[10-Q] Black Hills Corporation Quarterly Earnings Report

Rhea-AI Filing Summary

BKH’s Q2 2025 results showed solid top-line and earnings growth. Revenue rose 9% year-over-year to $439 million, lifting operating income 17% to $82.5 million. Net income available to common stock climbed 21% to $27.5 million ($0.38 diluted EPS vs $0.33).

For the first half, revenue increased 10% to $1.24 billion and net income grew 7% to $161.7 million ($2.24 diluted EPS). Higher retail sales at both Electric and Gas Utilities plus larger transportation volumes drove the gains; operating margin held at 23%. Interest expense, however, continued to pressure results, up 8% year-to-date to $101.6 million.

Liquidity remains adequate: operating cash flow was $416 million (-10% YoY) against $372 million of capex, while the $750 million revolver maturity was extended to 2030. Long-term debt declined to $3.95 billion (-7% since year-end) but $300 million matures within 12 months; leverage stands near 59% of capital. The company issued $84 million of equity through ATM programs.

Regulatory momentum is favorable. CPUC approved a $17.5 million Colorado Electric rate hike effective March 2025; KCC okayed a $10.8 million Kansas Gas settlement effective Aug 2025; Nebraska Gas filed for $34.9 million, with interim rates expected in Aug 2025. Regulatory assets tied to Winter Storm Uri fell to $64.9 million (-41% YTD).

Positive

• Revenue up 9% YoY to $439 M, with EPS +15% YoY to $0.38.
• Regulators approved $28 M of annual rate increases (CO & KS) enhancing future cash flow.
• Long-term debt reduced by $298 M since Dec 2024; revolver maturity extended to 2030.
• Winter Storm Uri regulatory asset recouped by 41%, lowering balance-sheet risk.

Negative

• Operating cash flow fell 10% YoY to $416 M, tighter coverage of $372 M capex.
• Interest expense rose 8% YTD to $101.6 M, pressuring net margins.
• Equity issuances of $84 M create dilution risk.
• Cash balance only $8 M, leaving company reliant on credit lines.

Insights

Utility Equity Analyst

TL;DR: Modest beat, constructive regulatory wins, leverage manageable—incrementally positive.

BKH’s 9% sales and 21% EPS growth outpaced typical mid-cap utility peers. Constructive rulings in CO and KS improve allowed revenue by ~$28 million annually, enhancing forward earnings visibility. Equity issuance diluted 1% but eases financing risk alongside revolver extension. Capex largely self-funded; FFO/debt trends toward 14%, acceptable for BBB rating. Near-term catalysts: Nebraska decision, Lange II build, Ready Wyoming transmission. Valuation support comes from 3.9% dividend yield backed by 56% payout ratio.

Credit Analyst

TL;DR: Leverage edging lower; interest burden high but manageable—credit neutral/positive.

Long-term debt fell $298 million YTD and maturities are laddered, though $300 million due within a year requires refinancing. Revolver extension to 2030 and $8 million cash buffer provide liquidity but limited cushion. Regulatory recovery mechanisms (fuel, CEPR, GSRS) stabilize cash flows, offsetting thinner headroom from rising rates. FFO/Net Debt expected in mid-teens; interest coverage ~3.6× remains adequate. Outlook stable barring cost overruns on large projects.

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2025

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________

Commission File Number 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road

Rapid City, South Dakota 57702

Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report

NONE

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

	Large Accelerated Filer	x		Accelerated Filer	☐
	Non-accelerated Filer	☐		Smaller Reporting Company	☐
				Emerging Growth Company	☐

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act:
	Title of each class		Trading Symbol(s)		Name of each exchange on which registered
	Common stock of $1.00 par value		BKH		New York Stock Exchange

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.

	Class	Outstanding at July 29, 2025
	Common stock, $1.00 par value	72,851,741	shares

Table of Contents

TABLE OF CONTENTS

		Page
Glossary of Terms and Abbreviations		3
Forward-Looking Information		7
PART I. FINANCIAL INFORMATION		8
Item 1.	Financial Statements - unaudited	8
	Consolidated Statements of Income	8
	Consolidated Statements of Comprehensive Income	9
	Consolidated Balance Sheets	10
	Consolidated Statements of Cash Flows	12
	Consolidated Statements of Equity	13
	Condensed Notes to Consolidated Financial Statements	14
	Note 1. Management’s Statement	14
	Note 2. Regulatory Matters	15
	Note 3. Commitments, Contingencies and Guarantees	16
	Note 4. Revenue	17
	Note 5. Financing	18
	Note 6. Earnings Per Share	19
	Note 7. Risk Management and Derivatives	20
	Note 8. Fair Value Measurements	23
	Note 9. Other Comprehensive Income	25
	Note 10. Employee Benefit Plans	26
	Note 11. Income Taxes	27
	Note 12. Business Segment Information	27
	Note 13. Selected Balance Sheet Information	30
	Note 14. Subsequent Events	31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	32
	Executive Summary	32
	Recent Developments	32
	Results of Operations	33
	Consolidated Summary and Overview	34
	Non-GAAP Financial Measure	35
	Electric Utilities	36
	Gas Utilities	39
	Corporate and Other	41
	Consolidated Interest Expense, Other Income and Income Tax Expense	41
	Liquidity and Capital Resources	42
	Cash Flow Activities	42
	Capital Resources	44
	Credit Ratings	44
	Capital Requirements	44
	Critical Accounting Estimates	45
	New Accounting Pronouncements	45
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	45
Item 4.	Controls and Procedures	45
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	45
Item 1A.	Risk Factors	45
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 4.	Mine Safety Disclosures	46
Item 5.	Other Information	46
Item 6.	Exhibits	46
Signatures		46

2

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:

AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
Arkansas Gas	Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
ASU	Accounting Standards Update as issued by the FASB
ATM	At-the-market equity offering program
Availability	The availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHC	Black Hills Corporation; the Company
Black-box Settlement	Settlement with a utility's commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Black Hills Colorado IPP	Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.
Black Hills Electric Parent Holdings	Black Hills Electric Utility Holdings, LLC., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Energy	The name used to conduct the business of our Utilities
Black Hills Energy Renewable Resources (BHERR)	Black Hills Energy Renewable Resources, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy Services	Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Blockchain Interruptible Service (BCIS) Tariff	A WPSC-approved tariff applicable to prospective new Wyoming Electric blockchain customers. The tariff allows customers to negotiate rates and terms and conditions for interruptible electric utility service of 10 MW or greater that would be interconnected with Wyoming Electric’s system. Agreements under the BCIS tariff must be filed with the WPSC prior to the first customer billing, be at least 2 years in duration and include specific pricing for all electricity purchased (with pricing terms subject to renegotiation every three years). BCIS customers shall not participate in the PCA to the extent of service received under the tariff.
Busch Ranch I	A 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.
Busch Ranch II	A 59.4 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a PPA expiring in November 2044.
CEPR	Clean Energy Plan Rider, which is a 1.5% surcharge to fund Colorado Electric's recovery of renewable energy projects under the Clean Energy Plan. In conjunction with the implementation of the CEPR in January 2025, the RESA surcharge was reduced from 2.0% to 1.5%.
Choice Gas Program	Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.
Chief Operating Decision Maker (CODM)	Chief Executive Officer
CIAC	Contribution in aid of construction

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Clean Energy Plan	2030 Ready Plan that establishes a roadmap and preferred resource portfolio for Colorado Electric to achieve the State of Colorado’s requirement calling upon electric utilities to reduce greenhouse gas emissions by a minimum of 80% from 2005 levels by 2030. The recommended resource portfolio proposes the addition of 350 MW of clean energy resources to Colorado Electric's system. Colorado legislation allows electric utilities to own up to 50% of the renewable generation assets added to comply with the Clean Energy Plan.
Colorado Electric	Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Parent Holdings, providing electric services to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas	Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Consolidated Indebtedness to Capitalization Ratio	Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and the low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CP Program	Commercial Paper Program
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion Turbine
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Emergency PSPS	Emergency Public Safety Power Shutoff is a safety measure to prevent the electric system from becoming a potential source of ignition during extreme weather conditions/events. It entails selectively and intentionally turning off power to a portion of a service area when high-fire-risk weather and fuel conditions occur.
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings Inc.
GAAP	Accounting principles generally accepted in the United States of America
GSRS	Gas System Reliability Surcharge is a monthly charge that recovers Kansas Gas's costs associated with pipeline safety and government-mandated projects.
Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServe	We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
Integrated Generation	Non-regulated power generation and mining businesses (Black Hills Electric Generation and WRDC) that are vertically integrated within our Electric Utilities segment.
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP	Independent Power Producer
IRA	Inflation Reduction Act of 2022
IRS	United States Internal Revenue Service
IUC	Iowa Utilities Commission
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
KCC	Kansas Corporation Commission

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Lange II	A dual fuel (natural gas and diesel oil) electric generation project in Rapid City, South Dakota with an estimated total capacity of 99 MW. This facility will be owned and operated by South Dakota Electric and will be located adjacent to the Lange CT generation facility. This project is expected to begin construction in third quarter of 2025 and in service during the the second half of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements.
Large Power Contract Service (LPCS) Tariff	Innovative tariff solution developed in collaboration with Microsoft and approved by the WPSC in 2016. The LPSC is applicable to Wyoming Electric retail customers with new loads of 13 MW or greater who agree to Black Hills Energy-dispatched, customer-owned generation, on-site for the purpose of providing backup service for the customer’s load and maintaining reliability. If the parties agree through negotiations to electric service through this tariff, a Large Power Service Agreement will be executed. The associated service agreement provides qualifying customers with market-based energy rates and access to renewable energy resources that is not served from utility-owned generation (i.e. minimal capital model for Wyoming Electric). Customers shall not participate in the PCA or TCAM to the extent of service received under the tariff.
MMBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
MW	Megawatts
MWh	Megawatt-hours
N/A	Not applicable
Nebraska Gas	Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
NPSC	Nebraska Public Service Commission
OBBBA	One Big Beautiful Bill Act enacted on July 4, 2025, which is a legislative package designed to permanently extend certain expiring provisions of the TCJA and deliver additional tax relief for individuals and businesses. The OBBBA introduced changes to federal energy policies by rolling back several clean energy provisions and codified restrictions related to prohibited foreign entities, termination and restrictions on clean energy PTCs, extension and modification of clean fuel production. The OBBBA does not repeal tax credit transferability provisions enacted under the IRA, but restricts credit transfers to prohibited foreign entities.
OCI	Other Comprehensive Income
PPA	Power Purchase Agreement
PTC	Production Tax Credit
Pueblo Airport Generation	Pueblo Airport Generating Station located in Pueblo, Colorado includes 440 MW of combined cycle gas-fired power generation plants jointly owned by Colorado Electric (240 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP operates this facility. The plants commenced operation on January 1, 2012.
Ready Wyoming	A 260-mile, multi-phase transmission expansion project in Wyoming. This transmission project is expected to serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and expanding access to power markets and renewable resources. The project is expected to help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region.
RESA	Renewable Energy Standard Adjustment is an incremental retail rate limited to 1.5% for Colorado Electric customers that provides funding for renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard.
Revolving Credit Facility	Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended on May 31, 2024, and will terminate on May 31, 2030. This facility 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.
RNG	Renewable natural gas
SEC	United States Securities and Exchange Commission
Service Guard Comfort Plan	Appliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.
S&P	S&P Global Ratings, a division of S&P Global Inc.
South Dakota Electric	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).

