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10-Q

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 March 31, 2026

☐ 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.

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 ☒

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 May 4, 2026
Common stock, $1.00 par value	76,128,592	shares

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TABLE OF CONTENTS


		Page
Glossary of Terms and Abbreviations		3
Forward-Looking Information		6

PART I. FINANCIAL INFORMATION		7

Item 1.	Financial Statements - unaudited	7
	Consolidated Statements of Income	7
	Consolidated Statements of Comprehensive Income	8
	Consolidated Balance Sheets	9
	Consolidated Statements of Cash Flows	11
	Consolidated Statements of Equity	12
	Condensed Notes to Consolidated Financial Statements	13
	Note 1. Management’s Statement	13
	Note 2. Regulatory Matters	14
	Note 3. Commitments, Contingencies and Guarantees	15
	Note 4. Revenue	16
	Note 5. Financing	16
	Note 6. Earnings Per Share	18
	Note 7. Risk Management and Derivatives	18
	Note 8. Fair Value Measurements	20
	Note 9. Other Comprehensive Income	22
	Note 10. Employee Benefit Plans	23
	Note 11. Income Taxes	24
	Note 12. Business Segment Information	24
	Note 13. Selected Balance Sheet Information	26
	Note 14. Pending Merger with NorthWestern	27
	Note 15. Subsequent Events	27

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	28
	Executive Summary	28
	Recent Developments	28
	Results of Operations	29
	Consolidated Summary and Overview	29
	Non-GAAP Financial Measure	30
	Electric Utilities	31
	Gas Utilities	34
	Corporate and Other	35
	Consolidated Interest Expense, Other Income and Income Tax Expense	35
	Liquidity and Capital Resources	36
	Cash Flow Activities	37
	Capital Resources	38
	Credit Ratings	38
	Capital Requirements	39
	Critical Accounting Estimates	39
	New Accounting Pronouncements	39

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 4.	Controls and Procedures	39

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	40
Item 1A.	Risk Factors	40
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	40
Item 4.	Mine Safety Disclosures	40
Item 5.	Other Information	40
Item 6.	Exhibits	40

Signatures		41

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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)
APSC	Arkansas Public Service Commission
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
BHC	Black Hills Corporation; the Company
BHSC	Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
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 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 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)
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.
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
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.
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.

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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
CPUC	Colorado Public Utilities Commission
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
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.
GW	Gigawatts
GWh	Gigawatt Hours
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.
HSR Act	Hart-Scott-Rodino Antitrust Improvements Act of 1976
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).
IRS	United States Internal Revenue Service
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
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 be in service by 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	Wyoming Electric offers service under the LPCS tariff approved by the Wyoming Public Service Commission. The LPCS Tariff provides a cost-based rate structure for customers with very large electric loads, typically data centers or other high-demand facilities.This Tariff is designed to ensure that service to LPCS customers is fully self-supporting and does not shift costs to other customer classes.
Merger	Merger Sub merging with and into NorthWestern
Merger Agreement	The Agreement and Plan of Merger, dated August 18, 2025, by and among BHC, Merger Sub, and NorthWestern
Merger Sub	River Merger Sub Inc., a Delaware corporation and direct, wholly owned subsidiary of BHC
MMBtu	Million British thermal units
Moody's	Moody's Ratings
MPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
N/A	Not applicable
N/M	Not meaningful

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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).
NorthWestern	NorthWestern Energy Group, Inc., a Delaware corporation
NPSC	Nebraska Public Service Commission
OCI	Other Comprehensive Income
PPA	Power Purchase Agreement
PTC	Production Tax Credit
Ready Wyoming	A 260-mile, multi-phase transmission expansion project in Wyoming which was fully completed and placed in service in 2025. The project provides customers long-term price stability and greater flexibility as power markets develop in the western United States. This project is also expected to enable economic growth in Wyoming, expand access to renewable resources and facilitate additional renewable development across wind- and sun-rich resource areas.
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.
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Service Guard Comfort Plan	Appliance protection plan that provides home appliance repair services through ongoing 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).
SSIR	System Safety and Integrity Rider is a mechanism that allows us to recover the costs associated with certain pipeline safety and integrity investments, including the replacement of higher risk pipe, the improvement of the data management system, and the mitigation of other safety issues identified on our natural gas system.
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
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.
Wildfire Mitigation Plan (WMP)	Our three-layered approach to manage wildfire risks driven by asset-based risk assessments that include asset programs, integrity programs and operational response.
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 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 2025 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;

•

The expected timing and likelihood of completion and our ability to realize the anticipated benefits of the proposed merger with NorthWestern, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed acquisition that could reduce anticipated benefits or give rise to the termination of the merger; 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 March 31,
	2026			2025
	(in millions, except per share amounts)
Revenue	$	780.7		$	805.2

Operating expenses:
Fuel, purchased power and cost of natural gas sold		337.9			359.7
Operations and maintenance		148.0			153.7
Depreciation and amortization		74.8			69.2
Taxes other than income taxes		18.1			17.6
Total operating expenses		578.8			600.2

Operating income		201.9			205.0

Other income (expense):
Interest expense incurred net of amounts capitalized		(53.1	)		(51.7	)
Interest income		1.2			0.4
Other income, net		0.7			0.8
Total other (expense)		(51.2	)		(50.5	)

Income before income taxes		150.7			154.5
Income tax (expense)		(17.6	)		(18.1	)
Net income		133.1			136.4
Net income attributable to non-controlling interest		(2.1	)		(2.1	)
Net income available for common stock	$	131.0		$	134.3

Earnings per share of common stock:
Earnings per share, Basic	$	1.74		$	1.87
Earnings per share, Diluted	$	1.73		$	1.87

Weighted average common shares outstanding:
Basic		75.4			71.6
Diluted		75.6			71.8

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 March 31,
	2026			2025
	(in millions)
Net income	$	133.1		$	136.4

Other comprehensive income (loss), net of tax;
Reclassification of benefit plan liability		0.1			-
Derivative instruments designated as cash flow hedges:
Reclassification of settled/amortized interest rate swaps		0.6			0.6
Unrealized gain on commodity derivatives		0.2			0.1
Reclassification of settled commodity derivatives		1.3			0.3
Other comprehensive income (loss), net of tax		2.2			1.0

Comprehensive income		135.3			137.4
Less: comprehensive income attributable to non-controlling interest		(2.1	)		(2.1	)
Comprehensive income available for common stock	$	133.2		$	135.3

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
	March 31, 2026			December 31, 2025
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	23.6		$	182.8
Restricted cash and equivalents		7.8			7.6
Accounts receivable, net		383.4			389.0
Materials, supplies and fuel		146.8			172.4
Income tax receivable, net		22.6			23.3
Regulatory assets, current		122.6			139.7
Other current assets		81.4			81.1
Total current assets		788.2			995.9

Property, plant and equipment		10,556.4			10,344.9
Less: accumulated depreciation		(2,162.6	)		(2,110.7	)
Total property, plant and equipment, net		8,393.8			8,234.2

Other assets:
Goodwill		1,299.5			1,299.5
Intangible assets, net		5.8			6.4
Regulatory assets, non-current		251.7			255.0
Other assets, non-current		81.0			78.8
Total other assets, non-current		1,638.0			1,639.7

TOTAL ASSETS	$	10,820.0		$	10,869.8

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
	March 31, 2026			December 31, 2025
	(in millions)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	210.8		$	311.7
Accrued liabilities		260.2			322.6
Derivative liabilities, current		1.8			5.8
Regulatory liabilities, current		85.9			99.9
Notes payable		252.2			—
Current maturities of long-term debt		410.0			—
Total current liabilities		1,220.9			740.0

Long-term debt, net of current maturities		3,992.5			4,701.1

Deferred credits and other liabilities:
Deferred income tax liabilities, net		736.6			697.9
Regulatory liabilities, non-current		490.2			488.3
Benefit plan liabilities		121.2			123.4
Other deferred credits and other liabilities		231.7			213.4
Total deferred credits and other liabilities		1,579.7			1,523.0

Commitments, contingencies and guarantees (Note 3)

Equity:
Stockholder's equity -
Common stock $1 par value; 100,000,000 shares authorized; issued 76,174,264 and 75,520,234 shares, respectively		76.2			75.5
Additional paid-in capital		2,459.4			2,417.5
Retained earnings		1,420.8			1,342.9
Treasury stock, at cost - 57,505 and 43,167 shares, respectively		(3.7	)		(2.6	)
Accumulated other comprehensive (loss)		(7.5	)		(9.7	)
Total stockholders' equity		3,945.2			3,823.6
Non-controlling interest		81.7			82.1
Total equity		4,026.9			3,905.7

