Rate of increase in compensation levels 3.04 % 3.04 % 3.06 % — — — N/A N/A N/A Weighted-average assumptions used to determine net periodic benefit cost for plan year: Discount rate (a) 4.99 % 5.17 % 2.88 % 4.93 % 5.13 % 2.77 % 4.97 % 5.14 % 2.79 % Expected long-term rate of return on assets (b) 6.00 % 6.00 % 4.25 % N/A N/A N/A 3.50 % 3.10 % 1.70 % Rate of increase in compensation levels 3.04 % 3.06 % 3.08 % — — — N/A N/A N/A (a) The estimated discount rate for the Defined Benefit Pension Plan is 5.63 % for the calculation of the 2025 net periodic pension costs. (b) The expected rate of return on plan as sets for the Defined Benefit Pension Plan is 6.50 % for the calculation of the 2025 net periodic pension cost.
Schedule of Health Care Cost Trend Rates	The healthcare benefit obligation at December 31 was determined as follows: 2024 2023 Trend Rate - Medical Pre-65 for next year - All Plans 7.50 % 6.69 % Pre-65 Ultimate trend rate - Black Hills Corp 4.50 % 4.50 % Trend Year 2035 2034 Post-65 for next year - All Plans 6.50 % 5.81 % Post-65 Ultimate trend rate - Black Hills Corp 4.50 % 4.50 % Trend Year 2033 2034
Schedule of Expected Benefit Payments	The following benefit payments to employees, which reflect future service, are expected to be paid: Pension Plan Supplemental Plans Healthcare Plan (in millions) 2025 $ 24.4 $ 2.8 $ 5.3 2026 24.8 2.8 5.1 2027 25.1 2.7 5.0 2028 25.1 2.7 4.8 2029 25.6 2.5 4.7 2030 - 2034 $ 123.5 $ 11.3 $ 21.4
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: December 31, 2024 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments (in millions) Pension Plan Common Collective Trust - Cash and Cash Equivalents $ — $ 5.4 $ — $ 5.4 $ — $ 5.4 Common Collective Trust - Equity — 51.5 — 51.5 — 51.5 Common Collective Trust - Fixed Income — 190.8 — 190.8 — 190.8 Common Collective Trust - Real Estate — — — — 14.9 14.9 Hedge Funds — — — — 7.6 7.6 Total investments measured at fair value $ — $ 247.7 $ — $ 247.7 $ 22.5 $ 270.2 Healthcare Plan Cash and Cash Equivalents 7.5 — — 7.5 — 7.5 Total investments measured at fair value $ 7.5 $ — $ — $ 7.5 $ — $ 7.5 December 31, 2023 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value NAV (a) Total Investments (in millions) Pension Plan Common Collective Trust - Cash and Cash Equivalents $ — $ 6.7 $ — $ 6.7 $ — $ 6.7 Common Collective Trust - Equity — 42.7 — 42.7 — 42.7 Common Collective Trust - Fixed Income — 234.5 — 234.5 — 234.5 Common Collective Trust - Real Estate — — — — 16.4 16.4 Hedge Funds — — — — 8.1 8.1 Total investments measured at fair value $ — $ 283.9 $ — $ 283.9 $ 24.5 $ 308.4 Healthcare Plan Cash and Cash Equivalents 8.0 — — 8.0 — 8.0 Total investments measured at fair value $ 8.0 $ — $ — $ 8.0 $ — $ 8.0 (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.

Share-based Compensation Plans

Share-based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2024
Share-Based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Expensed Amount	Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the ye ars ended December 31: 2024 2023 2022 (in millions) Stock-based compensation expense $ 10.6 $ 7.0 $ 8.6
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, 2024, was as follows: Restricted Stock Weighted-Average Grant Date Fair Value Balance at January 1, 2024 164,687 $ 64.81 Granted 180,676 53.58 Vested ( 83,737 ) 65.11 Forfeited ( 29,684 ) 59.13 Balance at December 31, 2024 231,942 $ 56.68 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 millions) 2024 $ 53.58 $ 4.5 2023 $ 63.33 $ 5.9 2022 $ 69.03 $ 6.4
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	The Monte Carlo simulation is used to estimate expected share payout based on the Company’s TSR for a three-year performance period relative to the designated peer group beginning January 1 of the award year. The significant assumptions included in the company's Monte Carlo simulations were as follows: 2024 2023 Fair value of share units award $ 55.14 $ 77.95 Risk-free rate 4.12 % 3.84 % Black Hills Corporation’s common stock volatility 24 % 31 % Volatility range for the peer group 12 - 53 % 24 - 39 %
Schedule of Nonvested Share Activity	The following table summarizes the performance share unit activity for the year ended December 31, 2024: Performance Share Units - Performance Share Units - Share Units Weighted-Average Fair Value per Share Unit Share Units Weighted-Average Fair Value per Share Unit Nonvested at January 1, 2024 110,747 $ 73.31 62,654 $ 67.88 Granted 71,537 55.14 30,663 51.00 Vested ( 30,749 ) 64.97 ( 20,512 ) 61.45 Nonvested at December 31, 2024 151,535 $ 66.43 72,805 $ 62.59

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
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: 2024 2023 2022 (in millions) Current: Federal $ 16.5 $ 0.8 $ 0.5 State ( 0.8 ) ( 1.0 ) ( 0.1 ) Current income tax benefit (expense) 15.7 ( 0.2 ) 0.4 Deferred: Federal ( 47.2 ) ( 30.9 ) ( 23.2 ) State ( 4.8 ) 5.5 ( 2.4 ) Deferred income tax (expense) ( 52.0 ) ( 25.4 ) ( 25.6 ) Income tax (expense) $ ( 36.3 ) $ ( 25.6 ) $ ( 25.2 )
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: 2024 2023 2022 Federal statutory rate 21.0 % 21.0 % 21.0 % State income tax (net of federal tax effect) (a) 1.3 ( 0.8 ) 0.5 Non-controlling interest (b) ( 0.7 ) ( 1.0 ) ( 0.9 ) Tax credits ( 5.6 ) ( 6.2 ) ( 7.7 ) Flow-through adjustments (c) ( 2.2 ) ( 1.7 ) ( 1.4 ) Amortization of excess deferred income taxes (d) ( 2.4 ) ( 3.0 ) ( 2.5 ) Other ( 0.1 ) 0.2 ( 0.5 ) Effective Tax Rate 11.3 % 8.5 % 8.5 % (a) For the year ended December 31, 2023, we recognized an $ 8.2 million tax benefit from a Nebraska income tax rate decrease. (b) The effective tax rate reflects the income attributable to the non-controlling interest in Black Hills Colorado IPP for which a tax provision was not recorded. (c) 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. (d) Primarily TCJA - see Note 2 for additional information.
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: 2024 2023 (in millions) Deferred tax assets: Regulatory liabilities $ 70.9 $ 74.0 State tax credits 8.4 22.8 Federal NOL 114.9 146.6 State NOL 12.7 16.5 Partnership 11.6 12.2 Credit Carryovers 110.5 110.1 Other deferred tax assets 35.4 33.7 Less: Valuation allowance ( 1.3 ) ( 15.4 ) Total deferred tax assets 363.1 400.5 Deferred tax liabilities: Accelerated depreciation, amortization, and other property-related differences ( 729.2 ) ( 686.2 ) Regulatory assets ( 49.5 ) ( 65.6 ) Goodwill ( 75.9 ) ( 67.8 ) State deferred tax liability ( 88.7 ) ( 84.5 ) Other deferred tax liabilities ( 44.9 ) ( 44.4 ) Total deferred tax liabilities ( 988.2 ) ( 948.5 ) Net deferred tax liability $ ( 625.1 ) $ ( 548.0 )
Summary of Operating Loss and Tax Credit Carryforwards	At December 31, 2024, we have federal NOL and state NOL and tax credit carryforwards that will expire at various dates as follows: Amounts Expiration Dates (in millions) Federal NOL Carryforward $ 547.2 No expiration Federal Tax Credit Carryforward $ 110.5 2030-2044 State NOL Carryforward (a) $ 242.6 2025-2042 State Tax Credit Carryforward $ 8.4 2025-2038 (a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.
Reconciliation of 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: Changes in Uncertain Tax Positions: 2024 2023 2022 (in millions) Beginning balance $ 13.7 $ 11.9 $ 10.6 Additions for prior year tax positions 0.6 — - Reductions for prior year tax positions ( 8.1 ) ( 0.3 ) ( 0.8 ) Additions for current year tax positions 1.6 2.1 2.1 Ending balance $ 7.8 $ 13.7 $ 11.9