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TCAM	Transmission Cost Adjustment Mechanism is a WPSC-approved tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmission costs.
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017, which reduced the U.S. federal corporate tax rate from 35% to 21%. As such, we remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017.
Tech Services	Non-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our Electric Utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
Utilities	Black Hills' Electric and Gas Utilities
Wind Capacity Factor	Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.
Winter Storm Uri	February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a coal mine which is a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities at our Gillette Energy Complex (doing business as Black Hills Energy).
Wygen I	A mine-mouth, coal-fired generating facility with a total capacity of 90 MW located at our Gillette Energy Complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wygen III	A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 116 MW located at our Gillette Energy Complex. South Dakota Electric owns 52% of the power plant, MDU owns 25%, and the City of Gillette owns the remaining 23%.
Wyoming Electric	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas	Black Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

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FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 2024 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q and other reports that we file with the SEC from time to time, and the following:

•Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings on periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power and other operating costs, and the timing in which new rates would go into effect;

•Our ability to complete our capital program in a cost-effective and timely manner;

•Our ability to execute on our strategy;

•Our ability to successfully execute our financing plans;

•The effects of changing interest rates;

•Our ability to achieve our greenhouse gas emissions intensity reduction goals;

•The impact of future governmental regulation;

•Our ability to overcome the impacts of supply chain disruptions on availability and cost of materials;

•The effects of inflation, tariffs and volatile energy prices;

•Our ability to obtain sufficient insurance coverage at reasonable costs and whether such coverage will protect us against significant losses; and

•Other factors discussed from time to time in our filings with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2025			2024			2025			2024
	(in millions, except per share amounts)
Revenue	$	439.0		$	402.6		$	1,244.2		$	1,129.0
Operating expenses:
Fuel, purchased power and cost of natural gas sold		124.0			107.1			483.8			423.7
Operations and maintenance		147.6			141.7			301.3			275.2
Depreciation and amortization		69.8			66.6			139.0			132.5
Taxes other than income taxes		15.1			16.6			32.7			33.6
Total operating expenses		356.5			332.0			956.8			865.0
Operating income		82.5			70.6			287.4			264.0
Other income (expense):
Interest expense incurred net of amounts capitalized		(49.8	)		(48.2	)		(101.6	)		(94.2	)
Interest income		0.9			5.6			1.3			7.5
Other income (expense), net		(0.4	)		0.4			0.6			(0.5	)
Total other (expense)		(49.3	)		(42.2	)		(99.7	)		(87.2	)
Income before income taxes		33.2			28.4			187.7			176.8
Income tax (expense)		(4.4	)		(3.7	)		(22.5	)		(20.6	)
Net income		28.8			24.7			165.2			156.2
Net income attributable to non-controlling interest		(1.3	)		(1.9	)		(3.5	)		(5.6	)
Net income available for common stock	$	27.5		$	22.8		$	161.7		$	150.6
Earnings per share of common stock:
Earnings per share, Basic	$	0.38		$	0.33		$	2.25		$	2.20
Earnings per share, Diluted	$	0.38		$	0.33		$	2.24		$	2.19
Weighted average common shares outstanding:
Basic		72.4			69.0			72.0			68.6
Diluted		72.4			69.0			72.1			68.7

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)	Three Months Ended June 30,						Six Months Ended June 30,
	2025			2024			2025			2024
	(in millions)
Net income	$	28.8		$	24.7		$	165.2		$	156.2
Other comprehensive income (loss), net of tax;
Reclassification adjustments of benefit plan liability - net loss (net of tax of $0.0, $0.0, $0.0 and $0.0, respectively)		—			—			0.1			0.1
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(0.2), $(0.2), $(0.3), and $(0.3), respectively)		0.6			0.6			1.1			1.1
Net unrealized gains (losses) on commodity derivatives (net of tax of $0.1, $0.0, $0.1, and $0.0, respectively)		(0.3	)		—			(0.2	)		(0.2	)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $0.0, $(0.1), $(0.2), and $(0.8), respectively)		0.1			0.4			0.4			2.5
Other comprehensive income, net of tax		0.4			1.0			1.4			3.5
Comprehensive income		29.2			25.7			166.6			159.7
Less: comprehensive income attributable to non-controlling interest		(1.3	)		(1.9	)		(3.5	)		(5.6	)
Comprehensive income available for common stock	$	27.9		$	23.8		$	163.1		$	154.1

See Note 9 for additional disclosures.

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(unaudited)	As of
	June 30, 2025			December 31, 2024
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	8.1		$	16.1
Restricted cash and equivalents		7.7			7.3
Accounts receivable, net		260.8			351.2
Materials, supplies and fuel		145.2			153.9
Income tax receivable, net		20.9			19.8
Regulatory assets, current		132.1			154.8
Other current assets		33.6			39.2
Total current assets		608.4			742.3
Property, plant and equipment		9,894.5			9,566.5
Less: accumulated depreciation		(2,034.1	)		(1,936.6	)
Total property, plant and equipment, net		7,860.4			7,629.9
Other assets:
Goodwill		1,299.5			1,299.5
Intangible assets, net		7.0			7.6
Regulatory assets, non-current		247.8			272.9
Other assets, non-current		68.5			70.4
Total other assets, non-current		1,622.8			1,650.4
TOTAL ASSETS	$	10,091.6		$	10,022.6

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Continued)

(unaudited)	As of
	June 30, 2025			December 31, 2024
	(in millions)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	180.8		$	229.1
Accrued liabilities		251.1			302.2
Derivative liabilities, current		1.7			4.2
Regulatory liabilities, current		96.6			94.1
Notes payable		123.7			133.8
Current maturities of long-term debt		300.0			—
Total current liabilities		953.9			763.4
Long-term debt, net of current maturities		3,952.4			4,250.2
Deferred credits and other liabilities:
Deferred income tax liabilities, net		674.0			625.1
Regulatory liabilities, non-current		480.1			474.6
Benefit plan liabilities		119.9			122.9
Other deferred credits and other liabilities		191.9			201.2
Total deferred credits and other liabilities		1,465.9			1,423.8
Commitments, contingencies and guarantees (Note 3)
Equity:
Stockholder's equity -
Common stock $1 par value; 100,000,000 shares authorized; issued 72,902,676 and 71,676,756 shares, respectively		72.9			71.7
Additional paid-in capital		2,260.7			2,193.4
Retained earnings		1,313.3			1,249.1
Treasury stock, at cost - 47,947 and 56,608 shares, respectively		(2.8	)		(3.3	)
Accumulated other comprehensive (loss)		(8.0	)		(9.4	)
Total stockholders' equity		3,636.1			3,501.5
Non-controlling interest		83.3			83.7
Total equity		3,719.4			3,585.2
TOTAL LIABILITIES AND TOTAL EQUITY	$	10,091.6		$	10,022.6

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)	Six Months Ended June 30,
	2025			2024
Operating activities:	(in millions)
Net income	$	165.2		$	156.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		139.0			132.5
Deferred financing cost amortization		4.3			5.5
Stock compensation		5.7			5.4
Deferred income taxes		37.5			36.6
Employee benefit plans		5.6			5.6
Other adjustments, net		2.9			(4.0	)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel		8.4			29.0
Accounts receivable and other current assets		84.8			117.1
Accounts payable and other current liabilities		(93.3	)		(77.4	)
Regulatory assets		57.9			69.8
Other operating activities, net		(1.6	)		(12.3	)
Net cash provided by operating activities		416.4			464.0
Investing activities:
Property, plant and equipment additions		(371.8	)		(342.4	)
Other investing activities		(4.4	)		1.7
Net cash (used in) investing activities		(376.2	)		(340.7	)
Financing activities:
Dividends paid on common stock		(97.6	)		(89.3	)
Common stock issued		65.0			73.0
Net borrowings (payments) of Revolving Credit Facility and CP Program		(10.1	)		—
Long-term debt - issuance		—			450.0
Distributions to non-controlling interests		(3.8	)		(10.0	)
Other financing activities		(1.3	)		(8.3	)
Net cash provided by (used in) financing activities		(47.8	)		415.4
Net change in cash, restricted cash and cash equivalents		(7.6	)		538.7
Cash, restricted cash, and cash equivalents beginning of period		23.4			93.0
Cash, restricted cash, and cash equivalents end of period	$	15.8		$	631.7
Supplemental cash flow information:
Cash (paid) received during the period:
Interest (net of amounts capitalized)	$	(100.8	)	$	(89.5	)
Income taxes, net of transferred tax credits (Note 11)		13.9			14.7
Non-cash investing and financing activities:
Accrued property, plant, and equipment purchases at June 30,		78.5			73.0

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

(unaudited)	Common Stock						Treasury Stock
	Shares			Value			Shares			Value			Additional Paid in Capital			Retained Earnings			AOCI			Non-controlling Interest			Total
	(in millions except share amounts)
December 31, 2024		71,676,756		$	71.7			56,608		$	(3.3	)	$	2,193.4		$	1,249.1		$	(9.4	)	$	83.7		$	3,585.2
Net income		—			—			—			—			—			134.3			—			2.1			136.4
Other comprehensive income, net of tax		—			—			—			—			—			—			1.0			—			1.0
Dividends on common stock ($0.676 per share)		—			—			—			—			—			(48.6	)		—			—			(48.6	)
Share-based compensation		103,995			0.1			(22,488	)		1.3			(0.1	)		—			—			—			1.3
Issuance of common stock		763,481			0.7			—			—			45.4			—			—			—			46.1
Issuance costs		—			—			—			—			(0.5	)		—			—			—			(0.5	)
Distributions to non-controlling interest		—			—			—			—			—			—			—			(3.8	)		(3.8	)
March 31, 2025		72,544,232		$	72.5			34,120		$	(2.0	)	$	2,238.2		$	1,334.8		$	(8.4	)	$	82.0		$	3,717.1
Net income		—			—			—			—			—			27.5			—			1.3			28.8
Other comprehensive income, net of tax		—			—			—			—			—			—			0.4			—			0.4
Dividends on common stock ($0.676 per share)		—			—			—			—			—			(49.0	)		—			—			(49.0	)
Share-based compensation		19,159			0.1			13,827			(0.8	)		3.4			—			—			—			2.7
Issuance of common stock		339,285			0.3			—			—			19.4			—			—			—			19.7
Issuance costs		—			—			—			—			(0.3	)		—			—			—			(0.3	)
June 30, 2025		72,902,676		$	72.9			47,947		$	(2.8	)	$	2,260.7		$	1,313.3		$	(8.0	)	$	83.3		$	3,719.4