TOTAL LIABILITIES AND TOTAL EQUITY	$	10,820.0		$	10,869.8

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)	Three Months Ended March 31,
	2026			2025
Operating activities:	(in millions)
Net income	$	133.1		$	136.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		74.8			69.2
Deferred financing cost amortization		2.5			2.4
Stock compensation		3.2			2.6
Deferred income taxes		31.8			33.2
Employee benefit plans		1.6			2.2
Other adjustments		1.4			3.3
Changes in certain operating assets and liabilities:
Materials, supplies and fuel		24.5			25.3
Accounts receivable and other current assets		20.5			(42.6	)
Accounts payable and other current liabilities		(119.3	)		(56.0	)
Regulatory assets		5.4			52.6
Other operating activities, net		(3.3	)		(0.8	)
Net cash provided by operating activities		176.2			227.8

Investing activities:
Property, plant and equipment additions		(267.4	)		(152.9	)
Other investing activities		(2.6	)		(2.3	)
Net cash (used in) investing activities		(270.0	)		(155.2	)

Financing activities:
Dividends paid on common stock		(53.1	)		(48.6	)
Common stock issued		40.7			45.6
Net borrowings (payments) of Revolving Credit Facility and CP Program		252.2			(73.9	)
Long-term debt - repayments		(300.0	)		—
Distributions to non-controlling interests		(2.5	)		(3.8	)
Other financing activities		(2.5	)		(1.2	)
Net cash (used in) financing activities		(65.2	)		(81.9	)

Net change in cash, restricted cash and cash equivalents		(159.0	)		(9.3	)

Cash, restricted cash, and cash equivalents beginning of period		190.4			23.4
Cash, restricted cash, and cash equivalents end of period	$	31.4		$	14.1

Supplemental cash flow information:
Cash (paid) received during the period:
Interest (net of amounts capitalized)	$	(51.1	)	$	(48.8	)
Income taxes, net of transferred tax credits (Note 11)		14.8			15.2
Non-cash investing and financing activities:
Accrued property, plant, and equipment purchases at March 31,		87.7			86.8

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, 2025		75,520,234	$	75.5		43,167	$	(2.6	)	$	2,417.5		$	1,342.9		$	(9.7	)	$	82.1		$	3,905.7
Net income		—		—		—		—			—			131.0			—			2.1			133.1
Other comprehensive income, net of tax		—		—		—		—			—			—			2.2			—			2.2
Dividends on common stock ($0.703 per share)		—		—		—		—			—			(53.1	)		—			—			(53.1	)
Share-based compensation		93,064		0.1		14,338		(1.1	)		1.8			—			—			—			0.8
Issuance of common stock		560,966		0.6		—		—			40.6			—			—			—			41.2
Issuance costs		—		—		—		—			(0.5	)		—			—			—			(0.5	)
Distributions to non-controlling interest		—		—		—		—			—			—			—			(2.5	)		(2.5	)
March 31, 2026		76,174,264	$	76.2		57,505	$	(3.7	)	$	2,459.4		$	1,420.8		$	(7.5	)	$	81.7		$	4,026.9


(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

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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 2025 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 2025 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 March 31, 2026, December 31, 2025, and March 31, 2025, 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

Disaggregation of Income Statement Expenses, ASU 2024-03

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures, and in January 2025, the FASB issued ASU 2025-01, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Clarifying the Effective Date. ASU 2024-03 requires public entities to disclose, in the notes to financial statements, certain costs and expenses, such as purchases of inventory, employee compensation, and costs related to depreciation and amortization. ASU 2024-03, as clarified by ASU 2025-01, is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2027, and subsequent interim periods, with early adoption permitted. We are currently evaluating the impact of these standards on our consolidated financial statement disclosures.

Targeted Improvements to the Accounting for Internal-Use Software, ASU 2025-06

In September 2025, the FASB issued ASU 2025-06, Targeted Improvements to the Accounting for Internal-Use Software, which amends the accounting guidance for internal-use software under ASC 350-40. The amendments are intended to modernize the recognition and capitalization framework to better reflect current software development practices, particularly agile methodologies. ASU 2025-06 is effective for fiscal years beginning after December 15, 2027, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the impact of ASU 2025-06 on our consolidated financial statements and related disclosures.

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(2)

Regulatory Matters

We had the following regulatory assets and liabilities:


	As of			As of
	March 31, 2026			December 31, 2025
	(in millions)
Regulatory assets
Winter Storm Uri	$	24.0		$	50.7
Deferred energy and fuel cost adjustments		90.7			83.3
Deferred gas cost adjustments		8.6			10.2
Gas price derivatives		—			4.6
Deferred taxes on AFUDC		11.0			10.6
Employee benefit plans and related deferred taxes		86.6			87.4
Environmental		13.1			13.1
Loss on reacquired debt		13.7			14.1
Deferred taxes on flow through accounting		97.4			94.8
Other regulatory assets		29.2			25.9
Total regulatory assets		374.3			394.7
Less current regulatory assets		(122.6	)		(139.7	)
Regulatory assets, non-current	$	251.7		$	255.0

Regulatory liabilities
Deferred energy and fuel cost adjustments		14.4		$	12.3
Deferred gas cost adjustments		31.2			51.5
Employee benefit plan costs and related deferred taxes		35.9			36.2
Cost of removal		220.6			216.5
Excess deferred income taxes		227.2			230.3
Colorado renewable energy		36.3			33.2
Other regulatory liabilities		10.5			8.2
Total regulatory liabilities		576.1			588.2
Less current regulatory liabilities		(85.9	)		(99.9	)
Regulatory liabilities, non-current	$	490.2		$	488.3

Recent Rate Review Activity

Arkansas Gas

On December 5, 2025, Arkansas Gas filed a rate review with the APSC seeking recovery of infrastructure investments in its natural gas pipeline system. The rate review requested $29.4 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10.5%. The request seeks to implement new rates in the fourth quarter of 2026.

Kansas Gas

On February 3, 2025, Kansas Gas filed a rate review with the KCC seeking recovery of infrastructure investments 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 Black-box Settlement agreement for a general rate increase expected to generate $10.8 million in new annual revenue and shift $4.4 million of GSRS rider revenue to base rates. New rates were enacted on August 1, 2025. The settlement also included 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. On March 2, 2026, Kansas Gas filed the abbreviated case, which was limited in scope and requested increases in base rate revenues of $2.4 million with new rates effective in the second half of 2026.

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Nebraska Gas

On May 1, 2025, Nebraska Gas filed a rate review with the NPSC seeking recovery of infrastructure investments and increased operations and maintenance costs driven by inflation and operational needs to serve customers. On December 9, 2025, Nebraska Gas received final approval from the NPSC for a settlement agreement for a general rate increase. The settlement is expected to generate $23.9 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 9.85%. The settlement also includes renewal of Nebraska Gas' SSIR for five years and the development of a two-year pilot program for a weather normalization adjustment rider. New rates were enacted on January 1, 2026, which replaced interim rates effective in August 2025. Nebraska Gas customers are entitled to a $4.7 million refund due to the interim rate increase exceeding the final approved rate increase, which was retroactive to August 2025. These amounts are expected to be refunded to customers as a one-time bill credit during the second quarter of 2026.

South Dakota Electric

On February 19, 2026, South Dakota Electric filed a rate review with the SDPUC seeking recovery of infrastructure investments and increased operations and maintenance costs driven by inflation and operational needs to serve customers since its last rate review in 2014. The rate review requested $50.6 million in new annual revenue with a capital structure of 53% equity and 47% debt and a return on equity of 10.5%. The request seeks interim rates to be effective 180 days after the filing, with new rates expected to be finalized in the first quarter of 2027.

On March 18, 2026, South Dakota Electric filed a rate review with the WPSC seeking recovery of infrastructure investments and increased operations and maintenance costs driven by inflation and operational needs to serve customers since its last rate review in 2014 The company is seeking an annual base rate increase to retail electric service rates of $5.1 million based on a similar capital structure and return on equity requested in South Dakota. New rates are expected to be finalized in the first quarter of 2027.

(3)

Commitments, Contingencies, and Guarantees

Deborah Ferrari et al. v. Colorado Electric, Case No. 2024CV31889 (District Court for the City and County of Denver, Colorado)

During the year ended December 31, 2025, Colorado Electric settled a legal matter involving an auto accident. As part of the settlement, Colorado Electric recognized a legal liability of $20 million, which was paid in the first quarter of 2026. In connection with this matter, Colorado Electric also recognized a loss recovery receivable of $20 million under its insurance coverage, which was received in the first quarter of 2026. We do not expect additional material losses related to this matter.