Business Segment Information (T

Business Segment Information (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Reporting Information, Additional Information [Abstract]
Segment information included in Consolidated Balance Sheets	Capital Expenditures (a) for the years ended December 31, 2024 2023 2022 (in millions) Electric Utilities $ 381.9 $ 210.7 $ 243.1 Gas Utilities 402.7 371.9 349.5 Corporate and Other 13.0 7.3 5.1 Total capital expenditures $ 797.6 $ 589.9 $ 597.7 (a) Includes accruals for property, plant, and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows .
Segment information included in Consolidated Statements of Income	Segment information was as follows: Consolidating Income Statement Year Ended December 31, 2024 Electric Utilities Gas Utilities Corporate Total (in millions) Revenue - External Customers $ 864.4 $ 1,263.3 $ — $ 2,127.7 Inter-segment 11.7 6.1 ( 17.8 ) — Total revenue 876.1 1,269.4 ( 17.8 ) 2,127.7 Fuel, purchased power and cost of natural gas sold 206.4 524.3 ( 0.4 ) 730.3 Operations and maintenance (a) - Direct 127.5 155.4 ( 16.3 ) 266.6 Allocated 125.1 165.3 — 290.4 Depreciation, depletion and amortization 145.3 124.7 0.1 270.1 Taxes other than income taxes 38.8 28.4 — 67.2 Operating income (loss) $ 233.0 $ 271.3 $ ( 1.2 ) $ 503.1 Interest expense, net ( 181.7 ) Other income (expense), net ( 1.4 ) Income tax (expense) ( 36.3 ) Net income 283.7 Net income attributable to non-controlling interest ( 10.6 ) Net income available for common stock $ 273.1 Consolidating Income Statement Year Ended December 31, 2023 Electric Utilities Gas Utilities Corporate Total (in millions) Revenue - External Customers $ 853.6 $ 1,477.7 $ — $ 2,331.3 Inter-segment 11.4 6.5 ( 17.9 ) — Total revenue 865.0 1,484.2 ( 17.9 ) 2,331.3 Fuel, purchased power and cost of natural gas sold 200.1 783.2 ( 0.4 ) 982.9 Operations and maintenance (a) - Direct 112.2 162.2 ( 12.9 ) 261.5 Allocated 124.0 166.5 — 290.5 Depreciation, depletion and amortization 142.6 113.9 0.3 256.8 Taxes other than income taxes 37.3 29.6 — 66.9 Operating income (loss) $ 248.8 $ 228.8 $ ( 4.9 ) $ 472.7 Interest expense, net ( 167.9 ) Other income (expense), net ( 3.2 ) Income tax (expense) ( 25.6 ) Net income 276.0 Net income attributable to non-controlling interest ( 13.8 ) Net income available for common stock $ 262.2 Consolidating Income Statement Year Ended December 31, 2022 Electric Utilities Gas Utilities Corporate Total (in millions) Revenue - External Customers $ 888.4 $ 1,663.4 $ — $ 2,551.8 Inter-segment 11.8 5.7 ( 17.5 ) — Total revenue 900.2 1,669.1 ( 17.5 ) 2,551.8 Fuel, purchased power and cost of natural gas sold 266.3 965.1 ( 0.8 ) 1,230.6 Operations and maintenance (a) - Direct 124.0 158.5 ( 13.7 ) 268.8 Allocated 120.8 158.8 — 279.6 Depreciation, depletion and amortization 135.9 114.7 0.3 250.9 Taxes other than income taxes 38.9 27.8 — 66.7 Operating income (loss) $ 214.3 $ 244.2 $ ( 3.3 ) $ 455.2 Interest expense, net ( 161.0 ) Other income (expense), net 1.8 Income tax (expense) ( 25.2 ) Net income 270.8 Net income attributable to non-controlling interest ( 12.4 ) Net income available for common stock $ 258.4 (a) Direct and Allocated Operations and maintenance expenses for our operating segments are regularly provided to the CODM. Direct expenses represents the costs incurred directly by our operating segments. Allocated expenses represent costs incurred by BHSC for various direct and indirect support services provided to our operating segments. Pursuant to the BHSC Cost Allocation Manual, indirect cost allocations are determined in accordance with PUHCA 2005.

Business Description And Sign_4

Business Description And Significant Accounting Policies: Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Billed Accounts Receivable	$ 201.5	$ 198.5
Unbilled Revenue	151.8	154
Less Allowance for Credit Losses	(2.1)	(2.2)	$ (3)	$ (2.1)
Accounts Receivable, net	$ 351.2	$ 350.3

Business Description And Sign_5

Business Description And Significant Accounting Policies: Changes to Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance at Beginning of Year	$ 2.2	$ 3	$ 2.1
Additions Charged to Costs and Expenses	5.6	8.7	9.1
Recoveries and Other Additions	4.2	4.1	3.5
Write-offs and Other Deductions	(9.9)	(13.6)	(11.7)
Balance at End of Year	$ 2.1	$ 2.2	$ 3

Business Description And Sign_6

Business Description And Significant Accounting Policies: Materials, Supplies and Fuel (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Inventory, Net [Abstract]
Materials and supplies	$ 106.1	$ 105.9
Fuel	7.5	7.7
Natural gas in storage	40.3	47.3
Total materials, supplies and fuel	$ 153.9	$ 160.9

Business Description And Sign_7

Business Description And Significant Accounting Policies: Property, Plant and Equipment (AFUDC) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Interest expense incurred net of amounts capitalized
AFUDC Debt	$ 8.7	$ 6	$ 5.6
Other Nonoperating Income (Expense)
AFUDC Equity	$ 4	$ 0.4	$ 0.6

Business Description And Sign_8

Business Description And Significant Accounting Policies: Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Goodwill [Line Items]
Goodwill	$ 1,299.5	$ 1,299.5
Electric Utilities
Goodwill [Line Items]
Goodwill	257.3	257.3
Gas Utilities
Goodwill [Line Items]
Goodwill	$ 1,042.2	$ 1,042.2

Business Description And Sign_9

Business Description And Significant Accounting Policies: Schedule of Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Roll Forward]
Intangible assets, net, beginning balance	$ 8.4	$ 9.6	$ 10.8
Intangible assets, Additions	0.3	0	0
Intangible assets, amortization expense	(1.1)	(1.2)	(1.2)
Intangible assets, net, ending balance	7.6	$ 8.4	$ 9.6
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Future Amortization Expense, Year Five	$ 1.2
Minimum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life	1 year
Maximum
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Useful Life	17 years

Business Description And Sig_10

Business Description And Significant Accounting Policies: Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued employee compensation, benefits and withholdings	$ 85.5	$ 74.8
Accrued property taxes	54.7	52.7
Customer deposits and prepayments	55.6	76
Accrued interest	56.4	46.3
Other (none of which is individually significant)	50	43.5
Total accrued liabilities	$ 302.2	$ 293.3

Business Description And Sig_11

Business Description And Significant Accounting Policies: Earnings Per Share Reconciliation (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Net income available for common stock	$ 273.1	$ 262.2	$ 258.4
Weighted average shares - Basic (in shares)	69.8	67	64.9
Dilutive effect of equity compensation	0.1	0.1	0.1
Weighted average shares - diluted (in shares)	69.9	67.1	65
Net income available for common stock, per share - Diluted	$ 3.91	$ 3.91	$ 3.97

Regulatory Matters_ Regulatory

Regulatory Matters: Regulatory Matters (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Regulatory assets	$ 427.7	$ 480.1
Regulatory assets, current	(154.8)	(175.7)
Regulatory assets, non-current	272.9	304.4
Regulatory liabilities	568.7	566.6
Regulatory liabilities, current	(94.1)	(98.9)
Regulatory liabilities, non-current	$ 474.6	467.7
Maximum
Gas Price Derivatives - Term of Contract	2 years
Deferred energy and gas costs
Regulatory liabilities	$ 91.9	88.9
Employee benefit plans and related deferred taxes
Regulatory liabilities	36.7	36.2
Cost of removal
Regulatory liabilities	197	181.9
Excess deferred income taxes
Regulatory liabilities	238.5	247.1
Other regulatory liabilities
Regulatory liabilities	4.6	12.5
Storm Costs
Regulatory assets	$ 109.5	199.6
Regulatory Asset, Amortization Period	1 year 7 months 6 days
Deferred energy and gas costs
Regulatory assets	$ 62.8	55.1
Deferred gas cost adjustments
Regulatory assets	14.5	4.1
Gas price derivatives
Regulatory assets	2.9	5.1
Deferred taxes on AFUDC
Regulatory assets	8	7.1
Employee benefit plans and related deferred taxes
Regulatory assets	89	89.3
Environmental
Regulatory assets	10.7	2.9
Loss on reacquired debt
Regulatory assets	15.7	17.4
Deferred taxes on flow through accounting
Regulatory assets	87.7	74.7
Decommissioning costs
Regulatory assets	2.4	2.4
Other regulatory assets
Regulatory assets	$ 24.5	$ 22.4

Regulatory Matters_ Winter Stor

Regulatory Matters: Winter Storm Uri (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 427.7	$ 480.1
Storm Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 109.5	199.6
Regulatory Asset, Amortization Period	1 year 7 months 6 days
Deferred gas cost adjustments
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 14.5	$ 4.1