(unaudited)	Common Stock						Treasury Stock
	Shares			Value			Shares			Value			Additional Paid in Capital			Retained Earnings			AOCI			Non-controlling Interest			Total
	(in millions except share amounts)
December 31, 2023		68,265,042		$	68.3			68,073		$	(4.1	)	$	2,007.7		$	1,158.2		$	(14.8	)	$	90.5		$	3,305.8
Net income		—			—			—			—			—			127.9			—			3.7			131.6
Other comprehensive income, net of tax		—			—			—			—			—			—			2.5			—			2.5
Dividends on common stock ($0.65 per share)		—			—			—			—			—			(44.4	)		—			—			(44.4	)
Share-based compensation		104,181			0.1			14,270			(0.6	)		1.9			—			—			—			1.4
Issuance of common stock		600,355			0.6			—			—			30.9			—			—			—			31.5
Issuance costs		—			—			—			—			(0.3	)		—			—			—			(0.3	)
Distributions to non-controlling interest		—			—			—			—			—			—			—			(5.6	)		(5.6	)
March 31, 2024		68,969,578		$	69.0			82,343		$	(4.7	)	$	2,040.2		$	1,241.7		$	(12.3	)	$	88.6		$	3,422.5
Net income		—			—			—			—			—			22.8			—			1.9			24.7
Other comprehensive income, net of tax		—			—			—			—			—			—			1.0			—			1.0
Dividends on common stock ($0.65 per share)		—			—			—			—			—			(44.9	)		—			—			(44.9	)
Share-based compensation		9,623			—			817			(0.2	)		2.9			—			—			—			2.7
Issuance of common stock		768,019			0.7			—			—			41.5			—			—			—			42.2
Issuance costs		—			—			—			—			(0.4	)		—			—			—			(0.4	)
Distributions to non-controlling interest		—			—			—			—			—			—			—			(4.4	)		(4.4	)
June 30, 2024		69,747,220		$	69.7			83,160		$	(4.9	)	$	2,084.2		$	1,219.6		$	(11.3	)	$	86.1		$	3,443.4

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BLACK HILLS CORPORATION

Condensed Notes to Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2024 Annual Report on Form 10-K)

(1)Management’s Statement

The unaudited Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we”, or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 2024 Annual Report on Form 10-K.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2025, December 31, 2024, and June 30, 2024, financial information. Certain lines of business in which we operate are highly seasonal and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.

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. We are evaluating the disclosure impact of ASU 2023-09; however, the standard is not expected to have an impact on our financial condition, results of operations and/or cash flows.

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 evaluating the disclosure impact of ASU 2024-03; however, the standard is not expected to have an impact on our financial condition, results of operations and/or cash flows.

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(2)Regulatory Matters

We had the following regulatory assets and liabilities:

	As of			As of
	June 30, 2025			December 31, 2024
	(in millions)
Regulatory assets
Winter Storm Uri	$	64.9		$	109.5
Deferred energy and fuel cost adjustments		70.6			62.8
Deferred gas cost adjustments		3.0			14.5
Gas price derivatives		1.0			2.9
Deferred taxes on AFUDC		9.0			8.0
Employee benefit plans and related deferred taxes		86.7			89.0
Environmental		11.5			10.7
Loss on reacquired debt		14.9			15.7
Deferred taxes on flow through accounting		92.8			87.7
Decommissioning costs		2.4			2.4
Other regulatory assets		23.1			24.5
Total regulatory assets		379.9			427.7
Less current regulatory assets		(132.1	)		(154.8	)
Regulatory assets, non-current	$	247.8		$	272.9
Regulatory liabilities
Deferred energy and gas costs	$	67.5		$	67.8
Employee benefit plan costs and related deferred taxes		35.5			36.7
Cost of removal		206.6			197.0
Excess deferred income taxes		234.1			238.5
Colorado renewable energy (a)		28.9			24.1
Other regulatory liabilities		4.1			4.6
Total regulatory liabilities		576.7			568.7
Less current regulatory liabilities		(96.6	)		(94.1	)
Regulatory liabilities, non-current	$	480.1		$	474.6

(a)Represents Colorado Electric's RESA and CEPR mechanisms, which allow for recovery/repayment of costs, but not a rate of return. Through these mechanisms, which are authorized by the CPUC, Colorado Electric is allowed to charge its retail customers an incremental rate limited to 1.5% per mechanism that provides funding for various renewable energy projects and programs to comply with requirements under the State of Colorado’s emissions reduction legislation. Project costs that are over-recovered through customer rates will be refunded to customers in future periods.

Regulatory Activity

Colorado Electric

On June 14, 2024, Colorado Electric filed a rate review with the CPUC seeking recovery of infrastructure investments in its 3,200-mile electric distribution and 600-mile electric transmission systems. On March 17, 2025, Colorado Electric received an order from the CPUC for a general rate increase which was expected to generate approximately $17.0 million of new annual revenue based on a weighted average cost of capital of 6.9% with a capital structure in a range of 47% to 49% equity and 51% to 53% debt, and a return on equity in a range of 9.3% to 9.5%. The new rates were effective March 22, 2025. On April 7, 2025, Colorado Electric filed a request with the CPUC for rehearing, re-argument or reconsideration (RRR). On May 6, 2025, Colorado Electric received a final decision from the CPUC related to its RRR request, increasing new annual revenue from approximately $17.0 million to approximately $17.5 million.

Iowa Gas

On May 1, 2024, Iowa Gas filed a rate review with the IUC seeking recovery of infrastructure investments in its 5,000-mile natural gas pipeline system. In the fourth quarter of 2024, Iowa Gas received final approval from the IUC for a settlement agreement for a general rate increase. The 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.

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Kansas Gas

On February 3, 2025, Kansas Gas filed a rate review with the KCC seeking recovery of infrastructure investments in its 4,765-mile natural gas pipeline system and increased operations and maintenance costs driven by inflation and operational needs to serve customers. On July 24, 2025, Kansas Gas received final approval from the KCC for a settlement agreement for a general rate increase. The approved Black-box Settlement is expected to generate $10.8 million in new annual revenue and will shift $4.4 million of GSRS rider revenue to base rates. New rates will be effective on August 1, 2025. The settlement also includes approval for Kansas Gas to file an abbreviated case in first quarter of 2026 that includes the addition of capital placed in service through December 31, 2025.

Nebraska Gas

On May 1, 2025, Nebraska Gas filed a rate review with the NPSC seeking recovery of infrastructure investments in its 12,900-mile natural gas pipeline system and increased operations and maintenance costs driven by inflation and operational needs to serve customers. The rate review requests $34.9 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 10.5%. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review and Nebraska Gas plans to implement interim rates, subject to adjustment or refund, effective in August 2025. New rates are expected to be effective in the first quarter of 2026.

(3)Commitments, Contingencies and Guarantees

There have been no significant changes to commitments, contingencies and guarantees from those previously disclosed in Note 3 of our Notes to the Consolidated Financial Statements in our 2024 Annual Report on Form 10-K except as described below.

Transfers of Renewable Tax Credits

In January 2025, we entered into an agreement with a third party to sell our 2024 generated PTCs. In the agreement, we provided indemnifications associated with the proceeds for PTCs transferred to the third party in the event of an adverse change or interpretation of tax law, including whether the related tax credits meet the qualification requirements. We believe the likelihood of having to make any material cash payments under these indemnifications is remote. See Note 11 for additional information.

Manufactured Gas Plant

In 2008, we acquired liabilities for a former manufactured gas plant site in Iowa, which was previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.5 million recorded in Other current assets on our Consolidated Balance Sheets, which will be used to help offset remediation costs. As of December 31, 2024, we had an Accrued liability of $9.7 million on our Consolidated Balance Sheets for the remaining remediation of the manufactured gas plant site in Iowa. During the six months ended June 30, 2025, we completed substantially all remaining remediation work. As of June 30, 2025, $11.5 million of cumulative remediation costs, which are net of our $1.5 million insurance recovery asset, were recorded to a Regulatory asset on our Consolidated Balance Sheets which Iowa Gas intends to seek recovery of during a future rate review. We expect to recover our $1.5 million insurance recovery asset by year-end 2025.

GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (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. The retrial occurred and on May 12, 2025, the jury returned a verdict in favor of BHC and its subsidiaries on all counts, thus resolving any claims without material impact on our financial position, results or operations and cash flows.

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(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 three and six months ended June 30, 2025, and 2024. Sales tax and other similar taxes are excluded from revenues.

Three Months Ended June 30, 2025	Electric Utilities			Gas Utilities			Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	178.1		$	168.5		$	—		$	346.6
Transportation		—			42.1			(0.1	)		42.0
Wholesale		4.2			—			—			4.2
Market - off-system sales		10.7			0.1			—			10.8
Transmission		10.0			0.1			—			10.1
Other revenues		15.6			10.2			(3.8	)		22.0
Revenue from contracts with customers	$	218.6		$	221.0		$	(3.9	)	$	435.7
Alternative revenue and other		1.3			2.0			—			3.3
Total revenues	$	219.9		$	223.0		$	(3.9	)	$	439.0
Timing of revenue recognition:
Services transferred at a point in time	$	9.1		$	—		$	—		$	9.1
Services transferred over time		209.5			221.0			(3.9	)		426.6
Revenue from contracts with customers	$	218.6		$	221.0		$	(3.9	)	$	435.7

Three Months Ended June 30, 2024	Electric Utilities			Gas Utilities			Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	163.4		$	152.9		$	—		$	316.3
Transportation		—			36.0			(0.2	)		35.8
Wholesale		6.5			—			—			6.5
Market - off-system sales		5.5			—			—			5.5
Transmission		12.9			0.1			—			13.0
Other revenues		14.4			9.9			(4.3	)		20.0
Revenue from contracts with customers	$	202.7		$	198.9		$	(4.5	)	$	397.1
Alternative revenue and other		2.4			3.1			—			5.5
Total revenues	$	205.1		$	202.0		$	(4.5	)	$	402.6
Timing of revenue recognition:
Services transferred at a point in time	$	7.8		$	—		$	—		$	7.8
Services transferred over time		194.9			198.9			(4.5	)		389.3
Revenue from contracts with customers	$	202.7		$	198.9		$	(4.5	)	$	397.1

Six Months Ended June 30, 2025	Electric Utilities			Gas Utilities			Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	369.3		$	668.3		$	—		$	1,037.6
Transportation		—			99.8			(0.2	)		99.6
Wholesale		11.3			—			—			11.3
Market - off-system sales		22.0			0.1			—			22.1
Transmission		22.2			0.3			—			22.5
Other revenues		29.4			21.2			(7.6	)		43.0
Revenue from contracts with customers	$	454.2		$	789.7		$	(7.8	)	$	1,236.1
Alternative revenue and other		2.4			5.7			—			8.1
Total revenues	$	456.6		$	795.4		$	(7.8	)	$	1,244.2
Timing of revenue recognition:
Services transferred at a point in time	$	17.2		$	—		$	—		$	17.2
Services transferred over time		437.0			789.7			(7.8	)		1,218.9
Revenue from contracts with customers	$	454.2		$	789.7		$	(7.8	)	$	1,236.1

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Six Months Ended June 30, 2024	Electric Utilities			Gas Utilities			Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	343.0		$	590.3		$	—		$	933.3
Transportation		—			87.6			(0.2	)		87.4
Wholesale		15.0			—			—			15.0
Market - off-system sales		12.0			—			—			12.0
Transmission		25.6			0.4			—			26.0
Other revenues		28.5			20.8			(8.7	)		40.6
Revenue from contracts with customers	$	424.1		$	699.1		$	(8.9	)	$	1,114.3
Alternative revenue and other		3.2			11.5			—			14.7
Total revenues	$	427.3		$	710.6		$	(8.9	)	$	1,129.0
Timing of revenue recognition:
Services transferred at a point in time	$	16.5		$	—		$	—		$	16.5
Services transferred over time		407.6			699.1			(8.9	)		1,097.8
Revenue from contracts with customers	$	424.1		$	699.1		$	(8.9	)	$	1,114.3

(5)Financing

Short-term Debt

Revolving Credit Facility and CP Program

On June 6, 2025, with approval from our lenders, we utilized one of our two available one-year extension options under the amended and restated Revolving Credit Facility, thereby extending its maturity date to May 31, 2030.