Generation Reservation Agreement with Prospective Data Center Customer

On April 22, 2026, Wyoming Electric entered into a generation reservation agreement with a prospective new customer seeking to construct a 1.8 GW data center under Wyoming Electric's LPCS Tariff. Under the agreement, the prospective customer will provide a refundable CIAC to Wyoming Electric to support milestone payments to suppliers to secure long lead-time generation equipment for potential company‑owned generation to serve the customer. To date, Wyoming Electric has received approximately $201 million in refundable CIAC payments from the prospective customer. Unless otherwise extended by the parties, this generation reservation agreement will terminate on June 30, 2026. This agreement is a bridge agreement to support long lead-time items while Wyoming Electric continues to negotiate definitive agreements with the prospective customer.

Power Purchase Agreement for Clean Energy Plan

On February 18, 2026, Colorado Electric executed a PPA with Honors Energy, LLC to purchase up to 200 MW of solar energy upon construction of a new renewable generation facility, which is expected to be completed by mid-2029. The agreement will expire 15 years after construction completion. The solar energy from this PPA will be used to support Colorado Electric's Clean Energy Plan.

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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 months ended March 31, 2026, and 2025. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended March 31, 2026	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	197.0	$	458.7	$	—		$	655.7
Transportation		—		54.5		(0.1	)		54.4
Wholesale		6.0		—		—			6.0
Market - off-system sales		10.9		—		—			10.9
Transmission		12.0		0.2		—			12.2
Other revenues		14.8		11.9		(3.9	)		22.8
Revenue from contracts with customers	$	240.7	$	525.3	$	(4.0	)	$	762.0
Alternative revenue and other		0.9		17.8		—			18.7
Total revenues	$	241.6	$	543.1	$	(4.0	)	$	780.7

Timing of revenue recognition:
Services transferred at a point in time	$	8.8	$	—	$	—		$	8.8
Services transferred over time		231.9		525.3		(4.0	)		753.2
Revenue from contracts with customers	$	240.7	$	525.3	$	(4.0	)	$	762.0


Three Months Ended March 31, 2025	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	191.3	$	499.7	$	—		$	691.0
Transportation		—		57.7		(0.1	)		57.6
Wholesale		7.1		—		—			7.1
Market - off-system sales		11.3		—		—			11.3
Transmission		12.1		0.2		—			12.3
Other revenues		13.8		11.1		(3.8	)		21.1
Revenue from contracts with customers	$	235.6	$	568.7	$	(3.9	)	$	800.4
Alternative revenue and other		1.1		3.7		—			4.8
Total revenues	$	236.7	$	572.4	$	(3.9	)	$	805.2

Timing of revenue recognition:
Services transferred at a point in time	$	8.1	$	—	$	—		$	8.1
Services transferred over time		227.5		568.7		(3.9	)		792.3
Revenue from contracts with customers	$	235.6	$	568.7	$	(3.9	)	$	800.4

(5)

Financing

Short-term Debt

Revolving Credit Facility and CP Program

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:


	March 31, 2026			December 31, 2025
	(dollars in millions)
Amount outstanding	$	252.2		$	—
Letters of credit (a)		3.2			3.2
Available capacity		494.6			746.8
Weighted average interest rates		3.95	%	N/A

(a)

Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

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Revolving Credit Facility and CP Program borrowing activity was as follows:


	Three Months Ended March 31,
	2026			2025
	(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)	$	338.0		$	263.6
Average amount outstanding (based on daily outstanding balances)		182.6			87.1
Weighted average interest rates		3.88	%		4.55	%

Long-term Debt

On October 2, 2025, we completed a public debt offering of $450 million, 4.55% senior unsecured notes due January 31, 2031. Proceeds from the offering, which were reduced by $4.0 million of deferred financing costs, were used to repay all $300 million principal amount outstanding of our 3.95% senior unsecured notes at their January 15, 2026, maturity date and for other general corporate purposes.

Financial Covenants

Revolving Credit Facility

We were in compliance with all of our Revolving Credit Facility covenants as of March 31, 2026. 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 March 31, 2026, our Consolidated Indebtedness to Capitalization Ratio was 0.54 to 1.00.

Wyoming Electric

Wyoming Electric was in compliance with all covenants within its financing agreements as of March 31, 2026. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of March 31, 2026, Wyoming Electric's debt to capitalization ratio was 0.50 to 1.00.

Equity

ATM

ATM activity was as follows:


	Three Months Ended March 31,
	2026		2025
June 16, 2023 ATM Program	(in millions, except Average price per share amounts)
Proceeds, (net of issuance costs of $0.0 and $(0.5), respectively)	$	—	$	45.7
Number of shares issued		—		0.8

May 8, 2025 ATM Program
Proceeds, (net of issuance costs of $(0.4) and $0.0, respectively)	$	40.7	$	—
Number of shares issued		0.6		—

Total activity under both ATM Programs
Proceeds, (net of issuance costs of $(0.4) and $(0.5), respectively)	$	40.7	$	45.7
Number of shares issued		0.6		0.8
Average price per share	$	73.42	$	60.44

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(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 March 31,
	2026		2025
	(in millions, except per share amounts)
Net income available for common stock	$	131.0	$	134.3

Weighted average shares - basic		75.4		71.6
Dilutive effect of equity compensation		0.2		0.2
Weighted average shares - diluted	$	75.6	$	71.8

Net income available for common stock, per share - Diluted	$	1.73	$	1.87

Anti-dilutive shares excluded from the diluted earnings per share computation were not material for the three months ended March 31, 2026, and 2025.

(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.

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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 through September 2028. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

The contract or notional amounts and terms of the 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:


	March 31, 2026				December 31, 2025
	Notional Amounts (MMBtus)			Maximum Term (months) (a)	Notional Amounts (MMBtus)		Maximum Term (months) (a)
Natural gas futures purchased		—		N/A		620,000	3
Natural gas options purchased, net		—		N/A		2,750,000	3
Natural gas basis swaps purchased		—		N/A		1,040,000	3
Natural gas over-the-counter swaps, net (b)		2,610,000		29		3,430,000	23
Natural gas physical contracts, net (c)		(942,398	)	12		14,285,200	10

(a)

Term reflects the maximum forward period hedged.

(b)

As of March 31, 2026, 625,000 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 March 31, 2026, the Company had no amount related to such provisions, which would be 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	March 31, 2026			December 31, 2025
		(in millions)
Derivatives designated as hedges:
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	$	(0.7	)	$	(2.8	)
Total derivatives designated as hedges		$	(0.7	)	$	(2.8	)

Derivatives not designated as hedges:
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	$	(1.1	)	$	(3.0	)
Total derivatives not designated as hedges		$	(1.1	)	$	(3.0	)

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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 months ended March 31, 2026, and 2025. 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.


	Three Months Ended March 31,					Three Months Ended March 31,
	2026		2025			2026			2025
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	$	0.7	$	0.8	Interest expense	$	(0.7	)	$	(0.8	)
Commodity derivatives		2.0		0.5	Fuel, purchased power, and cost of natural gas sold		(1.7	)		(0.4	)
Total	$	2.7	$	1.3		$	(2.4	)	$	(1.2	)

As of March 31, 2026, $2.2 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 months ended March 31, 2026, and 2025. 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 March 31,
		2026		2025
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	$	0.3	$	1.1
		$	0.3	$	1.1

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 $0.0 million and $4.6 million as of March 31, 2026, and December 31, 2025, respectively.

(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.

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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 2025 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 March 31, 2026
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)		Total
	(in millions)
Assets:
Commodity derivatives - Gas Utilities	$	—	$	—	$	—	$	—	$	—
Total	$	—	$	—	$	—	$	—	$	—

Liabilities:
Commodity derivatives - Gas Utilities	$	—	$	1.8	$	—	$	—	$	1.8
Total	$	—	$	1.8	$	—	$	—	$	1.8

(a)

As of March 31, 2026, $0.0 million of our commodity derivative assets and $1.8 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.


	As of December 31, 2025
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)			Total
	(in millions)
Assets:
Commodity derivatives - Gas Utilities	$	—	$	2.0	$	—	$	(2.0	)	$	—
Total	$	—	$	2.0	$	—	$	(2.0	)	$	—

Liabilities:
Commodity derivatives - Gas Utilities	$	—	$	8.8	$	—	$	(3.0	)	$	5.8
Total	$	—	$	8.8	$	—	$	(3.0	)	$	5.8

(a)

As of December 31, 2025, $2.0 million of our commodity derivative assets and $3.0 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

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Pension and Postretirement Plan Assets

The fair value of our pension and postretirement plan assets is presented in Note 13 to the Consolidated Financial Statements included in our 2025 Annual Report on Form 10-K.