Regulatory Matters_ Gas Utiliti

Regulatory Matters: Gas Utilities Recent Regulatory Activity (Details) $ in Millions						1 Months Ended
	Feb. 03, 2025 USD ($) mi	Dec. 02, 2024 USD ($)	Oct. 01, 2024 USD ($)	Jun. 14, 2024 USD ($) mi	Jan. 17, 2024 USD ($)	Mar. 31, 2024 USD ($)	May 01, 2024 mi	Dec. 04, 2023 mi	May 18, 2023 mi	May 09, 2023 mi
Colorado Public Utilities Commission (CPUC) | Black Hills Energy - Colorado Electric | Rate Review Filed with the Regulatory Agency
Public Utilities, General Disclosures [Line Items]
Public Utilities - Length of Electric Distribution Lines to Receive Infrastructure Investments | mi				3,200
Public Utilities - Length of Electric Transmission Lines to Receive Infrastructure Investments | mi				600
Public Utilities, Requested Rate Increase (Decrease), Amount | $				$ 36.7
Public utilities, requested equity capital structure, percentage				53%
Public utilities, requested debt capital structure, percentage				47%
Public Utilities, Requested Return on Equity, Percentage				10.50%
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										10,000
Colorado Public Utilities Commission (CPUC) | Black Hills Energy - Colorado Gas | Settlement Reached with the Regulatory Agency
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Equity Capital Structure, Percentage						51%
Public Utilities, Approved Debt Capital Structure, Percentage						49%
Public Utilities, Approved Return on Equity, Percentage						9.30%
Public Utilities, Approved Rate Increase (Decrease), Amount | $						$ 20.2
Iowa Utilities Commission (IUC) | Black Hills Energy - Iowa 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							5,000
Iowa Utilities Commission (IUC) | Black Hills Energy - Iowa Gas | Received Final Approval from the IUC for a Settlement Agreement for a General Rate Increase
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount | $		$ 15
Weighted average cost of capital		7.20%
Arkansas Public Service Commission | Black Hills Energy - Arkansas 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								7,200
Arkansas Public Service Commission | Black Hills Energy - Arkansas Gas | Received Final Approval for a Settlement Agreement for a General Rate Increase
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Equity Capital Structure, Percentage			46%
Public Utilities, Approved Debt Capital Structure, Percentage			54%
Public Utilities, Approved Return on Equity, Percentage			9.90%
Public Utilities, Approved Shift Rate Rider Rate to Base Rate | $			$ 3.7
Public Utilities, Approved Rate Increase (Decrease), Amount | $			$ 25.4
Wyoming Public Service Commission | Black Hills Energy - Wyoming 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									6,400
Wyoming Public Service Commission | Black Hills Energy - Wyoming Gas | WPSC Approved a Settlement Agreement for a General Rate Increase
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Equity Capital Structure, Percentage					51%
Public Utilities, Approved Debt Capital Structure, Percentage					49%
Public Utilities, Approved Return on Equity, Percentage					9.85%
Public Utilities, Approved Rate Increase (Decrease), Amount | $					$ 13.9
Extension period as per settlement agreement					4 years
Subsequent Event | Kansas Corporation Commission (KCC) | Black Hills Energy, Kansas 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	4,765
Public Utilities, Requested Rate Increase (Decrease), Amount | $	$ 17.2
Public utilities, requested equity capital structure, percentage	50%
Public utilities, requested debt capital structure, percentage	50%
Public Utilities, Requested Return on Equity, Percentage	10.50%

Regulatory Matters_ Tax Cut and

Regulatory Matters: Tax Cut and Jobs Act (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Public Utilities, General Disclosures [Line Items]
U.S. federal corporate tax rate	21%	21%	21%

Regulatory Matters_ Electric Ut

Regulatory Matters: Electric Utilities Regulatory Activity (Details) - Black Hills Energy - Colorado Electric - Colorado Public Utilities Commission (CPUC) $ in Millions	Nov. 22, 2024 USD ($)	Jun. 14, 2024 USD ($) mi
Rate Review Filed with the Regulatory Agency
Public Utilities, General Disclosures [Line Items]
Public Utilities - Length of Electric Distribution Lines to Receive Infrastructure Investments | mi		3,200
Public Utilities - Length of Electric Transmission Lines to Receive Infrastructure Investments | mi		600
Public Utilities, Requested Rate Increase (Decrease), Amount | $		$ 36.7
Public utilities, requested equity capital structure, percentage		53%
Public utilities, requested debt capital structure, percentage		47%
Public Utilities, Requested Return on Equity, Percentage		10.50%
Rebuttal Testimony with Updated Request
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount | $	$ 25.1
Public utilities, requested equity capital structure, percentage	53%
Public utilities, requested debt capital structure, percentage	47%
Public Utilities, Requested Return on Equity, Percentage	9.80%

Commitment, Contingencies And_3

Commitment, Contingencies And Guarantees: Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2024 USD ($)
PPAs
Unrecorded Unconditional Purchase Obligation [Line Items]
2025	$ 0
2026	0
2027	0
2028	0
2029	0
Thereafter	0
Total future commitments	0
Transmission Services Agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2025	12.3
2026	0
2027	0
2028	0
2029	0
Thereafter	0
Total future commitments	12.3
Natural gas supply, transportation and storage agreements
Unrecorded Unconditional Purchase Obligation [Line Items]
2025	193.8
2026	171.2
2027	136.5
2028	86.6
2029	23
Thereafter	109
Total future commitments	$ 720.1

Commitment, Contingencies And_4

Commitment, Contingencies And Guarantees: Lease Agreements (Details) $ in Millions	Dec. 31, 2024 USD ($)
Lessor, Operating Lease, Payments, Fiscal Year Maturity [Abstract]
2025	$ 2.1
2026	3.1
2027	1.8
2028	1.8
2029	1.8
Thereafter	48.4
Total lease receivables	$ 59
Minimum
Lessor, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	1 year
Lessor - lease term	1 year
Maximum
Lessor, Lease, Description [Line Items]
Lessee, Operating Lease, Term of Contract	31 years
Lessor - lease term	31 years

Commitment, Contingencies And_5

Commitment, Contingencies And Guarantees: Manufactured Gas Plants (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Loss Contingencies [Line Items]
Regulatory assets	$ 427.7	$ 480.1
Accrued liabilities	302.2	293.3
Environmental
Loss Contingencies [Line Items]
Regulatory assets	10.7	$ 2.9
Manufactured Gas Plant
Loss Contingencies [Line Items]
Insurance Settlements Receivable, Noncurrent	1.5
Site remediation cost	7.4
Manufactured Gas Plant | Black Hills Energy - Iowa Gas
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	9.7
Manufactured Gas Plant | Environmental
Loss Contingencies [Line Items]
Regulatory assets	10.7
Manufactured Gas Plant | Gas Utilities | Black Hills Energy - Nebraska Gas
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies, Gross	$ 0.6

Commitments, Contingencies and

Commitments, Contingencies and Guarantees: GT Resources, LLC v Black Hills Corp (Details) - GT Resources, LLC - Pending Litigation a in Millions, $ in Millions	Apr. 13, 2022 USD ($) a
Loss Contingencies [Line Items]
Loss Contingency, Damages Awarded, Value | $	$ 41
Loss Contingency, Concession Award, Area | a	2.3

Commitment, Contingencies And_6

Commitment, Contingencies And Guarantees: Guarantees (Details) $ in Millions	Dec. 31, 2024 USD ($)
Guarantor Obligations [Line Items]
Total guarantees	$ 575.4
Surety Bond
Guarantor Obligations [Line Items]
Total guarantees	75.6
Guarantor Subsidiaries
Guarantor Obligations [Line Items]
Total guarantees	$ 499.8

Revenue_ Disaggregation of Reve

Revenue: Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenue from contracts with customers	$ 2,098	$ 2,301.7	$ 2,542.9
Revenue	2,127.7	2,331.3	2,551.8
Retail - Electric , Natural Gas and Coal
Revenue from contracts with customers	1,721.2	1,914.9	2,162.5
Transportation
Revenue from contracts with customers	177.8	176.3	172.9
Wholesale
Revenue from contracts with customers	26.8	34.2	44.8
Market - off-system sales
Revenue from contracts with customers	34.9	51.3	49.4
Transmission
Revenue from contracts with customers	52.9	47.8	41.3
Other revenues
Revenue from contracts with customers	84.4	77.2	72
Alternative revenue and other
Revenue	29.7	29.6	8.9
Services transferred at a point in time
Revenue from contracts with customers	34.7	31.5	30.4
Services transferred over time
Revenue from contracts with customers	2,063.3	2,270.2	2,512.5
Inter-segment Eliminations
Revenue from contracts with customers	(17.8)	(17.9)	(17)
Revenue	(17.8)	(17.9)	(17.5)
Inter-segment Eliminations | Retail - Electric , Natural Gas and Coal
Revenue from contracts with customers	0	0	0
Inter-segment Eliminations | Transportation
Revenue from contracts with customers	(0.4)	(0.5)	(0.4)
Inter-segment Eliminations | Wholesale
Revenue from contracts with customers	0	0	0
Inter-segment Eliminations | Market - off-system sales
Revenue from contracts with customers	0	0	0
Inter-segment Eliminations | Transmission
Revenue from contracts with customers	0	0	0
Inter-segment Eliminations | Other revenues
Revenue from contracts with customers	(17.4)	(17.4)	(16.6)
Inter-segment Eliminations | Alternative revenue and other
Revenue	0	0	(0.5)
Inter-segment Eliminations | Services transferred at a point in time
Revenue from contracts with customers	0	0	0
Inter-segment Eliminations | Services transferred over time
Revenue from contracts with customers	(17.8)	(17.9)	(17)
Operating Segments | Electric Utilities
Revenue from contracts with customers	871.1	854.2	894.6
Revenue	876.1	865	900.2
Operating Segments | Electric Utilities | Retail - Electric , Natural Gas and Coal
Revenue from contracts with customers	698.6	666.1	709.2
Operating Segments | Electric Utilities | Transportation
Revenue from contracts with customers	0	0	0
Operating Segments | Electric Utilities | Wholesale
Revenue from contracts with customers	26.8	34.2	44.8
Operating Segments | Electric Utilities | Market - off-system sales
Revenue from contracts with customers	34.8	50.9	48.6
Operating Segments | Electric Utilities | Transmission
Revenue from contracts with customers	52.2	47.1	40.5
Operating Segments | Electric Utilities | Other revenues
Revenue from contracts with customers	58.7	55.9	51.5
Operating Segments | Electric Utilities | Alternative revenue and other
Revenue	5	10.8	5.6
Operating Segments | Electric Utilities | Services transferred at a point in time
Revenue from contracts with customers	34.7	31.5	30.4
Operating Segments | Electric Utilities | Services transferred over time
Revenue from contracts with customers	836.4	822.7	864.2
Operating Segments | Gas Utilities
Revenue from contracts with customers	1,244.7	1,465.4	1,665.3
Revenue	1,269.4	1,484.2	1,669.1
Operating Segments | Gas Utilities | Retail - Electric , Natural Gas and Coal
Revenue from contracts with customers	1,022.6	1,248.8	1,453.3
Operating Segments | Gas Utilities | Transportation
Revenue from contracts with customers	178.2	176.8	173.3
Operating Segments | Gas Utilities | Wholesale
Revenue from contracts with customers	0	0	0
Operating Segments | Gas Utilities | Market - off-system sales
Revenue from contracts with customers	0.1	0.4	0.8
Operating Segments | Gas Utilities | Transmission
Revenue from contracts with customers	0.7	0.7	0.8
Operating Segments | Gas Utilities | Other revenues
Revenue from contracts with customers	43.1	38.7	37.1
Operating Segments | Gas Utilities | Alternative revenue and other
Revenue	24.7	18.8	3.8
Operating Segments | Gas Utilities | Services transferred at a point in time
Revenue from contracts with customers	0	0	0
Operating Segments | Gas Utilities | Services transferred over time
Revenue from contracts with customers	$ 1,244.7	$ 1,465.4	$ 1,665.3