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 as of:

	June 30, 2025			December 31, 2024
	(dollars in millions)
Amount outstanding	$	123.7		$	133.8
Letters of credit (a)		3.5			3.5
Available capacity		622.8			612.7
Weighted average interest rates		4.58	%		4.74	%

(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 was as follows:

	Six Months Ended June 30,
	2025			2024
	(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)	$	157.8		$	—
Average amount outstanding (based on daily outstanding balances)		80.4			—
Weighted average interest rates		4.60	%	N/A

Financial Covenants

Revolving Credit Facility

We were in compliance with all of our Revolving Credit Facility covenants as of June 30, 2025. 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 June 30, 2025, our Consolidated Indebtedness to Capitalization Ratio was 0.55 to 1.00.

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Wyoming Electric

Wyoming Electric was in compliance with all covenants within its financing agreements as of June 30, 2025. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of June 30, 2025, Wyoming Electric's debt to capitalization ratio was 0.51 to 1.00.

Equity

ATM

On May 8, 2025, we entered into a First Amendment to our Equity Distribution Sales Agreement (the “First Amendment”). The First Amendment, among other things, provides for the continuation of the ATM, which allows us to sell shares of common stock under the Company's shelf registration statement (Registration No. 333-272739), and resets the size of the ATM to $400 million. The First Amendment aggregate gross sales price limitation of $400 million supersedes and replaces the aggregate gross sales price limitation provided in our Equity Distribution Sales Agreement. Except as modified by the First Amendment, our Equity Distribution Sales Agreement remains in full force and effect.

ATM activity was as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2025			2024			2025			2024
June 16, 2023 ATM Program	(in millions, except Average price per share amounts)
Proceeds, (net of issuance costs of $0.0, $(0.4), $(0.5), and $(0.7), respectively)	$	—		$	41.8		$	45.7		$	73.0
Number of shares issued		—			0.8			0.8			1.4
May 8, 2025 ATM Program
Proceeds, (net of issuance costs of $(0.2), $0.0, $(0.2), and $0.0, respectively)	$	19.6		$	—		$	19.6		$	—
Number of shares issued		0.3			—			0.3			—
Total activity under both ATM Programs
Proceeds, (net of issuance costs of $(0.2), $(0.4), $(0.7), and $(0.7), respectively)	$	19.6		$	41.8		$	65.3		$	73.0
Number of shares issued		0.3			0.8			1.1			1.4
Average price per share	$	58.28		$	55.02		$	59.78		$	53.92

(6)Earnings Per Share

A reconciliation of share amounts used to compute earnings per share in the accompanying Consolidated Statements of Income was as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2025			2024			2025			2024
	(in millions, except per share amounts)
Net income available for common stock	$	27.5		$	22.8		$	161.7		$	150.6
Weighted average shares - basic		72.4			69.0			72.0			68.6
Dilutive effect of equity compensation		—			—			0.1			0.1
Weighted average shares - diluted	$	72.4		$	69.0		$	72.1		$	68.7
Net income available for common stock, per share - Diluted	$	0.38		$	0.33		$	2.24		$	2.19

Anti-dilutive shares excluded from the diluted earnings per share computation were not material for the three and six months ended June 30, 2025, and 2024.

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(7)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, geopolitical events, pandemics, market speculation, imposition of new tariffs, 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 customers’ 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 are detailed below and in Note 8.

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 the 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 July 2025 through December 2027. 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.

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The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We had the following net long and (short) positions as of:

	June 30, 2025				December 31, 2024
	Notional Amounts (MMBtus)			Maximum Term (months) (a)	Notional Amounts (MMBtus)			Maximum Term (months) (a)
Natural gas futures purchased		—		N/A		660,000		3
Natural gas options purchased, net		1,160,000		9		2,780,000		3
Natural gas basis swaps purchased		—		N/A		1,080,000		3
Natural gas over-the-counter swaps, net (b)		5,590,000		29		3,480,000		20
Natural gas physical contracts, net (c)		6,077,280		9		20,276,230		10

(a)Term reflects the maximum forward period hedged.

(b)As of June 30, 2025, 3,040,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c)Volumes exclude contracts that qualify for the normal purchases and normal sales exception under 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 June 30, 2025, the Company posted $0.1 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

The following table presents the fair value and balance sheet classification of our derivative instruments as of:

	Balance Sheet Location	June 30, 2025			December 31, 2024
		(in millions)
Derivatives designated as hedges:
Asset derivative instruments:
Noncurrent commodity derivatives	Other assets, non-current	$	0.1		$	—
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current		(0.5	)		(0.7	)
Total derivatives designated as hedges		$	(0.4	)	$	(0.7	)
Derivatives not designated as hedges:
Asset derivative instruments:
Noncurrent commodity derivatives	Other assets, non-current	$	0.2		$	—
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current		(1.2	)		(3.5	)
Total derivatives not designated as hedges		$	(1.0	)	$	(3.5	)

Derivatives Designated as Hedge Instruments

The impact of cash flow hedges on our Consolidated Statements of Comprehensive Income and Consolidated Statements of Income are presented below for the three and six months ended June 30, 2025, and 2024. 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.

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	Three Months Ended June 30,							Three Months Ended June 30,
	2025			2024				2025			2024
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	$	0.8		$	0.7		Interest expense	$	(0.8	)	$	(0.7	)
Commodity derivatives		(0.3	)		0.6		Fuel, purchased power, and cost of natural gas sold		(0.1	)		(0.6	)
Total	$	0.5		$	1.3			$	(0.9	)	$	(1.3	)

	Six Months Ended June 30,							Six Months Ended June 30,
	2025			2024				2025			2024
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	$	1.4		$	1.4		Interest expense	$	(1.4	)	$	(1.4	)
Commodity derivatives		0.3			3.0		Fuel, purchased power, and cost of natural gas sold		(0.6	)		(3.2	)
Total	$	1.7		$	4.4			$	(2.0	)	$	(4.6	)

As of June 30, 2025, $3.0 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 three and six months ended June 30, 2025, and 2024. 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 profit or loss we realized when the underlying physical and financial transactions were settled.

		Three Months Ended June 30,
		2025			2024
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	Fuel, purchased power, and cost of natural gas sold	$	(0.5	)	$	0.1
		$	(0.5	)	$	0.1

		Six Months Ended June 30,
		2025			2024
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	Fuel, purchased power, and cost of natural gas sold	$	0.6		$	0.7
		$	0.6		$	0.7

As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset accounts related to these financial instruments were $1.0 million and $2.9 million as of June 30, 2025 and December 31, 2024, respectively.

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(8)Fair Value Measurements

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.

Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps, and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options, and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable 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. For additional information, see Note 1 of our Notes to the Consolidated Financial Statements in our 2024 Annual Report on Form 10-K.

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 June 30, 2025
	Level 1			Level 2			Level 3			Cash Collateral and Counterparty Netting (a)			Total
	(in millions)
Assets:
Commodity derivatives - Gas Utilities	$	—		$	1.3		$	—		$	(1.0	)	$	0.3
Total	$	—		$	1.3		$	—		$	(1.0	)	$	0.3
Liabilities:
Commodity derivatives - Gas Utilities	$	—		$	1.9		$	—		$	(0.2	)	$	1.7
Total	$	—		$	1.9		$	—		$	(0.2	)	$	1.7

(a)As of June 30, 2025, $1.0 million of our commodity derivative assets and $0.2 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

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	As of December 31, 2024
	Level 1			Level 2			Level 3			Cash Collateral and Counterparty Netting (a)			Total
	(in millions)
Assets:
Commodity derivatives - Gas Utilities	$	—		$	2.2		$	—		$	(2.2	)	$	—
Total	$	—		$	2.2		$	—		$	(2.2	)	$	—
Liabilities:
Commodity derivatives - Gas Utilities	$	—		$	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 assets and $0.6 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

Pension and Postretirement Plan Assets

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 13 to the Consolidated Financial Statements included in our 2024 Annual Report on Form 10-K.

Other Fair Value Measures

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 as of:

	June 30, 2025						December 31, 2024
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(in millions)
Long-term debt, including current maturities (a)	$	4,252.4		$	4,101.2		$	4,250.2		$	4,059.1

(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.