Captive Insurance Cell Investments

We have investments in the Captive that may be used to pay insurance losses in the event of certain insured loss events. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments. These investments are restricted for insured loss events. Additional information regarding the Captive is presented in Note 12 to the Consolidated Financial Statements included in our 2025 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:


	March 31, 2026				December 31, 2025
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Long-term debt, including current maturities (a)	$	4,402.5	$	4,264.7	$	4,701.1	$	4,639.0

(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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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 March 31,
	Location on the Consolidated Statements of Income	2026			2025
		(in millions)
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(0.7	)	$	(0.8	)
Commodity contracts	Fuel, purchased power, and cost of natural gas sold		(1.7	)		(0.4	)
		$	(2.4	)	$	(1.2	)
Income tax	Income tax (expense) benefit		0.5			0.3
Total reclassification adjustments related to cash flow hedges, net of tax		$	(1.9	)	$	(0.9	)

Amortization of components of defined benefit plans:
Actuarial (loss)	Operations and maintenance		(0.1	)		—
Total reclassification adjustments related to defined benefit plans, net of tax		$	(0.1	)	$	—
Total reclassifications		$	(2.0	)	$	(0.9	)

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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, 2025	$	(1.6	)	$	(2.2	)	$	(5.9	)	$	(9.7	)
Other comprehensive income (loss) before reclassifications		—			0.2			—			0.2
Amounts reclassified from AOCI		0.6			1.3			0.1			2.0
As of March 31, 2026	$	(1.0	)	$	(0.7	)	$	(5.8	)	$	(7.5	)


	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		—			0.1			—			0.1
Amounts reclassified from AOCI		0.6			0.3			—			0.9
As of March 31, 2025	$	(3.2	)	$	0.1		$	(5.3	)	$	(8.4	)

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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 March 31,	2026			2025			2026		2025		2026			2025
	(in millions)
Service cost	$	0.4		$	0.4		$	—	$	0.2	$	0.4		$	0.4
Interest cost		3.6			4.0			0.3		0.3		0.5			0.6
Expected return on plan assets		(4.2	)		(4.2	)		—		—		(0.1	)		(0.1	)
Net amortization of prior service costs		—			—			—		—		0.1			0.1
Recognized net actuarial loss		0.6			0.5			—		—		—			—
Net periodic expense	$	0.4		$	0.7		$	0.3	$	0.5	$	0.9		$	1.0

Plan Contributions

Contributions made in the first three months of 2026 and additional contributions anticipated for the remainder of 2026 are as follows:


	Contributions Made		Additional Contributions
	Three Months Ended March 31, 2026		Anticipated for 2026
	(in millions)
Defined Benefit Pension Plan	$	—	$	1.6
Non-pension Defined Benefit Postretirement Healthcare Plan		1.3		3.2
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans		0.7		2.1

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Income Taxes

Transfers of Production Tax Credits

In January 2025 and 2026, we entered into agreements with a third party to sell 2024 and 2025 generated PTCs for $16.0 million and $15.3 million, respectively. We expect to continue to explore monetization of our tax credits through third party transferability agreements.

Income Tax (Expense) and Effective Tax Rates

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025

Income tax (expense) for the three months ended March 31, 2026, was $(17.6) million compared to $(18.1) million reported for the same period in 2025. For the three months ended March 31, 2026, the effective tax rate was 11.7%, which was comparable to 11.7% for the same period in 2025.

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Business Segment Information

We are a holding company that, through our subsidiaries, conducts our operations through the following two 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 our captive insurance cell, business development activities that are not part of our operating segments, and inter-segment eliminations.

Our Chief Executive Officer, who is considered to be our CODM, sets financial performance objectives and budgets and establishes separate targets based on operating income for our Electric Utilities segment as well as our Gas Utilities segment. Our CODM assesses segment financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies. Our CODM reviews capital expenditures by operating segment rather than any individual or total asset amount.

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Segment information was as follows:


	Consolidating Income Statement
Three Months Ended March 31, 2026	Electric Utilities		Gas Utilities		Total Reportable Segments		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	239.1	$	541.6	$	780.7	$	—		$	780.7
Inter-segment		2.5		1.5		4.0		(4.0	)		—
Total revenue		241.6		543.1		784.7		(4.0	)		780.7

Fuel, purchased power and cost of natural gas sold		66.8		271.2		338.0		(0.1	)		337.9
Operations and maintenance (a) -
Direct		33.1		40.4		73.5		0.6			74.1
Allocated		32.0		41.9		73.9		—			73.9
Depreciation and amortization		40.6		34.2		74.8		—			74.8
Taxes other than income taxes		9.2		8.9		18.1		—			18.1
Operating income (loss)	$	59.9	$	146.5	$	206.4	$	(4.5	)	$	201.9

Interest expense, net											(51.9	)
Other income, net											0.7
Income tax (expense)											(17.6	)
Net income											133.1
Net income attributable to non-controlling interest											(2.1	)
Net income available for common stock										$	131.0


	Consolidating Income Statement
Three Months Ended March 31, 2025	Electric Utilities		Gas Utilities		Total Reportable Segments		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	234.3	$	570.9	$	805.2	$	—		$	805.2
Inter-segment		2.4		1.5		3.9		(3.9	)		—
Total revenue		236.7		572.4		809.1		(3.9	)		805.2

Fuel, purchased power and cost of natural gas sold		67.2		292.6		359.8		(0.1	)		359.7
Operations and maintenance (a) -						—
Direct		35.7		44.1		79.8		(3.0	)		76.8
Allocated		33.1		43.8		76.9		—			76.9
Depreciation and amortization		37.1		32.1		69.2		—			69.2
Taxes other than income taxes		9.3		8.3		17.6		—			17.6
Operating income (loss)	$	54.3	$	151.5	$	205.8	$	(0.8	)	$	205.0

Interest expense, net											(51.3	)
Other income, net											0.8
Income tax (expense)											(18.1	)
Net income											136.4
Net income attributable to non-controlling interest											(2.1	)
Net income available for common stock										$	134.3

(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 three months ended March 31,	2026		2025
	(in millions)
Electric Utilities	$	189.5	$	102.1
Gas Utilities		68.4		59.0
Corporate and Other		1.9		1.3
Total capital expenditures	$	259.8	$	162.4

(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:


	March 31, 2026			December 31, 2025
	(in millions)
Billed Accounts Receivable	$	269.4		$	223.3
Unbilled Revenue		117.5			168.1
Less: Allowance for Credit Losses		(3.5	)		(2.4	)
Account Receivable, net	$	383.4		$	389.0

Changes to allowance for credit losses for the three months ended March 31, 2026, and 2025, 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 March 31,
	(in millions)
2026	$	2.4	$	2.0	$	0.8	$	(1.7	)	$	3.5
2025	$	2.1	$	3.4	$	0.9	$	(1.5	)	$	4.9

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:


	March 31, 2026		December 31, 2025
	(in millions)
Materials and supplies	$	119.3	$	117.3
Fuel - Electric Utilities		6.4		6.4
Natural gas in storage		21.1		48.7
Total materials, supplies, and fuel	$	146.8	$	172.4

Accrued Liabilities

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


	March 31, 2026		December 31, 2025
	(in millions)
Accrued employee compensation, benefits, and withholdings	$	60.3	$	92.8
Accrued property taxes		56.9		54.8
Customer deposits and prepayments		45.4		59.0
Accrued interest		56.7		57.2
Other (none of which is individually significant)		40.9		58.8
Total accrued liabilities	$	260.2	$	322.6

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Pending Merger with NorthWestern

On August 18, 2025, we entered into an Agreement and Plan of Merger (the “Merger Agreement”), with NorthWestern and Merger Sub. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern (the “Merger”), with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills Corporation, which will assume a new corporate name as the resulting parent company of the combined corporate group. At the effective time of the Merger (the “Effective Time”), each share of common stock of NorthWestern, par value $0.01 per share, issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of our common stock, par value $1.00 per share (or cash-in-lieu of fractional shares thereof), in each case upon and subject to the terms and conditions of the Merger Agreement.

The Merger Agreement, which was unanimously approved on August 18, 2025, by both the board of directors of Black Hills Corporation and the board of directors of NorthWestern, provides for a tax-free, all-stock business combination of Black Hills Corporation and NorthWestern upon the terms and subject to the conditions set forth therein. Such conditions include, among other things, clearance under the HSR Act, consent of the FCC, approval from each company's shareholders, and regulatory approvals, including approval from the SDPUC, NPSC and MPSC, as well as the FERC. To date, the status of these matters is as follows:

•

In October 2025, we filed joint applications for approval with the MPSC, NPSC, and SDPUC. In March 2026, we reached a settlement agreement with all intervening parties in Nebraska. A hearing before the NPSC was held in April 2026. In April 2026, we reached settlements agreements with several parties in Montana, which were filed with the MPSC. Also in April 2026, we reached a settlement with the SDPUC Staff, which was filed with the SDPUC. Hearings before the MPSC and SDPUC are scheduled in the second quarter of 2026. All settlement agreements are subject to approval by the respective regulatory commissions.