Property, Plant and Equipment_2

Property, Plant and Equipment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Total gross property, plant and equipment	$ 9,566.5	$ 8,917.2
Less accumulated depreciation	(1,936.6)	(1,797.9)
Property, plant and equipment	7,629.9	7,119.3
Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	0.4	5.7
Construction work-in-progress, gross	10.3	13.6
Total gross property, plant and equipment	10.7	19.3
Less accumulated depreciation	0	(1.9)
Property, plant and equipment	$ 10.7	$ 17.4
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		4 years
Maximum | Corporate, Non-Segment
Property, Plant and Equipment [Line Items]
Weighted average useful life		21 years
Production, Gas | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	43 years	45 years
Production, Gas | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		24 years
Production, Gas | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		45 years
Gas transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	58 years	58 years
Gas transmission | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		32 years
Gas transmission | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		73 years
Gas distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	57 years	57 years
Gas distribution | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		48 years
Gas distribution | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		61 years
Gas, Storage | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	42 years	42 years
Gas, Storage | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		36 years
Gas, Storage | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		48 years
General | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	22 years	22 years
General | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		20 years
General | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		24 years
Electric Utilities
Property, Plant and Equipment [Line Items]
Total plant in service before construction work in progress	$ 4,576.2	$ 4,393.7
Construction work-in-progress	259.4	123.1
Property, Plant and Equipment	4,835.6	4,516.8
Less accumulated depreciation	(1,280.3)	(1,207.7)
Property, plant and equipment	$ 3,555.3	3,309.1
Electric Utilities | Wyodak Plant
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization, remaining amortization period	6 years
Electric Utilities | Production, Electric
Property, Plant and Equipment [Line Items]
Production, processing and storage	$ 1,508.5	$ 1,492.8
Electric Utilities | Production, Electric | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	39 years	40 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		44 years
Electric Utilities | Electric transmission
Property, Plant and Equipment [Line Items]
Transmission	$ 793.7	$ 737.4
Electric Utilities | Electric transmission | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	48 years	48 years
Electric Utilities | Electric transmission | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		42 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	$ 1,238.5	$ 1,146.9
Electric Utilities | Electric distribution | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	47 years	47 years
Electric Utilities | Electric distribution | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		45 years
Electric Utilities | Electric distribution | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		50 years
Electric Utilities | Integrated Generation
Property, Plant and Equipment [Line Items]
Plant acquisition adjustment	$ 724	$ 720
Electric Utilities | Integrated Generation | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	30 years	30 years
Electric Utilities | Integrated Generation | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		19 years
Electric Utilities | Integrated Generation | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		38 years
Electric Utilities | Plant acquisition adjustment
Property, Plant and Equipment [Line Items]
Plant acquisition adjustment	$ 4.9	$ 4.9
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	$ 306.6	$ 291.7
Electric Utilities | General | Weighted Average
Property, Plant and Equipment [Line Items]
Weighted average useful life	26 years	27 years
Electric Utilities | General | Minimum
Property, Plant and Equipment [Line Items]
Weighted average useful life		23 years
Electric Utilities | General | Maximum
Property, Plant and Equipment [Line Items]
Weighted average useful life		27 years
Gas Utilities
Property, Plant and Equipment [Line Items]
Total plant in service before construction work in progress	$ 4,676.7	$ 4,341.9
Construction work-in-progress, gross	43.5	39.2
Total gross property, plant and equipment	4,720.2	4,381.1
Less accumulated depreciation	(656.3)	(588.3)
Property, plant and equipment	4,063.9	3,792.8
Gas Utilities | Production, Gas
Property, Plant and Equipment [Line Items]
Production, processing and storage	21.6	21
Gas Utilities | Gas transmission
Property, Plant and Equipment [Line Items]
Transmission	817.5	759.5
Gas Utilities | Gas distribution
Property, Plant and Equipment [Line Items]
Distribution	3,107.3	2,860
Gas Utilities | Cushion gas - not depreciable
Property, Plant and Equipment [Line Items]
Production, processing and storage	52.1	58.2
Gas Utilities | Gas, Storage
Property, Plant and Equipment [Line Items]
Production, processing and storage	78.8	71.4
Gas Utilities | General
Property, Plant and Equipment [Line Items]
General	$ 599.4	$ 571.8

Jointly Owned Facilities (Detai

Jointly Owned Facilities (Details) $ in Millions	Dec. 31, 2024 USD ($)
Wyodak Plant
Jointly Owned Utility Plant Interests [Line Items]
Ownership Interest	20%
Plant in Service	$ 123
Construction Work in Progress	0
Less Accumulated Depreciation	(76.8)
Plant Net of Accumulated Depreciation	$ 46.2
Transmission Tie
Jointly Owned Utility Plant Interests [Line Items]
Ownership Interest	35%
Plant in Service	$ 24.5
Construction Work in Progress	0.3
Less Accumulated Depreciation	(8.3)
Plant Net of Accumulated Depreciation	$ 16.5
Wygen III Generating Facility
Jointly Owned Utility Plant Interests [Line Items]
Ownership Interest	52%
Plant in Service	$ 144.8
Construction Work in Progress	0.3
Less Accumulated Depreciation	(33)
Plant Net of Accumulated Depreciation	$ 112.1
Wygen I Generating Facility
Jointly Owned Utility Plant Interests [Line Items]
Ownership Interest	76.50%
Plant in Service	$ 116.3
Construction Work in Progress	1.9
Less Accumulated Depreciation	(61.6)
Plant Net of Accumulated Depreciation	$ 56.6

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance		$ 96.2	$ 88.9
Liabilities Incurred		0.2	6.7
Liabilities Settled		0	0
Accretion		4.1	3.5
Revisions to Prior Estimates		0.2	(2.9)
Ending Balance		100.7	96.2
Electric Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance		28.7	27.6
Liabilities Incurred		0	0
Liabilities Settled		0	0
Accretion		1.1	1.2
Revisions to Prior Estimates		0.2	(0.1)
Ending Balance		30	28.7
Gas Utilities
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	[1]	67.5	61.3
Liabilities Incurred		0.2	6.7	[1]
Liabilities Settled		0	0	[1]
Accretion		3	2.3	[1]
Revisions to Prior Estimates		0	(2.8)	[1]
Ending Balance		$ 70.7	$ 67.5	[1]
[1] The Revisions to Prior Estimates were primarily driven by changes in estimates associated with natural gas wells and compressor stations.

Financing - Schedule of Short-t

Financing - Schedule of Short-term Debt and Narrative (Details) $ in Millions		12 Months Ended
	May 31, 2024 USD ($) CreditExtension	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Short-Term Debt [Line Items]
Amount outstanding		$ 133.8	$ 0
Commercial Paper, Maximum Borrowing Capacity		$ 750
Commercial Paper
Short-Term Debt [Line Items]
Debt Instrument, Term		397 days
Revolving Credit Facility
Short-Term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity	$ 750
Number Of One-Year Extension Options | CreditExtension	2
Debt Instrument, Term	1 year
Maximum amount outstanding (based on daily outstanding balances)	$ 1,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.175%
Debt Issuance Cost, Gross, Noncurrent		$ 11
Revolving Credit Facility | Base Rate
Short-Term Debt [Line Items]
Weighted average interest rates		0.125%
Revolving Credit Facility | Eurodollar
Short-Term Debt [Line Items]
Weighted average interest rates		1.125%
Revolving Credit Facility | Letter of Credit
Short-Term Debt [Line Items]
Weighted average interest rates		1.125%
Revolving Credit Facility | Commercial Paper
Short-Term Debt [Line Items]
Amount outstanding		$ 133.8	0
Letters of credit		3.5	3.7
Available capacity		$ 612.7	746.3
Weighted average interest rates		4.74%
Maximum amount outstanding (based on daily outstanding balances)		$ 140.6	548.7
Average amount outstanding (based on daily outstanding balances)		$ 17.1	$ 81.7
Weighted average interest rates		4.86%	4.91%