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(9)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:

		Amount Reclassified from AOCI
		Three Months Ended June 30,						Six Months Ended June 30,
	Location on the Consolidated Statements of Income	2025			2024			2025			2024
		(in millions)
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(0.8	)	$	(0.7	)	$	(1.4	)	$	(1.4	)
Commodity contracts	Fuel, purchased power, and cost of natural gas sold		(0.1	)		(0.6	)		(0.6	)		(3.2	)
		$	(0.9	)	$	(1.3	)	$	(2.0	)	$	(4.6	)
Income tax	Income tax expense		0.2			0.3			0.5			1.0
Total reclassification adjustments related to cash flow hedges, net of tax		$	(0.7	)	$	(1.0	)	$	(1.5	)	$	(3.6	)
Amortization of components of defined benefit plans:
Actuarial (loss)	Operations and maintenance		—			—			(0.1	)		(0.1	)
Total reclassification adjustments related to defined benefit plans, net of tax		$	—		$	—		$	(0.1	)	$	(0.1	)
Total reclassifications		$	(0.7	)	$	(1.0	)	$	(1.6	)	$	(3.7	)

Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows:

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
	(in millions)
As of December 31, 2024	$	(3.8	)	$	(0.3	)	$	(5.3	)	$	(9.4	)
Other comprehensive income (loss) before reclassifications		—			(0.2	)		—			(0.2	)
Amounts reclassified from AOCI		1.1			0.4			0.1			1.6
As of June 30, 2025	$	(2.7	)	$	(0.1	)	$	(5.2	)	$	(8.0	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
	(in millions)
As of December 31, 2023	$	(6.1	)	$	(2.5	)	$	(6.2	)	$	(14.8	)
Other comprehensive income (loss) before reclassifications		—			(0.2	)		—			(0.2	)
Amounts reclassified from AOCI		1.1			2.5			0.1			3.7
As of June 30, 2024	$	(5.0	)	$	(0.2	)	$	(6.1	)	$	(11.3	)

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(10)Employee Benefit Plans

Components of Net Periodic Expense

The components of net periodic expense were as follows:

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
Three Months Ended June 30,	2025			2024			2025			2024			2025			2024
	(in millions)
Service cost	$	0.4		$	0.6		$	1.5		$	0.7		$	0.4		$	0.4
Interest cost		4.0			4.1			0.3			0.3			0.6			0.6
Expected return on plan assets		(4.2	)		(4.5	)		—			—			(0.1	)		(0.1	)
Net amortization of prior service costs		—			—			—			—			0.1			0.1
Recognized net actuarial loss		0.5			0.5			—			—			—			—
Net periodic expense	$	0.7		$	0.7		$	1.8		$	1.0		$	1.0		$	1.0

	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
Six Months Ended June 30,	2025			2024			2025			2024			2025			2024
	(in millions)
Service cost	$	0.8		$	1.1		$	1.6		$	1.6		$	0.7		$	0.8
Interest cost		8.0			8.2			0.7			0.7			1.2			1.2
Expected return on plan assets		(8.5	)		(9.0	)		—			—			(0.1	)		(0.1	)
Net amortization of prior service costs		—			—			—			—			0.1			0.1
Recognized net actuarial loss		1.1			1.0			—			—			—			—
Net periodic expense	$	1.4		$	1.3		$	2.3		$	2.3		$	1.9		$	2.0

Plan Contributions

Contributions made in the first six months of 2025 and anticipated contributions for 2025 are as follows:

	Contributions Made			Additional Contributions
	Six Months Ended June 30, 2025			Anticipated for 2025
	(in millions)
Defined Benefit Pension Plan	$	1.8		$	—
Non-pension Defined Benefit Postretirement Healthcare Plan		2.3			2.3
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans		1.4			1.4

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(11)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 January 2025, under this transferability provision, we entered into an 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.

One Big Beautiful Bill Act

On July 4, 2025, President Trump signed H.R. 1, commonly referred to as the OBBBA, a legislative package designed to permanently extend certain expiring provisions of the TCJA and deliver additional tax relief for individuals and businesses. The OBBBA introduced changes to federal energy policies by rolling back several clean energy provisions and codified restrictions related to prohibited foreign entities, termination and restrictions on clean energy PTCs, and extension and modification of clean fuel production. The OBBBA does not repeal tax credit transferability provisions enacted under the IRA and continues to permit the execution of our transferability agreements as originally agreed upon, but restricts credit transfers to prohibited foreign entities. Additionally, on July 7, 2025, President Trump issued Executive Order 14315, which relates to the implementation of such changes to energy tax credits. Further clarity is expected from the Secretaries of the Treasury and the Interior as it relates to their findings and actions taken under Executive Order 14315 within 45 days. We are currently evaluating the provisions of the OBBBA and Executive Order 14315 on our consolidated financial statements but we do not anticipate impacts to our clean energy generation facilities already in service or the execution of Colorado Electric's Clean Energy Plan.

Income Tax (Expense) and Effective Tax Rates

Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024

Income tax (expense) for the three months ended June 30, 2025, was $(4.4) million compared to $(3.7) million reported for the same period in 2024. For the three months ended June 30, 2025, the effective tax rate was 13.3%, which was comparable to 13.0% for the same period in 2024.

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024

Income tax (expense) for the six months ended June 30, 2025, was $(22.5) million compared to $(20.6) million reported for the same period in 2024. For the six months ended June 30, 2025, the effective tax rate was 12.0%, which was comparable to 11.7% for the same period in 2024.

(12)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.

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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
Three Months Ended June 30, 2025	Electric Utilities			Gas Utilities			Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	217.5		$	221.5		$	—		$	439.0
Inter-segment		2.4			1.5			(3.9	)		—
Total revenue		219.9			223.0			(3.9	)		439.0
Fuel, purchased power and cost of natural gas sold		55.3			68.9			(0.2	)		124.0
Operations and maintenance (a) -
Direct		36.1			38.9			(1.7	)		73.3
Allocated		33.1			41.2			—			74.3
Depreciation and amortization		37.5			32.3			—			69.8
Taxes other than income taxes		8.9			6.2			—			15.1
Operating income (loss)	$	49.0		$	35.5		$	(2.0	)	$	82.5
Interest expense, net											(48.9	)
Other income (expense), net											(0.4	)
Income tax (expense)											(4.4	)
Net income											28.8
Net income attributable to non-controlling interest											(1.3	)
Net income available for common stock										$	27.5

	Consolidating Income Statement
Three Months Ended June 30, 2024	Electric Utilities			Gas Utilities			Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	202.1		$	200.5		$	—		$	402.6
Inter-segment		3.0			1.5			(4.5	)		—
Total revenue		205.1			202.0			(4.5	)		402.6
Fuel, purchased power and cost of natural gas sold		45.9			61.3			(0.1	)		107.1
Operations and maintenance (a) -
Direct		37.4			38.2			(5.7	)		69.9
Allocated		30.7			41.1			—			71.8
Depreciation and amortization		35.5			31.1			—			66.6
Taxes other than income taxes		9.3			7.3			—			16.6
Operating income	$	46.3		$	23.0		$	1.3		$	70.6
Interest expense, net											(42.6	)
Other income (expense), net											0.4
Income tax (expense)											(3.7	)
Net income											24.7
Net income attributable to non-controlling interest											(1.9	)
Net income available for common stock										$	22.8

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	Consolidating Income Statement
Six Months Ended June 30, 2025	Electric Utilities			Gas Utilities			Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	451.8		$	792.4		$	—		$	1,244.2
Inter-segment		4.8			3.0			(7.8	)		—
Total revenue		456.6			795.4			(7.8	)		1,244.2
Fuel, purchased power and cost of natural gas sold		122.5			361.4			(0.1	)		483.8
Operations and maintenance (a) -
Direct		71.8			83.0			(4.8	)		150.0
Allocated		66.2			85.1			—			151.3
Depreciation and amortization		74.6			64.4			—			139.0
Taxes other than income taxes		18.2			14.5			—			32.7
Operating income (loss)	$	103.3		$	187.0		$	(2.9	)	$	287.4
Interest expense, net											(100.3	)
Other income (expense), net											0.6
Income tax (expense)											(22.5	)
Net income											165.2
Net income attributable to non-controlling interest											(3.5	)
Net income available for common stock										$	161.7

	Consolidating Income Statement
Six Months Ended June 30, 2024	Electric Utilities			Gas Utilities			Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	421.4		$	707.6		$	—		$	1,129.0
Inter-segment		5.9			3.0			(8.9	)		—
Total revenue		427.3			710.6			(8.9	)		1,129.0
Fuel, purchased power and cost of natural gas sold		100.8			323.2			(0.3	)		423.7
Operations and maintenance (a) -
Direct		64.8			76.3			(8.2	)		132.9
Allocated		60.7			81.6			—			142.3
Depreciation and amortization		70.8			61.5			0.2			132.5
Taxes other than income taxes		19.3			14.3			—			33.6
Operating income (loss)	$	110.9		$	153.7		$	(0.6	)	$	264.0
Interest expense, net											(86.7	)
Other income (expense), net											(0.5	)
Income tax (expense)											(20.6	)
Net income											156.2
Net income attributable to non-controlling interest											(5.6	)
Net income available for common stock										$	150.6

(a)Direct and Allocated Operations and maintenance expenses for our operating segments are regularly provided to the CODM. Direct Operations and maintenance expense represents the costs incurred directly by our operating segments. Allocated Operations and maintenance expense 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 the Public Utility Holding Company Act of 2005.

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Capital Expenditures (a) for the six months ended June 30,	2025			2024
	(in millions)
Electric Utilities	$	211.8		$	185.6
Gas Utilities		153.8			190.4
Corporate and Other		4.3			4.8
Total capital expenditures	$	369.9		$	380.8

(a)Includes accruals for property, plant, and equipment as disclosed in supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements. Capital expenditures are presented net of CIACs in the Consolidated Statements of Cash Flows.

(13)Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

Following is a summary of Accounts receivable, net included in the accompanying Consolidated Balance Sheets as of:

	June 30, 2025			December 31, 2024
	(in millions)
Billed Accounts Receivable	$	180.9		$	201.5
Unbilled Revenue		83.6			151.8
Less: Allowance for Credit Losses		(3.7	)		(2.1	)
Account Receivable, net	$	260.8		$	351.2

Changes to allowance for credit losses for the six months ended June 30, 2025 and 2024, respectively, were as follows:

	Balance at Beginning of Year			Additions Charged to Costs and Expenses			Recoveries and Other Additions			Write-offs and Other Deductions			Balance at June 30,
	(in millions)
2025	$	2.1		$	4.4		$	1.6		$	(4.4	)	$	3.7
2024	$	2.2		$	2.7		$	1.8		$	(3.6	)	$	3.1

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:

	June 30, 2025			December 31, 2024
	(in millions)
Materials and supplies	$	113.4		$	106.1
Fuel - Electric Utilities		6.7			7.5
Natural gas in storage		25.1			40.3
Total materials, supplies, and fuel	$	145.2		$	153.9

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of:

	June 30, 2025			December 31, 2024
	(in millions)
Accrued employee compensation, benefits, and withholdings	$	73.1		$	85.5
Accrued property taxes		43.2			54.7
Customer deposits and prepayments		44.7			55.6
Accrued interest		52.3			56.4
Other (none of which is individually significant)		37.8			50.0
Total accrued liabilities	$	251.1		$	302.2

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(14)Subsequent Events

Except as described in Notes 2 and 11, there have been no events subsequent to June 30, 2025, which would require recognition in the Consolidated Financial Statements or disclosures.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in our 2024 Annual Report on Form 10-K

Executive Summary

We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for more than 1.35 million customers and 800+ communities we serve. Our aspiration is to be the trusted energy partner across our growing eight-state footprint, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming. Our strategy is centered on four priorities: People & Culture—build a team that wins together, Operational Excellence—relentlessly deliver on our commitment to serve our customers, Transformation—be a simple and connected company and Growth—grow to be a dominant long-term energy provider.

We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We consider ourselves a domestic electric and natural gas utility company.

We have provided energy and served customers for 141 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations.

Recent Developments

One Big Beautiful Bill Act

On July 4, 2025, the OBBBA was enacted and on July 7, 2025, President Trump issued Executive Order 14315. See Note 11 of the Condensed Notes to Consolidated Financial Statements for further discussion surrounding the OBBBA and Executive Order 14315.