•

On December 22, 2025, we filed a joint application with the FERC. The initial public comment period closed on January 20, 2026. We expect a decision from the FERC by mid-2026.

•

On January 30, 2026, the Form S-4, which contains a joint proxy statement/prospectus for the Black Hills Corporation and NorthWestern, was publicly filed with the SEC. On February 6, 2026, the Form S-4 was declared effective by the SEC. On April 2, 2026, shareholders from both Black Hills Corporation and NorthWestern voted to approve the proposed all-stock merger.

•

On March 19, 2026, we filed an application for clearance under the HSR Act. The waiting period under the HSR Act was completed on April 20, 2026, satisfying a U.S. antitrust condition to closing.

We anticipate the transaction closing in the second half of 2026, subject to the satisfaction of certain closing conditions including receipt of certain regulatory approvals as mentioned above.

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Subsequent Events

Except as described below, there have been no events subsequent to March 31, 2026, which would require recognition in the Consolidated Financial Statements or disclosures.

See Note 3 for information regarding Wyoming Electric's generation reservation agreement.

See Note 14 for information regarding the pending merger with NorthWestern.

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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 2025 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 1.37 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 142 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

Pending Merger with NorthWestern

On August 18, 2025, we entered into the Merger Agreement with NorthWestern and Merger Sub. See Note 14 of the Condensed Notes to Consolidated Financial Statements for recent developments surrounding the pending Merger.

Business Segment Recent Developments

Electric Utilities

•

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

•

On March 12, 2026, the state of South Dakota enacted comprehensive wildfire liability mitigation legislation (SB36), effective July 1, 2026. The legislation provides material liability protections for a utility that complies with its published wildfire mitigation plan. South Dakota Electric plans to file its WMP with the SDPUC in the second half of 2026. In 2025, the state of Wyoming enacted similar legislation. In November 2025, Wyoming Electric filed its WMP with the WPSC and anticipates approval by mid-2026.

•

During the first quarter of 2026, South Dakota Electric continued with construction of its Lange II project which is anticipated to be in service in the fourth quarter of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements.

•

In 2025, Colorado Electric received CPUC approval for the addition of 250 MW of new renewable generation resources in support of its Clean Energy Plan, which included a 50-MW utility-owned battery storage project and a 200-MW solar PPA. During the fourth quarter of 2025, Colorado Electric commenced construction of the 50-MW battery storage project. The project is expected to be completed by year-end 2027. On February 18, 2026, Colorado Electric entered into a 200-MW solar PPA. See Note 3 of the Condensed Notes to Consolidated Financial Statements for additional information regarding the PPA.

•

In January 2026, Wyoming Electric set a new all-time peak load of 393 MW, surpassing the previous peak of 379 MW set on June 20, 2025.

Gas Utilities

•

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

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Corporate and Other

•

See Note 5 of the Condensed Notes to Consolidated Financial Statements for information regarding recent financing activities.

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 months ended March 31, 2026, and 2025, and our financial condition as of March 31, 2026, and December 31, 2025, 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.

Consolidated Summary and Overview


	Three Months Ended March 31,
	2026			2025			2026 vs 2025 Variance
	(in millions, except per share amounts)
Operating income (loss):
Electric Utilities	$	59.9		$	54.3		$	5.6
Gas Utilities		146.5			151.5			(5.0	)
Corporate and Other (a)		(4.5	)		(0.8	)		(3.7	)
Operating income		201.9			205.0			(3.1	)

Interest expense, net		(51.9	)		(51.3	)		(0.6	)
Other income, net		0.7			0.8			(0.1	)
Income tax (expense)		(17.6	)		(18.1	)		0.5
Net income		133.1			136.4			(3.3	)
Net income attributable to non-controlling interest		(2.1	)		(2.1	)		-
Net income available for common stock	$	131.0		$	134.3		$	(3.3	)

Weighted average common shares outstanding, Diluted		75.6			71.8			3.8
Total earnings per share of common stock, Diluted	$	1.73		$	1.87		$	(0.14	)

(a)

Includes inter-segment eliminations.

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025:

•

Electric Utilities’ operating income increased $5.6 million primarily due to new rates and rider recovery driven by the Colorado Electric rate review and Wyoming Electric's recently completed Ready Wyoming project partially offset by unfavorable weather and lower residential and commercial customer usage;

•

Gas Utilities’ operating income decreased $5.0 million primarily due to unfavorable weather partially offset by new rates and rider recovery driven by the Kansas Gas and Nebraska Gas rate reviews and lower operating expenses; and

•

Corporate and Other operating loss increased $3.7 million primarily due to costs related to the pending merger with NorthWestern.

Segment Operating Results

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

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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 March 31,						Three Months Ended March 31,
	2026			2025			2026			2025
	(in millions)
Revenue	$	241.6		$	236.7		$	543.1		$	572.4
Fuel, purchased power and cost of natural gas sold		(66.8	)		(67.2	)		(271.2	)		(292.6	)
Operations and maintenance (a)		(39.2	)		(41.9	)		(41.1	)		(46.2	)
Depreciation and amortization		(40.5	)		(37.1	)		(34.2	)		(32.1	)
Taxes other than income taxes		(9.2	)		(9.3	)		(8.9	)		(8.3	)
Gross margin (GAAP)	$	85.9		$	81.2		$	187.7		$	193.2
Operations and maintenance (a)		39.2			41.9			41.1			46.2
Depreciation and amortization		40.5			37.1			34.2			32.1
Taxes other than income taxes		9.2			9.3			8.9			8.3
Electric and Gas Utility margin (non-GAAP)	$	174.8		$	169.5		$	271.9		$	279.8

(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 $25.9 million and $26.9 million for the three months ended March 31, 2026, and 2025, respectively, for the Electric Utilities and $41.2 million and $41.7 million for the three months ended March 31, 2026, and 2025, respectively, for the Gas Utilities.

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Electric Utilities

Operating results for the Electric Utilities were as follows:


	Three Months Ended March 31,
	2026		2025		2026 vs 2025 Variance
	(in millions)
Revenue	$	241.6	$	236.7	$	4.9
Fuel and purchased power		66.8		67.2		(0.4	)
Electric Utility margin (non-GAAP) (a)		174.8		169.5		5.3

Operations and maintenance		65.1		68.8		(3.7	)
Depreciation and amortization		40.6		37.1		3.5
Taxes other than income taxes		9.2		9.3		(0.1	)
Total operating expenses (excluding Fuel and purchased power)		114.9		115.2		(0.3	)

Operating income	$	59.9	$	54.3	$	5.6

(a)

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

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025:

•

Electric Utility margin increased as a result of the following:


	(in millions)
New rates and rider recovery	$	13.3
Residential and commercial customer usage		(3.6	)
Weather		(3.2	)
Other		(1.2	)
	$	5.3

•

Operations and maintenance expense decreased primarily due to $2.4 million of lower outside services expenses.

•

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 March 31,				Three Months Ended March 31,
By Customer Class	2026		2025		2026		2025
	(in millions)				(in GWh)
Retail Revenue -
Residential	$	63.1	$	66.4		358.9		406.4
Commercial		70.0		68.8		492.2		517.2
Industrial (a)		56.2		48.2		707.4		609.8
Municipal		4.3		4.5		31.1		34.6
Other Retail		3.4		3.4		—		—
Subtotal Retail Revenue - Electric		197.0		191.3		1,589.6		1,568.0
Wholesale		6.0		7.1		140.1		147.8
Market - off-system sales		10.9		11.3		198.3		173.6
Transmission		12.0		12.1		—		—
Other (b)		15.7		14.9		—		—
Total Revenue and Quantities Sold	$	241.6	$	236.7		1,928.0		1,889.4
Other Uses, Losses, or Generation, net (c)						103.2		94.1
Total Energy						2,031.2		1,983.5

(a)

The increase in industrial quantities sold for the three months ended March 31, 2026, compared to the same period in 2025, was primarily driven by Wyoming Electric's 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 March 31,				Three Months Ended March 31,
By Business Unit	2026		2025		2026		2025
	(in millions)				(in GWh)
Colorado Electric	$	69.2	$	72.4		495.9		532.3
South Dakota Electric		86.7		86.9		679.7		682.0
Wyoming Electric		74.8		66.6		726.6		645.8
Integrated Generation		10.9		10.8		25.8		29.3
Total Revenue and Quantities Sold	$	241.6	$	236.7		1,928.0		1,889.4


	Three Months Ended March 31,
Quantities Generated and Purchased by Fuel Type	2026		2025
	(in GWh)
Generated:
Coal (a)		490.2		599.9
Natural Gas and Oil		441.7		512.1
Wind		186.8		175.4
Total Generated		1,118.7		1,287.4
Purchased:
Coal, Natural Gas, Oil, and Other Market Purchases		562.4		375.7
Wind and Solar		350.1		320.4
Total Purchased (b)		912.5		696.1

Total Generated and Purchased		2,031.2		1,983.5

(a)

The decrease in coal generation for the three months ended March 31, 2026, compared to the same period in 2025, is primarily due to generation outages at Wygen III (returned to service in mid-March 2026).