Financing_ Long-Term Debt (Deta

Financing: Long-Term Debt (Details) - USD ($)	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Total long-term debt	$ 4,276,300,000	$ 4,426,000,000
Less current maturities	0	(600,000,000)
Less unamortized deferred financing costs	(26,100,000)	(24,800,000)
Long-term debt, net of current maturities	4,250,200,000	3,801,200,000
Revolving Credit Facility
Debt Instrument [Line Items]
Less unamortized deferred financing costs	(2,400,000)	(1,100,000)
Black Hills Corporation | Corporate, Non-Segment
Debt Instrument [Line Items]
Long-term debt	3,750,000,000	3,900,000,000
Less unamortized debt discount	(8,600,000)	(8,900,000)
Total long-term debt	3,741,400,000	3,891,100,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Long-term debt	$ 0	600,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2026
Debt Instrument [Line Items]
Stated interest rate (percent)	3.95%
Long-term debt	$ 300,000,000	300,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Stated interest rate (percent)	3.15%
Long-term debt	$ 400,000,000	400,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2028
Debt Instrument [Line Items]
Stated interest rate (percent)	5.95%
Long-term debt	$ 350,000,000	350,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2029
Debt Instrument [Line Items]
Stated interest rate (percent)	3.05%
Long-term debt	$ 400,000,000	400,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2030
Debt Instrument [Line Items]
Stated interest rate (percent)	2.50%
Long-term debt	$ 400,000,000	400,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2033
Debt Instrument [Line Items]
Stated interest rate (percent)	4.35%
Long-term debt	$ 400,000,000	400,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2034
Debt Instrument [Line Items]
Stated interest rate (percent)	6.15%
Long-term debt	$ 450,000,000	450,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2035
Debt Instrument [Line Items]
Stated interest rate (percent)	6%
Long-term debt	$ 450,000,000	0
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2046
Debt Instrument [Line Items]
Stated interest rate (percent)	4.20%
Long-term debt	$ 300,000,000	300,000,000
Black Hills Corporation | Corporate, Non-Segment | Senior Unsecured Notes Due 2049
Debt Instrument [Line Items]
Stated interest rate (percent)	3.88%
Long-term debt	$ 300,000,000	300,000,000
Black Hills Energy - South Dakota Electric | Electric Utilities
Debt Instrument [Line Items]
Long-term debt	340,000,000	340,000,000
Less unamortized debt discount	(100,000)	(100,000)
Total long-term debt	$ 339,900,000	339,900,000
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	$ 75,000,000	75,000,000
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	$ 180,000,000	180,000,000
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	$ 85,000,000	85,000,000
Wyoming Electric | Electric Utilities
Debt Instrument [Line Items]
Long-term debt	195,000,000	195,000,000
Less unamortized debt discount	0	0
Total long-term debt	195,000,000	195,000,000
Wyoming Electric | Electric Utilities | Senior Unsecured Notes Due 2027
Debt Instrument [Line Items]
Long-term debt	$ 10,000,000
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2044
Debt Instrument [Line Items]
Stated interest rate (percent)	4.53%
Long-term debt	$ 75,000,000	75,000,000
Wyoming Electric | Electric Utilities | Industrial Development Revenue Bonds Due 2027
Debt Instrument [Line Items]
Variable interest rate (percent)	3.68%
Long-term debt	$ 10,000,000	10,000,000
Wyoming Electric | Electric Utilities | First Mortgage Bonds Due 2037
Debt Instrument [Line Items]
Stated interest rate (percent)	6.67%
Long-term debt	$ 110,000,000	$ 110,000,000

Financing_ Long-Term Debt_ Aggr

Financing: Long-Term Debt: Aggregate Maturities of Long Term Debt and Associated Interest Payments (Details) $ in Millions	Dec. 31, 2024 USD ($)
Principal Payments on Long-term Debt Including Current Maturities
Debt Instrument [Line Items]
2025	$ 0
2026	300
2027	410
2028	350
2029	400
Thereafter	2,825
Total	4,285
Interest Payments on Long-term Debt
Debt Instrument [Line Items]
2025	199.5
2026	189.2
2027	176.6
2028	159.9
2029	149.4
Thereafter	1,078.3
Total	$ 1,952.9

Financing_ Long-term Debt (Addi

Financing: Long-term Debt (Additional Information) (Details) - USD ($) $ in Millions			12 Months Ended
	Aug. 23, 2024	May 16, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Less unamortized deferred financing costs			$ 26.1	$ 24.8
Repayment of long term debt			$ 600	$ 525	$ 0
Segment Reporting, Reconciling Item, Corporate Nonsegment [Member] | Senior Unsecured Notes Due 2035 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Debt		$ 450
Stated interest rate (percent)		6%
Less unamortized deferred financing costs		$ 5.2
Segment Reporting, Reconciling Item, Corporate Nonsegment [Member] | Senior Unsecured Notes Due 2024 [Member]
Debt Instrument [Line Items]
Stated interest rate (percent)	1.04%
Repayment of long term debt	$ 600

Financing_ Debt Covenants (Addi

Financing: Debt Covenants (Additional Information) (Details)	Dec. 31, 2024
Line of Credit Facility [Line Items]
Consolidated indebtedness to capitalization ratio	0.56
Maximum
Line of Credit Facility [Line Items]
Consolidated indebtedness to capitalization ratio	0.65
Wyoming Electric
Line of Credit Facility [Line Items]
Consolidated indebtedness to capitalization ratio	0.51
Wyoming Electric | Maximum
Line of Credit Facility [Line Items]
Consolidated indebtedness to capitalization ratio	0.6

Financing_ Dividend Restriction

Financing: Dividend Restrictions (Details) $ in Millions	Dec. 31, 2024 USD ($)
Utilities Group
Debt Instrument [Line Items]
Restricted Net Assets for Subsidiaries	$ 152.2

Financing_ Equity (Details)

Financing: Equity (Details) - shares	Dec. 31, 2024	Dec. 31, 2023
Stockholders' Equity Note [Abstract]
Common stock, shares authorized	100,000,000	100,000,000
Preferred Stock, Shares Authorized	25,000,000
Common stock, shares outstanding	71,700,000
Preferred Stock, Shares Outstanding	0

Financing_ At-the-Market Equity

Financing: At-the-Market Equity Offering Program (Details) $ in Millions	Jun. 16, 2023 USD ($)
At The Market Equity Offering Program Authorized Aggregate Value	$ 400

Financing_ Summary of ATM Activ

Financing: Summary of ATM Activity (Details) - Common Stock - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Proceeds, (net of issuance costs)	$ 181.6	$ 118.7	$ 90.3
Number of shares issued	3.3	2	1.3
Average price per share	$ 55.63	$ 59.04	$ 69.74
Payments of Stock Issuance Costs	$ (1.8)	$ (1.2)	$ (0.9)
August 4, 2020 ATM Program
Proceeds, (net of issuance costs)	$ 0	$ 48.5	$ 90.3
Number of shares issued	0	0.8	1.3
Payments of Stock Issuance Costs	$ 0	$ (0.5)	$ (0.9)
June 16, 2023 ATM Program
Proceeds, (net of issuance costs)	$ 181.6	$ 70.2	$ 0
Number of shares issued	3.3	1.2	0
Payments of Stock Issuance Costs	$ (1.8)	$ (0.7)	$ 0

Risk Management and Derivativ_3

Risk Management and Derivatives: Utilities (Details) $ in Millions		Dec. 31, 2024 USD ($) MMBTU	Dec. 31, 2023 MMBTU
Derivative [Line Items]
Credit Risk Derivative Liabilities, at Fair Value | $		$ 0.3
Natural Gas, Distribution | Cash Flow Hedging
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		1,427,000
Natural Gas, Distribution | Natural gas futures purchased
Derivative [Line Items]
Derivative, Remaining Maturity	[1]	3 months	3 months
Natural Gas, Distribution | Natural gas futures purchased | Long
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		660,000	650,000
Natural Gas, Distribution | Natural gas options purchased, net
Derivative [Line Items]
Derivative, Remaining Maturity	[1]	3 months	3 months
Natural Gas, Distribution | Natural gas options purchased, net | Long
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		2,780,000	2,850,000
Natural Gas, Distribution | Natural gas basis swaps purchased
Derivative [Line Items]
Derivative, Remaining Maturity	[1]	3 months	3 months
Natural Gas, Distribution | Natural gas basis swaps purchased | Long
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount		1,080,000	1,050,000
Natural Gas, Distribution | Natural gas over-the-counter swaps, net
Derivative [Line Items]
Derivative, Remaining Maturity	[1],[2]	20 months	21 months
Natural Gas, Distribution | Natural gas over-the-counter swaps, net | Long
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	[2]	3,480,000	3,890,000
Natural Gas, Distribution | Natural gas physical commitments, net
Derivative [Line Items]
Derivative, Remaining Maturity	[1],[3]	10 months	10 months
Natural Gas, Distribution | Natural gas physical commitments, net | Long
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	[3]	20,276,230	12,582,415
[1] Term reflects the maximum forward period hedged. As of December 31, 2024 , 1,427,000 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP.