Trade Tariffs

Trade tariffs were recently enacted and proposed to be enacted through presidential executive orders affecting products exported by several U.S. trading partners. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect with the possibility of additional tariffs being imposed. We are currently unable to predict the impact that recently imposed and possible future tariffs may have on our business. Trade tariffs have not had a material impact on our operations or financial performance to date. We are closely monitoring the impacts of trade tariffs and the potential effect they may have on our financial position, results of operations, or cash flows.

Business Segment Recent Developments

Electric Utilities

•See Note 2 of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for Colorado Electric.

•On March 6, 2025, the state of Wyoming enacted comprehensive wildfire mitigation legislation (HB0192), effective July 1, 2025. The legislation provides material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. The legislation provides a utility a presumption of meeting an appropriate level of operating care for compliance with an approved wildfire mitigation plan. We plan to file our wildfire mitigation plan with the WPSC in the second half of 2025.

•In 2024, we published our first formal WMP, which is an overview of our three-layered approach to manage wildfire risks driven by asset-based risk assessments that include asset programs, integrity programs and operational response. On June 30, 2025, we established our Emergency PSPS program across all three of our electric utilities to promote customer safety and mitigate wildfire risk. In establishing the Emergency PSPS program, we engaged with wildfire experts and key stakeholders including customers, community and local agencies, regulators and community leaders.

•In the first half of 2025, Wyoming Electric set four new all-time peak loads, including an all-time peak of 379 MW on June 20, 2025. Prior to 2025, the previous all-time peak was 314 MW set on January 11, 2024.

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•During the second quarter of 2025, Colorado Electric continued to advance the addition of 350 MW of new renewable generation resources in support of its Clean Energy Plan. In 2024, the CPUC approved the addition of a 100-MW utility-owned solar project, 50-MW utility-owned battery storage project and a 200-MW solar PPA. On June 12, 2025, Colorado Electric filed a CPCN for the battery storage project and expects a CPUC decision by year-end 2025. Negotiations with counterparties for the other two projects are ongoing, which will drive final cost and timing of projects.

•On March 28, 2025, South Dakota Electric filed a request with the WPSC for the Lange II project, which was approved in June 2025. The new facility is scheduled to begin construction in the third quarter of 2025 and to be in service by the second half of 2026.

•During the second quarter of 2025, Wyoming Electric continued construction of its approximately 260-mile, $350 million Ready Wyoming electric transmission expansion project. The project is on track to be completed and in service by year end 2025.

Gas Utilities

•See Note 2 of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for Iowa Gas, Kansas Gas and Nebraska Gas.

Corporate and Other

•See Note 5 of the Condensed Notes to Consolidated Financial Statements for our corporate Revolving Credit Facility and ATM program activity.

•During the second quarter of 2025, we published our 2024 Corporate Sustainability, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals.

•On January 17, 2025, Fitch affirmed BHC's long-term issuer rating at BBB+ with a negative outlook. Following the affirmation, the parties jointly withdrew the rating. See Liquidity and Capital Resources section below for additional information on our credit ratings.

Results of Operations

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2025, and 2024, and our financial condition as of June 30, 2025, and December 31, 2024, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

All amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.

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Consolidated Summary and Overview

	Three Months Ended June 30,									Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions, except per share amounts)
Operating income (loss):
Electric Utilities	$	49.0		$	46.3		$	2.7		$	103.3		$	110.9		$	(7.6	)
Gas Utilities		35.5			23.0			12.5			187.0			153.7			33.3
Corporate and Other (a)		(2.0	)		1.3			(3.3	)		(2.9	)		(0.6	)		(2.3	)
Operating income		82.5			70.6			11.9			287.4			264.0			23.4
Interest expense, net		(48.9	)		(42.6	)		(6.3	)		(100.3	)		(86.7	)		(13.6	)
Other income (expense), net		(0.4	)		0.4			(0.8	)		0.6			(0.5	)		1.1
Income tax (expense)		(4.4	)		(3.7	)		(0.7	)		(22.5	)		(20.6	)		(1.9	)
Net income		28.8			24.7			4.1			165.2			156.2			9.0
Net income attributable to non-controlling interest		(1.3	)		(1.9	)		0.6			(3.5	)		(5.6	)		2.1
Net income available for common stock	$	27.5		$	22.8		$	4.7		$	161.7		$	150.6		$	11.1
Weighted average common shares outstanding, Diluted		72.4			69.0			3.4			72.1			68.7			3.4
Total earnings per share of common stock, Diluted	$	0.38		$	0.33		$	0.05		$	2.24		$	2.19		$	0.05

(a)Includes inter-segment eliminations.

Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024

The variance to the prior year included the following:

•Electric Utilities' operating income increased $2.7 million primarily due to new rates and rider recovery partially offset by higher operating expenses;

•Gas Utilities' operating income increased $12.5 million primarily due to new rates and rider recovery driven by the Arkansas Gas and Iowa Gas rate reviews and favorable weather;

•Corporate and Other operating loss increased $3.3 million primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses; and

•Interest expense increased $6.3 million primarily due to higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances.

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:

The variance to the prior year included the following:

•Electric Utilities’ operating income decreased $7.6 million primarily due to higher operating expenses and current year unplanned generation outages partially offset by new rates and rider recovery;

•Gas Utilities’ operating income increased $33.3 million primarily due to new rates and rider recovery driven by the Arkansas Gas, Iowa Gas and Colorado Gas rate reviews and favorable weather partially offset by higher operating expenses;

•Corporate and Other operating loss increased $2.3 million primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses;

•Interest expense increased $13.6 million primarily due to higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances; and

•Net income attributable to non-controlling interest decreased $2.1 million due to lower net income from Black Hills Colorado IPP primarily driven by current year unplanned generation outages.

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Segment Operating Results

A discussion of operating results from our business segments follows. Unless otherwise indicated, segment information does not include inter-segment eliminations.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP and a “non-GAAP financial measure", Electric and Gas Utility margin. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Electric and Gas Utility margin as operating revenue less cost of fuel, purchased power and cost of natural gas sold. Electric and Gas Utility margin is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses determined to be directly attributable to revenue-producing activities, depreciation and amortization expenses, and taxes other than income taxes from the measure.

We believe that Gas and Electric Utility margin provides a useful basis for evaluating our segment operating results since our Utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer in current rates. As a result, management uses Gas and Electric Utility margin internally when assessing the financial performance of our operating segments as this measure excludes the majority of revenue fluctuations caused by changes in these costs of energy. Similarly, the presentation of Gas and Electric Utility margin is intended to supplement investors’ understanding of operating performance.

Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures. The following table includes a reconciliation of Electric and Gas Utility margin to Gross margin, the most directly comparable GAAP measure:

	Electric Utilities												Gas Utilities
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
	2025			2024			2025			2024			2025			2024			2025			2024
	(in millions)
Revenue	$	219.9		$	205.1		$	456.6		$	427.3		$	223.0		$	202.0		$	795.4		$	710.6
Fuel, purchased power and cost of natural gas sold		(55.3	)		(45.9	)		(122.5	)		(100.8	)		(68.9	)		(61.3	)		(361.4	)		(323.2	)
Operations and maintenance (a)		(43.8	)		(42.5	)		(85.7	)		(78.5	)		(40.7	)		(42.3	)		(86.9	)		(85.1	)
Depreciation and amortization		(37.5	)		(35.5	)		(74.6	)		(70.8	)		(32.3	)		(31.1	)		(64.4	)		(61.5	)
Taxes other than income taxes		(8.9	)		(9.3	)		(18.2	)		(19.3	)		(6.2	)		(7.3	)		(14.5	)		(14.3	)
Gross margin (GAAP)	$	74.4		$	71.9		$	155.6		$	157.9		$	74.9		$	60.0		$	268.2		$	226.5
Operations and maintenance (a)		43.8			42.5			85.7			78.5			40.7			42.3			86.9			85.1
Depreciation and amortization		37.5			35.5			74.6			70.8			32.3			31.1			64.4			61.5
Taxes other than income taxes		8.9			9.3			18.2			19.3			6.2			7.3			14.5			14.3
Electric and Gas Utility margin (non-GAAP)	$	164.6		$	159.2		$	334.1		$	326.5		$	154.1		$	140.7		$	434.0		$	387.4

(a)Operations and maintenance expenses which are deemed to be directly attributable to revenue-producing activities include plant operations and maintenance expenses at our electric generation facilities, operations and maintenance expenses at our WRDC coal mine, and electric and gas transmission and distribution expenses. These amounts are included in the table above to calculate gross margin in accordance with GAAP. These amounts excluded operations and maintenance expenses not directly attributable to revenue-producing activities of $25.4 million, $25.6 million, 52.3 million, and $47.0 million for the three and six months ended June 30, 2025 and 2024, respectively, for the Electric Utilities and $39.4, $37.0, $81.2 million, and $72.8 million for the three and six months ended June 30, 2025 and 2024, respectively, for the Gas Utilities.

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Electric Utilities

Operating results for the Electric Utilities were as follows:

	Three Months Ended June 30,									Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions)
Revenue	$	219.9		$	205.1		$	14.8		$	456.6		$	427.3		$	29.3
Fuel and purchased power		55.3			45.9			9.4			122.5			100.8			21.7
Electric Utility margin (non-GAAP) (a)		164.6			159.2			5.4			334.1			326.5			7.6
Operations and maintenance		69.2			68.1			1.1			138.0			125.5			12.5
Depreciation and amortization		37.5			35.5			2.0			74.6			70.8			3.8
Taxes other than income taxes		8.9			9.3			(0.4	)		18.2			19.3			(1.1	)
		115.6			112.9			2.7			230.8			215.6			15.2
Operating income	$	49.0		$	46.3		$	2.7		$	103.3		$	110.9		$	(7.6	)

(a)See Non-GAAP Financial Measures section above for reconciliation to Gross margin, the most directly comparable GAAP measure.

Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:

Electric Utility margin increased as a result of the following:

	(in millions)
New rates and rider recovery	$	5.0
Weather		(0.8	)
Other		1.2
	$	5.4

Operations and maintenance expense was comparable to the same period in the prior year.

Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.

Taxes other than income taxes was comparable to the same period in the prior year.

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:

Electric Utility margin increased as a result of the following:

	(in millions)
New rates and rider recovery	$	6.8
Retail customer growth and usage		3.0
Weather		0.4
Off-system excess energy sales		(0.8	)
Other		(1.8	)
	$	7.6

Operations and maintenance expense increased primarily due to $5.3 million of expenses related to unplanned generation outages, $4.1 million of higher outside services expenses and $2.3 million of higher insurance expense.

Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.

Taxes other than income taxes was comparable to the same period in the prior year.