(b)

The increase in total purchases for the three months ended March 31, 2026, compared to the same period in 2025, was primarily driven by increased demand from Wyoming Electric's BCIS Tariff customers and generation outages at Wygen III as discussed in (a) above.

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	Three Months Ended March 31,
Quantities Generated and Purchased by Business Unit	2026		2025
	(in GWh)
Generated:
Colorado Electric		143.8		184.3
South Dakota Electric (a)		400.6		478.9
Wyoming Electric		180.5		219.3
Integrated Generation		393.8		404.9
Total Generated		1,118.7		1,287.4
Purchased:
Colorado Electric		104.5		90.2
South Dakota Electric (a)		300.3		211.3
Wyoming Electric (b)		491.2		376.1
Integrated Generation		16.5		18.5
Total Purchased		912.5		696.1

Total Generated and Purchased		2,031.2		1,983.5

(a)

The shift in South Dakota Electric's generated and purchased GWh for the three months ended March 31, 2026, compared to the same period in 2025, is primarily driven by generation outages at Wygen III (returned to service in mid-March 2026).

(b)

As discussed in footnote (b) 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 BCIS Tariff customers.


	Three Months Ended March 31,
	2026		2025
Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	2,001	(21)%	2,733	9%
South Dakota Electric	2,567	(22)%	3,438	5%
Wyoming Electric	2,325	(23)%	3,140	5%
Combined (a)	2.263	(22)%	3,060	7%

Cooling Degree Days:
Colorado Electric	11	N/M	---	---
South Dakota Electric	---	---	---	---
Wyoming Electric	---	---	---	---
Combined (a)	5	N/M	---	---

(a)

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

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Gas Utilities

Operating results for the Gas Utilities were as follows:


	Three Months Ended March 31,
	2026		2025		2026 vs 2025 Variance
	(in millions)
Revenue	$	543.1	$	572.4	$	(29.3	)
Cost of natural gas sold		271.2		292.6		(21.4	)
Gas Utility margin (non-GAAP) (a)		271.9		279.8		(7.9	)

Operations and maintenance		82.3		87.9		(5.6	)
Depreciation and amortization		34.2		32.1		2.1
Taxes other than income taxes		8.9		8.3		0.6
Total operating expenses (excluding Cost of natural gas sold)		125.4		128.3		(2.9	)

Operating income	$	146.5	$	151.5	$	(5.0	)

(a)

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

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025:

•

Gas Utility margin decreased as a result of the following:


	(in millions)
Weather	$	(13.2	)
Retail customer usage		(2.1	)
Mark-to-market on non-utility natural gas commodity contracts		(0.7	)
New rates and rider recovery		8.8
Other		(0.7	)
	$	(7.9	)

•

Operations and maintenance expense decreased primarily due to $4.4 million of lower employee costs.

•

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.

Operating Statistics


	Revenue				Quantities Sold and Transported
	Three Months Ended March 31,				Three Months Ended March 31,
By Customer Class	2026		2025		2026		2025
	(in millions)				(Dth in millions)
Retail Revenue -
Residential	$	311.7	$	344.1		25.2		30.7
Commercial		125.5		134.3		12.2		14.0
Industrial		6.9		6.6		0.9		1.0
Other Retail (a)		14.6		14.7		—		—
Subtotal Retail Revenue - Gas		458.7		499.7		38.3		45.7
Transportation		54.5		57.7		46.2		50.4
Other (b)		29.9		15.0		—		—
Total Revenue and Quantities Sold	$	543.1	$	572.4		84.5		96.1

(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.

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	Revenue				Quantities Sold and Transported
	Three Months Ended March 31,				Three Months Ended March 31,
By Business Unit	2026		2025		2026		2025
	(in millions)				(Dth in millions)
Arkansas Gas	$	122.1	$	124.8		11.5		13.2
Colorado Gas		90.2		115.8		10.8		13.2
Iowa Gas		93.8		86.8		14.1		15.2
Kansas Gas		60.6		66.1		10.2		11.7
Nebraska Gas		130.9		130.2		26.2		29.6
Wyoming Gas		45.5		48.7		11.7		13.2
Total Revenue and Quantities Sold	$	543.1	$	572.4		84.5		96.1


	Three Months Ended March 31,
	2026		2025
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	1,572	(16)%	1,957	2%
Colorado Gas	2,059	(27)%	2,837	2%
Iowa Gas	2,994	(9)%	3,288	(1)%
Kansas Gas (a)	2,034	(15)%	2,616	10%
Nebraska Gas (a)	2,545	(15)%	3,039	2%
Wyoming Gas	2,464	(24)%	3,323	3%
Combined (b)	2,513	(18)%	3,082	1%

(a)

Arkansas Gas and Kansas Gas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins. Nebraska Gas received NPSC approval to implement a two-year pilot program for a weather normalization mechanism which was effective August 1, 2025.

(b)

The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas and Nebraska Gas (effective in August 2025) due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

Corporate and Other

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


	Three Months Ended March 31,
	2026			2025			2026 vs 2025 Variance
	(in millions)
Operating income (loss)	$	(4.5	)	$	(0.8	)	$	(3.7	)

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025:

•

Operating loss increased primarily due to $4.6 million of costs related to the pending merger with NorthWestern.

Consolidated Interest Expense, Other Income and Income Tax Expense


	Three Months Ended March 31,
	2026			2025			2026 vs 2025 Variance
	(in millions)
Interest expense, net	$	(51.9	)	$	(51.3	)	$	(0.6	)
Other income, net		0.7			0.8			(0.1	)
Income tax (expense)		(17.6	)		(18.1	)		0.5

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Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025:

•

Interest expense, net, was comparable to the same period in the prior year as higher interest expense primarily driven by higher debt balances was mostly offset by higher interest income driven by higher cash and cash equivalents balances.

•

Other income, 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 March 31, 2026, the effective tax rate was 11.7%, which was comparable to 11.7% for the same period in 2025.

Liquidity and Capital Resources

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


	March 31, 2026			December 31, 2025
	(dollars in millions)
Cash and cash equivalents	$	23.6		$	182.8
Available capacity under Revolving Credit Facility and CP Program (a)		494.6			746.8
Available liquidity	$	518.2		$	929.6

Capital structure
Short-term debt	$	662.2		$	-
Long-term debt		3,992.5			4,701.1
Total debt		4,654.7			4,701.1
Total stockholders' equity (excludes non-controlling interest)		3,945.2			3,823.6
Total capitalization	$	8,599.9		$	8,524.7

Debt to capitalization		54.1	%		55.1	%
Long-term debt to total debt		85.8	%		100.0	%

(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.

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. Our current shelf registration statement expires in the second quarter of 2026 and we expect to file a new shelf registration statement to replace it. Additionally, we plan to re-finance our $400 million, 3.15%, senior unsecured notes due January 2027, at or before the maturity date.

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CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the three months ended March 31, 2026:

Operating Activities:


	Three Months Ended March 31,
	2026			2025			2026 vs 2025 Variance
	(in millions)
Net income	$	133.1		$	136.4		$	(3.3	)
Non-cash adjustments to Net income		115.3			112.9			2.4
Total earnings	$	248.4		$	249.3		$	(0.9	)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel, Accounts receivable and other current assets		45.0			(17.3	)		62.3
Accounts payable and other current liabilities		(119.3	)		(56.0	)		(63.3	)
Regulatory assets		5.4			52.6			(47.2	)
Net inflow (outflow) from changes in certain operating assets and liabilities	$	(68.9	)	$	(20.7	)	$	(48.2	)
Other operating activities		(3.3	)		(0.8	)		(2.5	)
Net cash provided by operating activities	$	176.2		$	227.8		$	(51.6	)

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025

•

Total earnings (net income plus non-cash adjustments) were comparable to the same period in the prior year, as new rates and rider recovery were offset by unfavorable weather and lower retail customer usage.