Risk Management and Derivativ_4

Risk Management and Derivatives: Derivatives by Balance Sheet Classification (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ (0.7)	$ (2.9)
Commodity Contract | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	(3.5)	(3.9)
Derivative liabilities, current | Commodity Contract | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(0.7)	(2.7)
Derivative liabilities, current | Commodity Contract | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(3.5)	(3.8)
Other deferred credits and other liabilities | Commodity Contract | Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(0.2)
Other deferred credits and other liabilities | Commodity Contract | Not Designated as Hedging Instrument
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ 0	$ (0.1)

Risk Management and Derivativ_5

Risk Management and Derivatives: Cash Flow Hedges (Details) - Cash Flow Hedging - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Interest rate swaps
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 3.3
Designated as Hedging Instrument
Derivative [Line Items]
Unrealized Gain (Loss) on Cash Flow Hedging Instruments	5.8	$ 1.3	$ (0.7)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	$ (6.4)	$ (5.9)	$ (0.1)
Derivative Instrument, Gain (Loss) Reclassified from AOCI into Income, Effective Portion, Statement of Income or Comprehensive Income [Extensible Enumeration]	Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest	Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest
Designated as Hedging Instrument | Interest rate swaps
Derivative [Line Items]
Unrealized Gain (Loss) on Cash Flow Hedging Instruments	$ 2.9	$ 2.9	$ 2.8
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion	$ (2.9)	$ (2.9)	$ (2.8)
Derivative Instrument, Loss Reclassified from AOCI into Income, Effective Portion, Statement of Income or Comprehensive Income [Extensible Enumeration]	Interest Costs Incurred	Interest Costs Incurred	Interest Costs Incurred
Designated as Hedging Instrument | Commodity Contract
Derivative [Line Items]
Unrealized Gain (Loss) on Cash Flow Hedging Instruments	$ 2.9	$ (1.6)	$ (3.5)
Derivative Instruments, Loss Reclassified from Accumulated OCI into Income, Effective Portion	$ (3.5)	$ (3)
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion			$ 2.7
Derivative Instrument, Gain Reclassified from AOCI into Income, Effective Portion, Statement of Income or Comprehensive Income [Extensible Enumeration]	Fuel, Purchased Power and Cost of Gas Sold	Fuel, Purchased Power and Cost of Gas Sold	Fuel, Purchased Power and Cost of Gas Sold

Risk Management and Derivativ_6

Risk Management and Derivatives: Derivatives Not Designated as Hedge Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Regulatory assets	$ 427.7	$ 480.1
Gas price derivatives
Derivative [Line Items]
Regulatory assets	2.9	5.1
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 0.7	$ (4.2)	$ (0.8)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Fuel, Purchased Power and Cost of Gas Sold	Fuel, Purchased Power and Cost of Gas Sold	Fuel, Purchased Power and Cost of Gas Sold
Not Designated as Hedging Instrument | Natural Gas
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 0.7	$ (4.2)	$ (0.8)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Fuel, Purchased Power and Cost of Gas Sold	Fuel, Purchased Power and Cost of Gas Sold	Fuel, Purchased Power and Cost of Gas Sold

Fair Value Measurements_ Schedu

Fair Value Measurements: Schedule of Fair Values (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Derivative Liability, Current	Derivative Liability, Current
Contract Subject to Master Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 2.2	$ 1.9
Derivative Liability, Fair Value, Gross Liability	0.6	3.3
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	(2.2)	(1.9)
Derivative Liability, Fair Value, Gross Asset and Right to Reclaim Cash, Offset	(0.6)	(3.3)
Fair Value, Measurements, Recurring | Fair Value
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	4.2	6.8
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	0	0
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	2.2	1.9
Derivative, Liabilities, Fair Value Disclosure	4.8	10.1
Fair Value, Measurements, Recurring | Fair Value, Inputs, Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets, Fair Value Disclosure	0	0
Derivative, Liabilities, Fair Value Disclosure	$ 0	$ 0

Fair Value Measurements_ Other

Fair Value Measurements: Other Fair Value Measurements (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Carrying Amount
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, including current maturities	$ 4,250.2	$ 4,401.2
Fair Value
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt, including current maturities	$ 4,059.1	$ 4,215.6

Other Comprehensive Income_ Rec

Other Comprehensive Income: Reclassification Out of Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense	$ 195.2	$ 180	$ 162.6
Fuel, purchased power and cost of natural gas sold	730.3	982.9	1,230.6
Operations and maintenance	557	552	548.4
Income Tax Expense (Benefit)	(36.3)	(25.6)	(25.2)
Net income	283.7	276	$ 270.8
Reclassification out of Accumulated Other Comprehensive Income
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Operations and maintenance	0	0
Net income	(5.1)	(4.7)
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	(6.4)	(5.9)
Income Tax Expense (Benefit)	1.4	1.4
Net income	(5)	(4.5)
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	(2.9)	(2.9)
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	(3.5)	(3)
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	(0.2)	(0.2)
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	(0.2)	(0.2)
Income Tax Expense (Benefit)	0.1	0
Net income	$ (0.1)	$ (0.2)

Other Comprehensive Income_ Acc

Other Comprehensive Income: Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	$ (14.8)	$ (15.6)
Other comprehensive income (loss), before reclassifications	0.3	(3.9)
Amounts reclassified from AOCI	5.1	4.7
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(9.4)	(14.8)
Accumulated Defined Benefit Plans Adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period Start	(6.2)	(6.1)
Other comprehensive income (loss), before reclassifications	0.8	(0.3)
Amounts reclassified from AOCI	0.1	0.2
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(5.3)	(6.2)
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	(6.1)	(8.3)
Other comprehensive income (loss), before reclassifications	0	0
Amounts reclassified from AOCI	2.3	2.2
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	(3.8)	(6.1)
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	(2.5)	(1.2)
Other comprehensive income (loss), before reclassifications	(0.5)	(3.6)
Amounts reclassified from AOCI	2.7	2.3
Accumulated Other Comprehensive Income (Loss), Net of Tax, Period End	$ (0.3)	$ (2.5)

Variable Interest Entity_ (Deta

Variable Interest Entity: (Details) $ in Millions		12 Months Ended
	Apr. 14, 2016	Dec. 31, 2024 USD ($) MW	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.90%
Net income attributable to non-controlling interest		$ (10.6)	$ (13.8)	$ (12.4)
Number of Days Following the End of the Quarter When Distributions of Net Income Attributable to this Non-controlling Interest are Due		30 days
Current assets		$ 742.3	826.6
Property, plant and equipment		7,629.9	7,119.3
Current liabilities		763.4	1,185.1
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Current assets		11.7	15.1
Property, plant and equipment		160.4	166.8
Current liabilities		8.3	4.8
Power Generation
Variable Interest Entity [Line Items]
Net income attributable to non-controlling interest		$ (10.6)	$ (13.8)	$ (12.4)
Pueblo Airport Generation | Subsidiary of Common Parent
Variable Interest Entity [Line Items]
Electric Generation Capacity, Megawatts | MW		200

Employee Benefit Plans_ Defined

Employee Benefit Plans: Defined Contribution Plans (Details)	12 Months Ended
	Dec. 31, 2024
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	50%
Defined Contribution Plan, Employers Matching Contribution, Annual Vesting Percentage	20%
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%

Employee Benefit Plans_ Defin_2

Employee Benefit Plans: Defined Benefit Pension Plan (Details) - PensionPlan	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Number of Defined Pension Plans		1
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		100%	100%
Return Seeking Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		30%	24%
Liability-hedging Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		70%	76%
Investment in privately held oil and gas company | Return Seeking Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		19%	14%
Real Estate | Return Seeking Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		5%	5%
Fixed Income | Return Seeking Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		3%	2%
Fixed Income | Liability-hedging Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		68%	74%
Hedge Funds | Return Seeking Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		3%	3%
Cash | Liability-hedging Assets
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		2%	2%
Minimum | Return Seeking Assets | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		20%
Minimum | Return Seeking Assets | Pension Plan | Scenario Forecast
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	26%
Minimum | Hedge Funds | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		72%
Minimum | Hedge Funds | Pension Plan | Scenario Forecast
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	66%
Maximum | Return Seeking Assets | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		28%
Maximum | Return Seeking Assets | Pension Plan | Scenario Forecast
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	34%
Maximum | Hedge Funds | Pension Plan
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage		80%
Maximum | Hedge Funds | Pension Plan | Scenario Forecast
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	74%

Employee Benefit Plans_ Plan Co

Employee Benefit Plans: Plan Contributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	$ 1.8
Payment for Pension Benefits	2.3	$ 0
Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	4.7
Payment for Pension and Other Postretirement Benefits	5.7	5.4
Payment for Pension Benefits	4.2	4.3
Supplemental Plans
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year	2.8
Payment for Pension Benefits	4.1	3.5
Defined Contribution Plan, Company Retirement
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	11.3	12.7
Defined Contribution Plan, 401K
Defined Benefit Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 17.7	$ 17.1

Employee Benefit Plans_ Fair Va

Employee Benefit Plans: Fair Value Measurements (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 270.2	$ 308.6	$ 323.1
Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	270.2	308.4
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	247.7	283.9
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	22.5	24.5
Fair Value, Measurements, Recurring | Healthcare Plan
Defined Benefit Plan, Plan Assets, Amount	7.5	8
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	7.5	8
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
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 | Healthcare Plan
Defined Benefit Plan, Plan Assets, Amount	7.5	8
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	247.7	283.9
Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Healthcare Plan
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 | Healthcare Plan
Defined Benefit Plan, Plan Assets, Amount	$ 0	0
Common Collective Trust Funds | Minimum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	15 days
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 5.4	6.7
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	5.4	6.7
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Common Collective Trust, Cash And Cash Equivalents | Fair Value, Measurements, Recurring | Healthcare Plan
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	5.4	6.7
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 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	51.5	42.7
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	51.5	42.7
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Common Collective Trust - Equity | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust - Equity | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	51.5	42.7
Common Collective Trust - Equity | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust - Fixed Income | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	190.8	234.5
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	190.8	234.5
Defined Benefit Plan, Alternative Investments, Fair Value Of Plan Assets	0	0
Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	190.8	234.5
Common Collective Trust - Fixed Income | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 0	0
Common Collective Trust - Real Estate | Minimum
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Investment Redemption, Notice Period	105 days
Common Collective Trust - Real Estate | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 14.9	16.4
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	14.9	16.4
Common Collective Trust - Real Estate | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust - Real Estate | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Common Collective Trust - Real Estate | 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	10%
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
Hedge Funds | Fair Value, Measurements, Recurring | Pension Plan
Defined Benefit Plan, Plan Assets, Amount	$ 7.6	8.1
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	7.6	8.1
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 | Healthcare Plan
Defined Benefit Plan, Plan Assets, Amount	7.5	8
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value investments	7.5	8
Cash | Fair Value, Inputs, Level 1 | Fair Value, Measurements, Recurring | Healthcare Plan
Defined Benefit Plan, Plan Assets, Amount	7.5	8
Cash | Fair Value, Inputs, Level 2 | Fair Value, Measurements, Recurring | Healthcare Plan
Defined Benefit Plan, Plan Assets, Amount	0	0
Cash | Fair Value, Inputs, Level 3 | Fair Value, Measurements, Recurring | Healthcare Plan
Defined Benefit Plan, Plan Assets, Amount	$ 0	$ 0