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Operating Statistics

	Revenue												Quantities Sold
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
By Customer Class	2025			2024			2025			2024			2025			2024			2025			2024
	(in millions)												(in GWh)
Retail Revenue -
Residential	$	54.1		$	50.8		$	120.5		$	113.3			321.0			323.5			727.4			712.3
Commercial		66.9			63.3			135.7			129.2			499.7			506.9			1,016.9			1,018.7
Industrial (a)		49.3			41.7			97.5			85.2			663.9			558.3			1,273.7			1,111.9
Municipal		4.3			4.1			8.8			8.4			34.1			36.1			68.7			70.3
Other Retail		3.5			3.5			6.9			7.0			—			—			—			—
Subtotal Retail Revenue - Electric		178.1			163.4			369.4			343.1			1,518.7			1,424.8			3,086.7			2,913.2
Wholesale		4.2			6.5			11.3			15.0			108.4			158.7			256.2			334.7
Market - off-system sales		10.7			5.5			22.0			12.1			220.0			164.2			393.6			279.8
Transmission		10.1			12.9			22.2			25.5			—			—			—			—
Other (b)		16.8			16.8			31.7			31.6			—			—			—			—
Total Revenue and Quantities Sold	$	219.9		$	205.1		$	456.6		$	427.3		$	1,847.1		$	1,747.7			3,736.5			3,527.7
Other Uses, Losses, or Generation, net (c)														125.4			25.1			219.5			126.9
Total Energy														1,972.5			1,772.8			3,956.0			3,654.6

(a)The increase in industrial revenues and quantities sold for the three and six months ended June 30, 2025, compared to the same periods in 2024, was primarily driven by Wyoming Electric LPCS Tariff and BCIS Tariff customers.

(b)Includes Integrated Generation, inter-segment rent, and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.

(c)Includes company uses and line losses.

	Revenue												Quantities Sold
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
By Business Unit	2025			2024			2025			2024			2025			2024			2025			2024
	(in millions)												(in GWh)
Colorado Electric	$	66.3		$	64.1		$	138.7		$	133.8			524.1			585.7			1,056.4			1,141.4
South Dakota Electric		78.0			75.9			164.9			156.5			638.9			591.4			1,320.9			1,212.5
Wyoming Electric		64.8			55.6			131.4			116.4			665.2			549.5			1,311.0			1,124.7
Integrated Generation		10.8			9.5			21.6			20.6			18.9			21.1			48.2			49.1
Total Revenue and Quantities Sold	$	219.9		$	205.1		$	456.6		$	427.3			1,847.1			1,747.7			3,736.5			3,527.7

	Three Months Ended June 30,						Six Months Ended June 30,
Quantities Generated and Purchased by Fuel Type	2025			2024			2025			2024
	(in GWh)
Generated:
Coal (a)		457.4			478.1			1,057.3			1,158.8
Natural Gas and Oil (b)		585.3			451.5			1,097.4			974.9
Wind		135.4			161.7			310.8			335.7
Total Generated		1,178.1			1,091.3			2,465.5			2,469.4
Purchased:
Coal, Natural Gas, Oil, and Other Market Purchases		470.8			350.6			846.5			639.5
Wind and Solar		323.6			330.9			644.0			545.7
Total Purchased (c)		794.4			681.5			1,490.5			1,185.2
Total Generated and Purchased		1,972.5			1,772.8			3,956.0			3,654.6

(a)The decrease in coal generation for the three and six months ended June 30, 2025, compared to the same period in 2024 is primarily due to unplanned outages at Wygen III.

(b)The increase in natural gas and oil generation for the three and six months ended June 30, 2025, compared to the same periods in 2024, was primarily due to the timing and extent of unplanned outages at Pueblo Airport Generation #4-5.

(c)The increase in total purchases for the three and six months ended June 30, 2025, compared to the same periods in 2024, was primarily driven by increased demand from Wyoming Electric LPCS Tariff and BCIS Tariff customers and unplanned outages at Wygen III as discussed in (a) above.
 

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	Three Months Ended June 30,						Six Months Ended June 30,
Quantities Generated and Purchased	2025			2024			2025			2024
	(in GWh)
Generated:
Colorado Electric		183.1			223.0			367.4			384.6
South Dakota Electric (a)		444.9			419.8			923.8			954.4
Wyoming Electric		220.1			187.8			439.4			403.0
Integrated Generation		330.0			260.7			734.9			727.4
Total Generated		1,178.1			1,091.3			2,465.5			2,469.4
Purchased:
Colorado Electric		106.5			172.7			196.7			262.9
South Dakota Electric (a)		232.6			163.0			443.9			263.6
Wyoming Electric (b)		439.7			329.8			815.8			625.5
Integrated Generation		15.6			16.0			34.1			33.2
Total Purchased		794.4			681.5			1,490.5			1,185.2
Total Generated and Purchased		1,972.5			1,772.8			3,956.0			3,654.6

(a)The shift in South Dakota Electric's generated and purchased GWh for the six months ended June 30, 2025, compared to the same period in 2024 is primarily driven by unplanned outages at Wygen III.

(b)As discussed in footnote (c) in the Quantities Generated and Purchased by Fuel Type table above, the increase in Wyoming Electric's purchases is primarily driven by increased demand from LPCS Tariff and BCIS Tariff customers.

	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Degree Days	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	623	5%	524	(12)%	3,356	8%	3,031	(7)%
South Dakota Electric	908	(12)%	898	(15)%	4,346	1%	4,032	(10)%
Wyoming Electric	1,085	(5)%	1,040	(10)%	4,225	2%	4,026	(7)%
Combined (a)	815	(5)%	757	(13)%	3,875	4%	3,577	(8)%
Cooling Degree Days:
Colorado Electric	235	(16)%	343	25%	235	(16)%	343	25%
South Dakota Electric	162	41%	114	8%	162	41%	114	8%
Wyoming Electric	60	(24)%	118	75%	60	(24)%	118	75%
Combined (a)	174	(4)%	219	25%	174	(4)%	219	25%

(a)Degree days are calculated based on a weighted average of total customers by state.

	Three Months Ended June 30,		Six Months Ended June 30,
Contracted generating facilities Availability(a) by fuel type	2025	2024	2025	2024
Coal	79.4%	75.5%	82.7%	85.6%
Natural gas and diesel oil	93.2%	91.6%	92.4%	94.1%
Wind	78.6%	92.1%	82.4%	91.2%
Total Availability (b)	87.2%	87.1%	88.1%	91.3%
Wind Capacity Factor (a)	31.1%	36.9%	35.5%	38.4%

(a)Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.

(b)2025 included unplanned outages at Wygen III, Pueblo Airport Generation #4-5 and Busch Ranch I and II. 2024 included unplanned outages at Wygen I and Pueblo Airport Generation #4-5.

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Gas Utilities

Operating results for the Gas Utilities were as follows:

	Three Months Ended June 30,									Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions)
Revenue	$	223.0		$	202.0		$	21.0		$	795.4		$	710.6		$	84.8
Cost of natural gas sold		68.9			61.3			7.6			361.4			323.2			38.2
Gas Utility margin (non-GAAP) (a)		154.1			140.7			13.4			434.0			387.4			46.6
Operations and maintenance		80.1			79.3			0.8			168.1			157.9			10.2
Depreciation and amortization		32.3			31.1			1.2			64.4			61.5			2.9
Taxes other than income taxes		6.2			7.3			(1.1	)		14.5			14.3			0.2
		118.6			117.7			0.9			247.0			233.7			13.3
Operating income	$	35.5		$	23.0		$	12.5		$	187.0		$	153.7		$	33.3

(a)See Non-GAAP Financial Measures section above for reconciliation to Gross margin, the most directly comparable GAAP measure.

Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:

Gas Utility margin increased as a result of the following:

	(in millions)
New rates and rider recovery	$	9.9
Weather		3.3
Mark-to-market on non-utility natural gas commodity contracts		(0.6	)
Other		0.8
	$	13.4

Operations and maintenance expense was comparable to the same period in the prior year.

Depreciation and amortization was comparable to the same period in the prior year.

Taxes other than income taxes was comparable to the same period in the prior year.

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:

Gas Utility margin increased as a result of the following:

	(in millions)
New rates and rider recovery	$	36.7
Weather		12.0
Other		(2.1	)
	$	46.6

Operations and maintenance expense increased primarily due to $4.4 million of higher employee related expenses, $3.6 million of higher insurance expense, and $1.5 million of higher bad debt expense driven by increased revenues and lower prior year write-offs.

Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.

Taxes other than income taxes was comparable to the same period in the prior year.

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Operating Statistics

	Revenue												Quantities Sold and Transported
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
By Customer Class	2025			2024			2025			2024			2025			2024			2025			2024
	(in millions)												(Dth in millions)
Retail Revenue -
Residential	$	113.3		$	102.6		$	457.4		$	400.4			7.2			6.9			37.9			34.7
Commercial		42.0			38.2			176.3			156.7			4.0			3.9			18.0			16.9
Industrial		6.4			5.8			13.0			10.9			1.4			1.8			2.4			2.7
Other Retail (a)		6.9			6.4			21.6			22.4			—			—			—			—
Subtotal Retail Revenue - Gas		168.6			153.0			668.3			590.4			12.6			12.6			58.3			54.3
Transportation		42.1			36.0			99.8			87.6			36.2			34.5			86.7			81.2
Other (b)		12.3			13.0			27.3			32.6			—			—			—			—
Total Revenue and Quantities Sold	$	223.0		$	202.0		$	795.4		$	710.6			48.8			47.1			145.0			135.5

(a)Includes Black Hills Energy Services revenue under the Choice Gas Program.

(b)Includes inter-segment rent and non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe.

	Revenue												Quantities Sold and Transported
	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
By Business Unit	2025			2024			2025			2024			2025			2024			2025			2024
	(in millions)												(Dth in millions)
Arkansas Gas	$	40.7		$	31.2		$	165.5		$	141.8			5.3			5.0			18.5			17.0
Colorado Gas		39.0			42.3			154.8			160.0			5.2			5.1			18.4			18.0
Iowa Gas		30.1			27.6			116.9			89.4			6.9			7.1			22.1			20.6
Kansas Gas		25.1			20.9			91.2			71.2			7.6			7.9			19.3			17.6
Nebraska Gas		57.9			50.4			188.1			164.7			16.4			14.5			46.1			41.6
Wyoming Gas		30.2			29.6			78.9			83.5			7.4			7.5			20.6			20.7
Total Revenue and Quantities Sold	$	223.0		$	202.0		$	795.4		$	710.6			48.8			47.1			145.0			135.5

	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	193	(33)%	144	(54)%	2,150	(2)%	1,916	(17)%
Colorado Gas	822	(5)%	790	(9)%	3,659	---	3,533	(5)%
Iowa Gas	640	(5)%	507	(27)%	3,928	(1)%	3,405	(18)%
Kansas Gas (a)	367	(9)%	266	(37)%	2,983	7%	2,557	(11)%
Nebraska Gas	553	(9)%	457	(26)%	3,592	---	3,259	(12)%
Wyoming Gas	1,110	(7)%	1,096	(9)%	4,433	1%	4,252	(5)%
Combined (b)	658	(8)%	587	(20)%	3,740	---	3,452	(10)%

(a)Arkansas Gas and Kansas Gas have weather normalization mechanisms that mitigate the weather impact on revenue.

(b)The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

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Corporate and Other

Corporate and Other operating results, including inter-segment eliminations, were as follows:

	Three Months Ended June 30,									Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions)
Operating income (loss)	$	(2.0	)	$	1.3		$	(3.3	)	$	(2.9	)	$	(0.6	)	$	(2.3	)

Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:

Operating loss increased primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses.