•

Net outflows from changes in certain operating assets and liabilities were $48.2 million higher, primarily attributable to:

Cash inflows increased by $62.3 million as a result of changes in accounts receivable and other current assets primarily driven by fluctuations in commodity prices and weather, and receipt of an insurance loss recovery receivable related to a legal settlement in Colorado;

Cash outflows increased by $63.3 million as a result of changes in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, payment of a legal liability from settlement in Colorado and changes in other working capital requirements; and

Cash inflows decreased by $47.2 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of gas and fuel cost adjustments driven by fluctuations in commodity prices, and lower recoveries of our Winter Storm Uri regulatory asset as recovery is now complete in most of our jurisdictions.

•

Cash outflows from other operating activities increased by $2.5 million primarily driven by settlement of contractor retainage balances from Wyoming Electric's recently completed Ready Wyoming project and higher cloud computing licensing costs.

Investing Activities:


	Three Months Ended March 31,
	2026			2025			2026 vs 2025 Variance
	(in millions)
Capital expenditures	$	(267.4	)	$	(152.9	)	$	(114.5	)
Other investing activities		(2.6	)		(2.3	)		(0.3	)
Net cash (used in) investing activities	$	(270.0	)	$	(155.2	)	$	(114.8	)

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025

•

Cash outflows from capital expenditures (which are net of non-refundable CIACs) increased $114.5 million primarily driven by Wyoming Electric’s milestone payments for long lead-time generation equipment. See Note 3 of the Condensed Notes to Consolidated Financial Statements for additional information.

•

Cash outflows from other investing activities were comparable to the same period in the prior year.

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Financing Activities:


	Three Months Ended March 31,
	2026			2025			2026 vs 2025 Variance
	(in millions)
Dividends paid on common stock	$	(53.1	)	$	(48.6	)	$	(4.5	)
Common stock issued		40.7			45.6			(4.9	)
Short-term and long-term debt borrowings (repayments), net		(47.8	)		(73.9	)		26.1
Distributions to non-controlling interests		(2.5	)		(3.8	)		1.3
Other financing activities		(2.5	)		(1.2	)		(1.3	)
Net cash provided by (used in) financing activities	$	(65.2	)	$	(81.9	)	$	16.7

Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025

•

Dividends paid on common stock increased $4.5 million due to the increased dividend rate per share and increased number of common shares outstanding.

•

Cash inflows decreased $4.9 million due to decreased issuances of common stock under our ATM.

•

Net cash outflows decreased $26.1 million primarily as a result of net borrowing activity under our CP Program partially offset by the repayment of $300 million, 3.95% senior unsecured notes on their January 15, 2026 maturity date.

•

Distributions to non-controlling interests were comparable to the same period in the prior year.

•

Cash outflows from other financing activities were comparable to the same period in the prior year.

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 August 19, 2025, S&P affirmed our BBB+ rating and maintained a Stable outlook.

(b)

On August 19, 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

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CAPITAL REQUIREMENTS

Capital Expenditures


	Actual (a)		Forecasted (b)
Capital Expenditures by Segment (minor differences may result due to rounding)	Three Months Ended March 31, 2026		2026		2027		2028		2029		2030
	(in millions)
Electric Utilities	$	190	$	471	$	367	$	455	$	356	$	391
Gas Utilities		68		396		455		507		591		552
Corporate and Other		2		39		22		21		22		25
	$	260	$	906	$	844	$	983	$	969	$	968

(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.

Common Stock Dividends

Dividends paid on our common stock totaled $53.1 million for the three months ended March 31, 2026, or $0.703 per share. On April 28, 2026, our board of directors declared a quarterly dividend of $0.703 per share payable June 1, 2026, equivalent to an annual dividend of $2.812 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.

Critical Accounting Estimates

A summary of our critical accounting estimates is included in our 2025 Annual Report on Form 10-K. There were no material changes made as of March 31, 2026.

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 2025 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 March 31, 2026. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 2026.

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 March 31, 2026, 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.

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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 2025 Annual Report on Form 10-K.

ITEM 1A. RISK FACTORS

There have been no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2025 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 March 31, 2026:


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
January 1, 2026 - January 31, 2026		1	$	69.42		—		—
February 1, 2026 - February 28, 2026		32,951		72.16		—		—
March 1, 2026 - March 31, 2026		1		73.63		—		—
Total		32,953	$	72.16		—		—

(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.

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 March 31, 2026.

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. Items constituting a board of director or management compensatory plan are designated by a cross (†).


Exhibit Number	Description
10.1*†	Form of Restricted Stock Unit Award Agreement (Non-Employee Director) effective for awards granted on or after May 1, 2026.
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)

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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:	May 7, 2026

EX-10.1

BLACK HILLS CORPORATION NON-EMPLOYEE DIRECTOR

EQUITY COMPENSATION PLAN

UNDER THE BLACK HILLS CORPORATION

AMENDED AND RESTATED 2015 omnibus INCENTIVE PLAN

Restricted Stock Unit Award Agreement (Non-Employee Director)

Black Hills Corporation (the “Company”), pursuant to its Non-Employee Director Equity Compensation Plan (the “Non-Employee Director Equity Plan”) under its Amended and Restated 2015 Omnibus Incentive Plan (the “Omnibus Plan”), hereby grants an award of Restricted Stock Units to you, the Participant named below. The terms and conditions of this Award are set forth in this Restricted Stock Unit Award Agreement (the “Agreement”), consisting of this cover page and the Terms and Conditions on the following pages, and in the Omnibus Plan document and the Non-Employee Director Equity Plan document, a copy of both documents which has been made available to you. Any capitalized term that is used but not defined in this Agreement shall have the meaning assigned to it in the Omnibus Plan or Non-Employee Director Equity Plan, as they currently exist or as they may be amended in the future.

     Name of Participant:    

    

     Number of Restricted Stock Units:    

    

     Grant Date:    May 1, 2026

    

     Scheduled Vesting Date:   April 30, 2027

    

By signing below or otherwise evidencing your acceptance of this Agreement in a manner approved by the Company, you agree to all of the terms and conditions contained in this Agreement, the Omnibus Plan and Non-Employee Director Equity Plan. You acknowledge that you have reviewed these documents.


PARTICIPANT:		BLACK HILLS CORPORATION
		By:
		Darren Nakata, Senior Vice President -- Chief Legal Officer, Corporate Secretary and Chief Compliance Officer

BLACK HILLS CORPORATION NON-EMPLOYEE DIRECTOR

EQUITY COMPENSATION PLAN

UNDER THE BLACK HILLS CORPORATION

AMENDED AND RESTATED 2015 omnibus INCENTIVE PLAN

Restricted Stock Unit Award Agreement (Non-Employee Director)

Terms and Conditions

1. Grant of Restricted Stock Units. The Company hereby confirms the grant to you, as of the Grant Date and subject to the terms and conditions in this Agreement, the Omnibus Plan and the Non-Employee Director Equity Plan, of the number of Restricted Stock Units specified on the cover page of this Agreement (the “Units”). Each Unit represents the right to receive one share of the Company’s Stock (each, a “Share”). Prior to their settlement or forfeiture in accordance with the terms of this Agreement, the Units granted to you will be credited to an account in your name maintained by the Company. This account shall be unfunded and maintained for book-keeping purposes only, with the Units simply representing an unfunded and unsecured contingent obligation of the Company.

2. Restrictions Applicable to Units. Neither this Award nor the Units subject to this Award may be sold, assigned, transferred, exchanged or encumbered, voluntarily or involuntarily, other than a transfer upon your death in accordance with your will, by the laws of descent and distribution or pursuant to a beneficiary designation submitted in accordance with the Plan. Following any such transfer, this Award shall continue to be subject to the same terms and conditions that were applicable to this Award immediately prior to its transfer. Any attempted transfer in violation of this Section 2 shall be void and without effect. The Units and your right to receive Shares in settlement of the Units under this Agreement shall be subject to forfeiture as provided in Section 5 until satisfaction of the vesting conditions set forth in Section 4.

3. No Shareholder Rights. The Units subject to this Award do not entitle you to any rights of a holder of the Company’s common stock. You will not have any of the rights of a shareholder of the Company in connection with the grant of Units subject to this Agreement unless and until Shares are issued to you upon settlement of the Units as provided in Section 6.

4. Vesting of Units. For purposes of this Agreement, “Vesting Date” means any date, including the Scheduled Vesting Date specified on the cover page of this Agreement, on which Units subject to this Agreement vest as provided in this Section 4. Notwithstanding the vesting and subsequent settlement of this Award, the Award and any Share issuances or payments made hereunder shall remain subject to the provisions of Section 21.1 of the Omnibus Plan.

(a)

Scheduled Vesting. If you remain a Director continuously from the Grant Date specified on the cover page of this Agreement, then the Units will vest on the Scheduled Vesting Date.