Employee Benefit Plans_ Compone

Employee Benefit Plans: Components of Net Periodic Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	$ 2.3	$ 2.5	$ 3.9
Interest cost	16.4	17.5	10.8
Expected return on assets	(18)	(18.7)	(18.5)
Net amortization of prior service cost	(0.1)	(0.1)	(0.1)
Recognized net actuarial loss (gain)	2	2	6.1
Net periodic benefit expense	2.6	3.2	2.2
Supplemental Plans
Defined Benefit Plan Disclosure [Line Items]
Service Cost	3.3	3.1	(0.8)
Interest cost	1.4	1.5	0.8
Expected return on assets	0	0	0
Net amortization of prior service cost	0	0	0
Recognized net actuarial loss (gain)	0	0	0.3
Net periodic benefit expense	4.7	4.6	0.3
Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Service Cost	1.6	1.5	1.9
Interest cost	2.4	2.4	1.3
Expected return on assets	(0.3)	(0.2)	(0.1)
Net amortization of prior service cost	0.2	0	(0.3)
Recognized net actuarial loss (gain)	0	0	0.1
Net periodic benefit expense	$ 3.9	$ 3.7	$ 2.9

Employee Benefit Plans_ Employe

Employee Benefit Plans: Employee Benefit Plan Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Amounts recognized on our Consolidated Balance Sheets as of December 31:
Regulatory assets	$ 427.7	$ 480.1
Non-current liabilities	122.9	123.9
Regulatory liabilities	568.7	566.6
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation at end of year	307.1	341.8
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	348.1	358.4
Service Cost	2.3	2.5	$ 3.9
Interest cost	16.4	17.5	10.8
Actuarial (gain) loss	(16)	11.6
Benefits paid	(39.2)	(41.9)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	311.6	348.1	358.4
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	308.6	323.1
Investment income (loss)	(1.6)	27.4
Employer contributions	2.3	0
Retiree contributions	0	0
Benefits paid	(39.1)	(41.9)
Fair value of plan assets at end of year	270.2	308.6	323.1
Funded status - deficiency	41.4	39.5
Amounts recognized on our Consolidated Balance Sheets as of December 31:
Regulatory assets	81.6	79.9
Current liabilities	0	0
Non-current assets	0	0
Non-current liabilities	41.4	39.4
Regulatory liabilities	3.1	2.9
Amounts recognized in AOCI, net of tax as of December 31:
Net (gain) loss	5.2	5
Prior service cost (gain)	0	0
Total amounts included in AOCI, net of tax not yet recognized as components of net periodic expense	5.2	5
Supplemental Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation at end of year	46.1	46.7
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	46.7	45.2
Service Cost	3.3	3.1	(0.8)
Interest cost	1.4	1.5	0.8
Actuarial (gain) loss	(1.2)	0.3
Benefits paid	(4.1)	(3.4)
Plan participants’ contributions	0	0
Projected benefit obligation at end of year	46.1	46.7	45.2
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	0	0
Investment income (loss)	0	0
Employer contributions	4.1	3.5
Retiree contributions	0	0
Benefits paid	(4.1)	(3.5)
Fair value of plan assets at end of year	0	0	0
Funded status - deficiency	46.1	46.7
Amounts recognized on our Consolidated Balance Sheets as of December 31:
Regulatory assets	0	0
Current liabilities	2.8	2.4
Non-current assets	0	0
Non-current liabilities	43.3	44.3
Regulatory liabilities	0	0
Amounts recognized in AOCI, net of tax as of December 31:
Net (gain) loss	0.8	1.8
Prior service cost (gain)	0	0
Total amounts included in AOCI, net of tax not yet recognized as components of net periodic expense	0.8	1.8
Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation at end of year	48.5	51.1
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Projected benefit obligation at beginning of year	51.1	49.7
Service Cost	1.6	1.5	1.9
Interest cost	2.4	2.4	1.3
Actuarial (gain) loss	(1.7)	1.7
Benefits paid	(5.7)	(5.3)
Plan participants’ contributions	0.8	1.1
Projected benefit obligation at end of year	48.5	51.1	49.7
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	8	7.8
Investment income (loss)	0.1	0.2
Employer contributions	4.2	4.3
Retiree contributions	0.9	1.1
Benefits paid	(5.7)	(5.4)
Fair value of plan assets at end of year	7.5	8	$ 7.8
Funded status - deficiency	41	43.1
Amounts recognized on our Consolidated Balance Sheets as of December 31:
Regulatory assets	4.9	4.8
Current liabilities	4.3	4.2
Non-current assets	0	1.3
Non-current liabilities	36.7	40.2
Regulatory liabilities	7.3	5.5
Amounts recognized in AOCI, net of tax as of December 31:
Net (gain) loss	(0.7)	(0.7)
Prior service cost (gain)	0	0.1
Total amounts included in AOCI, net of tax not yet recognized as components of net periodic expense	$ (0.7)	$ (0.6)

Employee Benefit Plans_ Assumpt

Employee Benefit Plans: Assumptions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Minimum
Defined Benefit Plan Disclosure [Line Items]
Trend Year	2035	2034
Maximum
Defined Benefit Plan Disclosure [Line Items]
Trend Year	2033	2034
Black Hills Corporation | Minimum
Defined Benefit Plan Disclosure [Line Items]
Post-65 for next year - All Plans	7.50%	6.69%
Post-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Black Hills Corporation | Maximum
Defined Benefit Plan Disclosure [Line Items]
Post-65 for next year - All Plans	6.50%	5.81%
Post-65 Ultimate trend rate - Black Hills Corp	4.50%	4.50%
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost effective discount rate	5.63%	4.99%	5.17%
Rate of increase in compensation levels	3.04%	3.04%	3.06%
Interest cost effective discount rate	4.99%	5.17%	2.88%
Expected long-term rate of return on assets	6%	6%	4.25%
Rate of increase in compensation levels	3.04%	3.06%	3.08%
Defined Benefit Plan Assumptions Used In Calculating Net Periodic Benefit Cost Expected Rate of Return On Assets For Next Fiscal Year	6.50%
2025	$ 24.4
2026	24.8
2027	25.1
2028	25.1
2029	25.6
2030 - 2034	$ 123.5
Pension Plan | Black Hills Corporation Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Post-65 for next year - All Plans	5.63%
Supplemental Plans
Defined Benefit Plan Disclosure [Line Items]
Interest cost effective discount rate	5.56%	4.93%	5.13%
Rate of increase in compensation levels	0%	0%	0%
Interest cost effective discount rate	4.93%	5.13%	2.77%
Rate of increase in compensation levels	0%	0%	0%
2025	$ 2.8
2026	2.8
2027	2.7
2028	2.7
2029	2.5
2030 - 2034	$ 11.3
Healthcare Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost effective discount rate	5.60%	4.97%	5.14%
Interest cost effective discount rate	4.97%	5.14%	2.79%
Expected long-term rate of return on assets	3.50%	3.10%	1.70%
2025	$ 5.3
2026	5.1
2027	5
2028	4.8
2029	4.7
2030 - 2034	$ 21.4

Share-based Compensation Plans_

Share-based Compensation Plans: Compensation Related Costs, Share Based Payments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Shares available for grant	1,988,252
Unrecognized compensation expense	$ 13
Weighted-average recognition period	2 years
Stock compensation	$ 10.6	$ 7	$ 8.6

Share-based Compensation Plan_2

Share-based Compensation Plans: Restricted Stock (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense	$ 13
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	231,942	164,687
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 56.68	$ 64.81
Performance Shares, Granted in Period	180,676
Granted (usd per share)	$ 53.58	$ 63.33	$ 69.03
Shares Vested	(83,737)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 65.11
Shares Forfeited	(29,684)
Forfeited (usd per share)	$ 59.13
Restricted Stock and RSUs, total fair value of shares vested	$ 4.5	$ 5.9	$ 6.4
Unrecognized compensation expense	$ 8.6
Weighted-average recognition period	2 years 1 month 6 days

Share-based Compensation Plan_3

Share-based Compensation Plans: Performance Plan Share Units (Details)	12 Months Ended
	Dec. 31, 2024
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award Payout, Shares of Common Stock Percentage	100%
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	10.32%
Share-based Compensation Arrangement by Share-based Payment Award, Award Requisite Service Period	3 years
Award vesting period	3 years
Performance Shares | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	0%
Performance Shares | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Share Award, Percentage of Target	200%