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:

Operating loss increased primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses.

Consolidated Interest Expense, Other Income and Income Tax Expense

	Three Months Ended June 30,									Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions)
Interest expense, net	$	(48.9	)	$	(42.6	)	$	(6.3	)	$	(100.3	)	$	(86.7	)	$	(13.6	)
Other income (expense), net		(0.4	)		0.4			(0.8	)		0.6			(0.5	)		1.1
Income tax (expense)		(4.4	)		(3.7	)		(0.7	)		(22.5	)		(20.6	)		(1.9	)

Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:

Interest expense, net increased primarily due to higher interest rates on long-term debt, higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances.

Other income (expense), net was comparable to the same period in the prior year.

Income tax (expense) was comparable to the same period in the prior year. For the three months ended June 30, 2025, the effective tax rate was 13.3%, which was comparable to 13.0% for the same period in 2024.

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:

Interest expense, net increased primarily due to higher interest rates on long-term debt, higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances.

Other income (expense), net was comparable to the same period in the prior year.

Income tax (expense) was comparable to the same period in the prior year. For the six months ended June 30, 2025, the effective tax rate was 12.0%, which was comparable to 11.7% for the same period in 2024.

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Liquidity and Capital Resources

The following table provides an informational summary of our liquidity and capital structure as of:

	June 30, 2025			December 31, 2024
	(dollars in millions)
Cash and cash equivalents	$	8.1		$	16.1
Available capacity under Revolving Credit Facility and CP Program (a)		622.8			612.7
Available liquidity	$	630.9		$	628.8
Capital structure
Short-term debt (b)	$	423.7		$	133.8
Long-term debt		3,952.4			4,250.2
Total debt		4,376.1			4,384.0
Total stockholders' equity (excludes non-controlling interest)		3,636.1			3,501.5
Total capitalization	$	8,012.2		$	7,885.5
Debt to capitalization		54.6	%		55.6	%
Long-term debt to total debt		90.3	%		96.9	%

(a)Available capacity under Revolving Credit Facility and CP Program represents $750 million of total borrowing capacity less outstanding borrowings and letters of credit. See Note 5 of the Notes to Consolidated Financial Statements for more information.

(b)Short-term debt includes our $300 million, 3.95% senior unsecured notes due January 2026.

Future Financing Plans

We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, and the issuance of common stock under our ATM or in a secondary offering. We plan to re-finance our $300 million, 3.95%, senior unsecured notes due January 2026, at or before maturity date.

CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the six months ended June 30, 2025:

Operating Activities:

	Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Net income	$	165.2		$	156.2		$	9.0
Non-cash adjustments to Net income		195.0			181.6			13.4
Total earnings	$	360.2		$	337.8		$	22.4
Changes in certain operating assets and liabilities:
Materials, supplies and fuel, Accounts receivable and other current assets		93.2			146.1			(52.9	)
Accounts payable and other current liabilities		(93.3	)		(77.4	)		(15.9	)
Regulatory assets		57.9			69.8			(11.9	)
Net inflow (outflow) from changes in certain operating assets and liabilities	$	57.8		$	138.5		$	(80.7	)
Other operating activities		(1.6	)		(12.3	)		10.7
Net cash provided by operating activities	$	416.4		$	464.0		$	(47.6	)

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024

Net cash provided by operating activities was $47.6 million lower than the same period in 2024. The variance to the prior year was primarily attributable to:

•Total earnings (net income plus non-cash adjustments) were $22.4 million higher for the six months ended June 30, 2025, compared to the same period in the prior year primarily as a result of increased Electric and Gas Utility margins due to new rates and rider recovery partially offset by higher operating expenses and higher financing costs.

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•Net inflows from changes in certain operating assets and liabilities were $80.7 million lower, primarily attributable to:

oCash inflows decreased by approximately $52.9 million as a result of changes in accounts receivable and other current assets primarily driven by fluctuations in commodity prices;

oCash outflows increased by approximately $15.9 million as a result of increases in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, remediation costs for our manufactured gas plant site in Iowa and changes in other working capital requirements; and

oCash inflows decreased by approximately $11.9 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of our Winter Storm Uri regulatory asset as recovery is now complete in several of our jurisdictions.

•Cash outflows decreased $10.7 million from other operating activities primarily due to lower costs from cloud computing arrangements.

Investing Activities:

	Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Capital expenditures	$	(371.8	)	$	(342.4	)	$	(29.4	)
Other investing activities		(4.4	)		1.7			(6.1	)
Net cash (used in) investing activities	$	(376.2	)	$	(340.7	)	$	(35.5	)

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024

Net cash used in investing activities was $35.5 million higher than the same period in 2024. The variance to the prior year was primarily attributable to:

•Cash outflows from capital expenditures (which are net of contributions in aid of construction) increased $29.4 million primarily as a result of the Ready Wyoming and Lange II projects and prior year receipts related to contributions in aid of construction for data center projects in Wyoming; and

•Cash outflows increased by $6.1 million for other investing activities primarily due to higher AFUDC debt driven by higher construction work-in-progress balances and prior year proceeds from the sale of a Corporate asset.

Financing Activities:

	Six Months Ended June 30,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Dividends paid on common stock	$	(97.6	)	$	(89.3	)	$	(8.3	)
Common stock issued		65.0			73.0			(8.0	)
Short-term and long-term debt borrowings (repayments), net		(10.1	)		450.0			(460.1	)
Distributions to non-controlling interests		(3.8	)		(10.0	)		6.2
Other financing activities		(1.3	)		(8.3	)		7.0
Net cash provided by (used in) financing activities	$	(47.8	)	$	415.4		$	(463.2	)

Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024

Net cash used in financing activities was $463.2 million higher than the same period in 2024. The variance to the prior year was primarily attributable to:

•Dividends paid on common stock increased $8.3 million due to the increased dividend rate per share and increased number of common shares outstanding;

•Cash inflows decreased $8.0 million due to lower issuances of common stock;

•Net cash outflows increased $460.1 million as a result of net repayment activity under our Revolving Credit Facility and CP Program and prior year proceeds from the May 16, 2024, debt offering;

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•Distributions to non-controlling interests decreased $6.2 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages; and

•Cash outflows decreased $7.0 million from other financing activities primarily due to prior year financing costs from the May 2024 debt offering.

CAPITAL RESOURCES

See Note 5 of the Condensed Notes to Consolidated Financial Statements for recent financing updates and financial covenants information.

CREDIT RATINGS

The following table represents the credit ratings and outlook and risk profile of BHC as of the date of this report:

Rating Agency	Senior Unsecured Rating	Outlook
S&P (a)	BBB+	Stable
Moody's (b)	Baa2	Stable

(a)On May 9, 2024, S&P affirmed BBB+ rating and maintained a Stable outlook.

(b)On March 5, 2025, Moody's affirmed our Baa2 rating and maintained a Stable outlook.

The following table represents the credit rating of South Dakota Electric as of the date of this report:

Rating Agency	Senior Secured Rating
S&P	A

We have not had any triggering events (i.e. an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.

CAPITAL REQUIREMENTS

Capital Expenditures

	Actual (a)		Forecasted (b)
Capital Expenditures by Segment (minor differences may result due to rounding)	Six Months Ended June 30, 2025		2025 (c)			2026			2027			2028			2029
	(in millions)
Electric Utilities	$	212	$	550		$	432		$	383		$	615		$	435
Gas Utilities		154		431			386			412			447			447
Corporate and Other		4		21			41			27			27			27
	$	370	$	1,002		$	859		$	822		$	1,089		$	909

(a)Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements. Capital expenditures are presented net of CIACs in the Consolidated Statements of Cash Flows.

(b)Projects are being evaluated by our segments for timing, cost, and other factors.

(c)Includes actual capital expenditures for the six months ended June 30, 2025.

Common Stock Dividends

Dividends paid on our common stock totaled $97.6 million for the six months ended June 30, 2025, or $0.676 per share. On July 22, 2025, our board of directors declared a quarterly dividend of $0.676 per share payable September 2, 2025, equivalent to an annual dividend of $2.704 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility, and our future business prospects.

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Critical Accounting Estimates

A summary of our critical accounting estimates is included in our 2024 Annual Report on Form 10-K. There were no material changes made as of June 30, 2025.

New Accounting Pronouncements

See Note 1 of the Condensed Notes to Consolidated Financial Statements for a description of recent accounting pronouncements, if any, and our expectation of their impact on our results of operations and financial condition.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to our quantitative and qualitative disclosures about market risk previously disclosed in Item 7A of our 2024 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of June 30, 2025. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, 2025.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2025, there have been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely, to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 3 of the Condensed Notes to Consolidated Financial Statements and Note 3 in Item 8 of our 2024 Annual Report on Form 10-K.

ITEM 1A. RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2024 Annual Report on Form 10-K.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table contains monthly information about our acquisitions of equity securities for the three months ended June 30, 2025:

Period	Total Number of Shares Purchased (a)			Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs			Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
April 1, 2025 - April 30, 2025		1		$	60.83			—			—
May 1, 2025 - May 31, 2025		745			61.50			—			—
June 1, 2025 - June 30, 2025		1			58.44			—			—
Total		747		$	61.49			—			—

(a)Shares were acquired under the share withholding provisions of the Amended and Restated 2015 Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.

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ITEM 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95.

ITEM 5. OTHER INFORMATION

None of our directors or officers adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the three months ended June 30, 2025.

ITEM 6. EXHIBITS

Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated.

Exhibit Number	Description
10.1	First Amendment to Equity Distribution Sales Agreement dated May 8, 2025 among Black Hills Corporation and the Agents, Forward Purchasers and Forward Sellers named therein (Filed as Exhibit 1.1 to the Registrant's Form 8-K filed on May 8, 2025).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
95*	Mine Safety and Health Administration Safety Data.
101.INS*	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents
104*	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

BLACK HILLS CORPORATION

		/s/ Linden R. Evans
		Linden R. Evans, President and
		Chief Executive Officer
		/s/ Kimberly F. Nooney
		Kimberly F. Nooney, Senior Vice President and
		Chief Financial Officer
Dated:	July 31, 2025

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FAQ

How did Black Hills (BKH) perform in Q2 2025?

Revenue rose 9% to $439 M and diluted EPS grew to $0.38 from $0.33 last year.

What new rate increases will impact BKH’s earnings?

Colorado Electric gained a $17.5 M hike effective Mar 2025; Kansas Gas adds $10.8 M from Aug 2025; Nebraska request of $34.9 M is pending.

What is BKH’s current debt position?

Long-term debt stands at $3.95 B with $300 M maturing within 12 months; revolver extended to 2030.

How much did BKH spend on capital projects?

First-half capex totaled $371.8 M, focused on transmission, distribution and generation upgrades.

Did BKH issue any new shares?

Yes, ATM programs added ~1.1 million shares for $84 M in gross proceeds year-to-date.