Share-based Compensation Plan_4

Share-based Compensation Plans: Performance Share Units-Market Condition (Details) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Performance Share Units - Market Condition
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award - Performance Period Used to Estimate Expected Share Payout	3 years
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (usd per share)	$ 55.14	$ 77.95
Risk-free rate	4.12%	3.84%
Black Hills Corporation’s common stock volatility	24%	31%
Volatility range for peer group, Minimum	12%	24%
Volatility range for the peer group, Maximum	53%	39%
Performance Shares | Performance Share Units - Market Condition
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (usd per share)	$ 55.14

Share-based Compensation Plan_5

Share-based Compensation Plans: Performance Condition (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted-average recognition period	2 years
Performance Share Units - Market Condition
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award - Performance Period Used to Estimate Expected Share Payout	3 years
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (usd per share)	$ 55.14	$ 77.95
Performance Share Award, Percentage of Target	10.32%
Target shares, value	$ 0.4
Performance Shares | Performance Share Units - Market Condition
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	151,535	110,747
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 66.43	$ 73.31
Performance Shares, Granted in Period	71,537
Granted (usd per share)	$ 55.14
Performance Shares, Vested in Period	(30,749)
Vested (usd per share)	$ 64.97
Performance Shares | Performance Share Units - Performance Condition
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	72,805	62,654
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 62.59	$ 67.88
Performance Shares, Granted in Period	30,663
Granted (usd per share)	$ 51
Performance Shares, Vested in Period	(20,512)
Vested (usd per share)	$ 61.45
Performance Shares | Outstanding Performance Share/Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	$ 4.3
Weighted-average recognition period	1 year 8 months 12 days

Income Taxes (Additional Inform

Income Taxes (Additional Information) (Details) - USD ($)	1 Months Ended
	Jan. 31, 2025	Jun. 30, 2024
Income Tax Disclosure [Line Items]
Transfers of production tax credits to third party		$ 16,900,000
Subsequent Event
Income Tax Disclosure [Line Items]
Transfers of production tax credits to third party	$ 17

Income Taxes_ Current and Defer

Income Taxes: Current and Deferred Income Tax (Expense) Benefit (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current:
Federal	$ 16.5	$ 0.8	$ 0.5
State	(0.8)	(1)	(0.1)
Current income tax benefit (expense)	15.7	(0.2)	0.4
Deferred:
Federal	(47.2)	(30.9)	(23.2)
State	(4.8)	5.5	(2.4)
Deferred income tax (expense)	(52)	(25.4)	(25.6)
Income tax (expense)	$ (36.3)	$ (25.6)	$ (25.2)

Income Taxes_ Effective Tax Rat

Income Taxes: Effective Tax Rate Differences From Statutory Tax Rates (Details)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Federal Statutory Rate	21%	21%	21%
State income tax (net of federal tax effect)	1.30%	(0.80%)	0.50%
Non-controlling interest	(0.70%)	(1.00%)	(0.90%)
Tax Credits	(5.60%)	(6.20%)	(7.70%)
Flow-through adjustments	(2.20%)	(1.70%)	(1.40%)
Amortization of excess deferred income taxes	(2.40%)	(3.00%)	(2.50%)
Other	(0.10%)	0.20%	(0.50%)
Effective Tax Rate	11.30%	8.50%	8.50%

Income Taxes - Effective Tax Ra

Income Taxes - Effective Tax Rate Differences From Statutory Tax Rates (Parenthetical) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Nebraska
Income Tax Disclosure [Line Items]
State income tax expense (benefit)	$ 8.2

Income Taxes_ Deferred Income T

Income Taxes: Deferred Income Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Deferred Tax Assets, Net [Abstract]
Regulatory liabilities	$ 70.9	$ 74
State tax credits	8.4	22.8
Federal NOL	114.9	146.6
State NOL	12.7	16.5
Partnership	11.6	12.2
Credit Carryovers	110.5	110.1
Other deferred tax assets	35.4	33.7
Less: Valuation allowance	(1.3)	(15.4)
Total deferred tax assets	363.1	400.5
Deferred tax liabilities:
Accelerated depreciation, amortization and other plant-related differences	(729.2)	(686.2)
Regulatory assets	(49.5)	(65.6)
Goodwill	(75.9)	(67.8)
State deferred tax liability	(88.7)	(84.5)
Other deferred tax liabilities	(44.9)	(44.4)
Total deferred tax liabilities	(988.2)	(948.5)
Net deferred tax liability	$ (625.1)	$ (548)

Income Taxes_ Net Operating Los

Income Taxes: Net Operating Loss and and Tax Credit Carryforwards (Details)	12 Months Ended
	Dec. 31, 2024 USD ($)
Internal Revenue Service (IRS)
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards, With no Expiration Date	$ 547,200,000
Tax Credit Carryforward	110,500,000
State and Local Jurisdiction
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards	242,600,000
Tax Credit Carryforward	8,400,000
State and Local Jurisdiction | Valuation Allowance, Operating Loss Carryforwards
Operating Loss Carryforwards [Line Items]
Operating Loss Carryforwards Valuation Allowance	300,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	0
Reductions in valuation allowance	700,000
State and Local Jurisdiction | Valuation Allowance, Income Tax Credit Carryforwards
Operating Loss Carryforwards [Line Items]
Income Tax Credit carryforward, valuation allowance	0
Reductions in valuation allowance	$ 14,400,000

Income Taxes_ Reconciliation of

Income Taxes: Reconciliation of unrecognized tax benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Liability for Uncertain Tax Positions, Noncurrent, Period Start	$ 13.7	$ 11.9	$ 10.6
Additions for prior year tax positions	0.6	0	0
Reductions for prior year tax positions	(8.1)	(0.3)	(0.8)
Additions for current year tax positions	1.6	2.1	2.1
Liability for Uncertain Tax Positions, Noncurrent, Period End	7.8	$ 13.7	$ 11.9
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	$ 7.5

Income Taxes_ Interest, Penalti

Income Taxes: Interest, Penalties and Audits (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Unrecognized Tax Benefits, Interest Expense	$ 0	$ 0	$ 0
Unrecognized Tax Benefits, Interest Accrued	$ 0	$ 0
Tax Year Subject to Examination	2018 2019 2021 2022 2023

Business Segment Information_ I

Business Segment Information: Information Relating to Segments Statement of Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information
Revenue	$ 2,127.7	$ 2,331.3	$ 2,551.8
Fuel, purchased power and cost of natural gas sold	730.3	982.9	1,230.6
Operations and maintenance - Direct	266.6	261.5	268.8
Operations and maintenance - Allocated	290.4	290.5	279.6
Depreciation, depletion and amortization	270.1	256.8	250.9
Taxes other than income taxes	67.2	66.9	66.7
Operating income (loss)	503.1	472.7	455.2
Interest expense, net	(181.7)	(167.9)	(161)
Other income (expense), net	(1.4)	(3.2)	1.8
Income tax (expense)	(36.3)	(25.6)	(25.2)
Net income	283.7	276	270.8
Net income attributable to non-controlling interest	(10.6)	(13.8)	(12.4)
Net income available for common stock	273.1	262.2	258.4
Corporate, Non-Segment
Segment Reporting Information
Revenue	(17.8)	(17.9)	(17.5)
Fuel, purchased power and cost of natural gas sold	(0.4)	(0.4)	(0.8)
Operations and maintenance - Direct	(16.3)	(12.9)	(13.7)
Depreciation, depletion and amortization	0.1	0.3	0.3
Taxes other than income taxes
Operating income (loss)	(1.2)	(4.9)	(3.3)
Operating Segments | Electric Utilities
Segment Reporting Information
Revenue	876.1	865	900.2
Fuel, purchased power and cost of natural gas sold	206.4	200.1	266.3
Operations and maintenance - Direct	127.5	112.2	124
Operations and maintenance - Allocated	125.1	124	120.8
Depreciation, depletion and amortization	145.3	142.6	135.9
Taxes other than income taxes	38.8	37.3	38.9
Operating income (loss)	233	248.8	214.3
Operating Segments | Gas Utilities
Segment Reporting Information
Revenue	1,269.4	1,484.2	1,669.1
Fuel, purchased power and cost of natural gas sold	524.3	783.2	965.1
Operations and maintenance - Direct	155.4	162.2	158.5
Operations and maintenance - Allocated	165.3	166.5	158.8
Depreciation, depletion and amortization	124.7	113.9	114.7
Taxes other than income taxes	28.4	29.6	27.8
Operating income (loss)	271.3	228.8	244.2
External Customers
Segment Reporting Information
Revenue	2,127.7	2,331.3	2,551.8
External Customers | Operating Segments | Electric Utilities
Segment Reporting Information
Revenue	864.4	853.6	888.4
External Customers | Operating Segments | Gas Utilities
Segment Reporting Information
Revenue	1,263.3	1,477.7	1,663.4
Inter-segment | Corporate, Non-Segment
Segment Reporting Information
Revenue	(17.8)	(17.9)	(17.5)
Inter-segment | Operating Segments | Electric Utilities
Segment Reporting Information
Revenue	11.7	11.4	11.8
Inter-segment | Operating Segments | Gas Utilities
Segment Reporting Information
Revenue	$ 6.1	$ 6.5	$ 5.7

Business Segment Information_ C

Business Segment Information: Capital Expenditures and Asset Acquisitions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information [Line Items]
Capital Expenditures	$ 797.6	$ 589.9	$ 597.7
Corporate, Non-Segment
Segment Reporting Information [Line Items]
Capital Expenditures	13	7.3	5.1
Electric Utilities | Operating Segments
Segment Reporting Information [Line Items]
Capital Expenditures	381.9	210.7	243.1
Gas Utilities | Operating Segments
Segment Reporting Information [Line Items]
Capital Expenditures	$ 402.7	$ 371.9	$ 349.5