(b)

Accelerated Vesting. The vesting of outstanding Units will be accelerated under the circumstances provided below:

(1)

Death or Disability. If you cease to be a Director prior to the Scheduled Vesting Date due to your death or Disability, then all of the unvested Units shall vest as of such termination date. Disability for this purpose means that the Director is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or can be expected to last for a continuous period of not less than 12 months.

RSU Agreement – Non-Employee Directors Page 2

(2)

Change of Control. If a Change of Control occurs while you are a Director and prior to the Scheduled Vesting Date, then all of the unvested Units shall vest as of the date of the consummation of such Change of Control.

(3)

Termination as Director upon Closing of the Merger. In the event that your service as a Director terminates upon the closing of the Agreement and Plan of Merger by and among the Company, NorthWestern Energy Group, Inc., and River Merger Sub Inc. dated August 18, 2025, then you will vest in a pro-rated amount of the Units with (i) 25% of the Units vesting for each calendar quarter that ended within the period between the Grant Date and the closing date and (ii) 25% of the Units vesting for the calendar quarter in which the closing date occurs (rounded in accordance with Section 6(a) and in no event in excess of an aggregate 100% vesting). For the avoidance of doubt, the end of the calendar quarter in which the Award was granted will count for purposes of determining the number of calendar quarters that ended between the Grant Date and the closing date, even though the Award was granted within that calendar quarter.

5. Forfeiture. Except as otherwise provided in accordance with Section 4 above or under the terms of the Non-Employee Director Equity Plan, if you cease to be a Director, you will forfeit all unvested Units.

6. Settlement of Units.

(a)

Unless you have elected to defer settlement of the Units, after any Units vest pursuant to Section 4, the Company shall, as soon as practicable (but no later than the 15th day of the third calendar month following the Vesting Date), cause to be issued and delivered to you (or to your personal representative or your designated beneficiary or estate in the event of your death, as applicable) one Share in payment and settlement of each vested Unit. Delivery of the Shares shall be effected by the issuance of a stock certificate to you, by an appropriate entry in the stock register maintained by the Company’s transfer agent with a notice of issuance provided to you, or by the electronic delivery of the Shares to a brokerage account you designate, and shall be subject to the tax provisions of Section 8, to the extent applicable, and compliance with all applicable legal requirements as provided in the Omnibus Plan, and shall be in complete satisfaction and settlement of such vested Units. If the Units that vest include a fractional Unit, the Company shall round the number of vested Units to the nearest whole Unit prior to issuance of Shares as provided herein.

(b)

If you have elected to defer the settlement of the Units (“Deferred Units”) pursuant to the terms of the Non-Employee Director Equity Plan, after any Deferred Units vest pursuant to Section 4, the settlement of such Deferred Units shall be governed by the terms of the Non-Employee Director Equity Plan and your related deferral election.

7. Dividend Equivalents. If the Company pays cash dividends on its Shares while any Units subject to this Agreement are outstanding, then the Company shall credit, as of each dividend payment date, with a number of additional Units (the “Dividend Units”) equal to the result of dividing (i) the product of (x) the total number of Restricted Stock Units credited to your Account on the record date for such dividend and (y) the per share amount of such dividend by (ii) the Fair Market Value of one Share on the date such dividend is paid by the Company to the holder of Shares. Your right to receive such accrued Dividend Units shall vest, and the Dividend Units shall be settled, to the same extent and at the same time as the underlying Units to which the Dividend Units relate vest and are settled, as provided in Sections 4 and 6 of this Agreement. Any Dividend Units accrued on Units that are forfeited in accordance with this Agreement shall also be forfeited.

RSU Agreement – Non-Employee Directors Page 3

8. Tax Consequences. No Shares will be delivered to you in settlement of vested Units unless you have made arrangements acceptable to the Company for payment of any federal, state, local or foreign taxes that may be due as a result of the delivery of the Shares.

9. Notices. Every notice or other communication relating to this Agreement shall be in writing and shall be mailed to or delivered (including electronically) to the party for whom it is intended at such address as may from time to time be designated by it in a notice mailed or delivered to the other party as herein provided. Unless and until some other address is so designated, all notices or communications by you to the Company shall be mailed or delivered to the Company, to the attention of its Corporate Secretary, at its office at 7001 Mt. Rushmore Road, Rapid City, SD 57702, darren.nakata@blackhillscorp.com, and all notices or communications by the Company to you may be given to you personally or may be mailed or, if you are still a Director, emailed to you at the address indicated in the Company's records as your most recent mailing or email address.

10. Additional Provisions.

(a) No Right to Continued Service. This Agreement does not give you a right to continue as a Director or other service provider with the Company or any Affiliate, regardless of the effect it may have upon you under this Agreement.

(b) Governing Plan Document. This Agreement and the Award are subject to all the provisions of the Omnibus Plan, the Non-Employee Director Equity Plan, and to all interpretations, rules and regulations which may, from time to time, be adopted and promulgated by the Committee pursuant to the Omnibus Plan and the Non-Employee Director Equity Plan. If there is any conflict between the provisions of this Agreement and the Omnibus Plan or Non-Employee Director Equity Plan, the provisions of the Omnibus Plan or Non-Employee Director Equity Plan will govern.

(c) Governing Law. This Agreement, the parties’ performance hereunder, and the relationship between them shall be governed by, construed, and enforced in accordance with the laws of the State of South Dakota, without giving effect to the choice of law principles thereof. The parties agree that any action relating to or arising out of this Agreement shall take place exclusively in the State of South Dakota, and you consent to the jurisdiction of the federal and/or state courts in South Dakota. You further consent to personal jurisdiction and venue in both such courts and to service of process by United States Mail or express courier service in any such action.

(d) Severability. The provisions of this Agreement shall be severable and if any provision of this Agreement is found by any court to be unenforceable, in whole or in part, the remainder of this Agreement shall nevertheless be enforceable and binding on the parties. You also agree that any trier of fact may modify any invalid, overbroad or unenforceable provision of this Agreement so that such provision, as modified, is valid and enforceable under applicable law.

(e) Binding Effect. This Agreement will be binding in all respects on your heirs, representatives, successors and assigns, and on the successors and assigns of the Company.

(f) Section 409A of the Code. Except to the extent Participant has elected to defer the Units pursuant to the terms of the Non-Employee Director Equity Plan and his or her related deferral election form, the award of Units as provided in this Agreement and any issuance of Shares or payment pursuant to this Agreement are intended to be exempt from Section 409A of the Code under the short-term deferral exception specified in Treas. Reg. § 1.409A-l(b)(4).

RSU Agreement – Non-Employee Directors Page 4

(g) Electronic Delivery and Acceptance. The Company may deliver any documents related to this Restricted Stock Unit Award by electronic means and request your acceptance of this Agreement by electronic means. You hereby consent to receive all applicable documentation by electronic delivery and to participate in the Omnibus Plan and Non-Employee Director Equity Plan through an on-line (and/or voice activated) system established and maintained by the Company or, if appliable, the Company’s third-party stock plan administrator.

By signing the cover page of this Agreement or otherwise accepting this Agreement in a manner approved by the Company, you agree to all the terms and conditions described above, in the Omnibus Plan document and the Non-Employee Director Equity Plan document.

RSU Agreement – Non-Employee Directors Page 5

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Linden R. Evans, certify that:

I have reviewed this Quarterly Report on Form 10-Q of Black Hills Corporation;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: May 7, 2026
	/s/ Linden R. Evans
	Linden R. Evans
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Kimberly F. Nooney, certify that:

I have reviewed this Quarterly Report on Form 10-Q of Black Hills Corporation;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.


Date: May 7, 2026
	/s/ Kimberly F. Nooney
	Kimberly F. Nooney
	Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2026, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Linden R. Evans, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.


Date: May 7, 2026

		/s/ Linden R. Evans
		Linden R. Evans
		President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Black Hills Corporation (the “Company”) on Form 10-Q for the period ended March 31, 2026, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kimberly F. Nooney, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of Section 13 (a) or

15 (d) of the Securities Exchange Act of 1934; and

(2)

The information contained in the Report fairly presents, in all material

respects, the financial condition and results of operations of the Company.


Date: May 7, 2026

		/s/ Kimberly F. Nooney
		Kimberly F. Nooney
		Senior Vice President and Chief Financial Officer

EX-95

Exhibit 95

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of Dodd-Frank is included below.

Mine Safety and Health Administration Safety Data

Safety is a core value at Black Hills Corporation and at each of its subsidiary operations. We have in place a comprehensive safety program that includes extensive health and safety training for all employees, site inspections, emergency response preparedness, crisis communications training, incident investigation, regulatory compliance training and process auditing, as well as an open dialogue between all levels of employees. The goals of our processes are to eliminate exposure to hazards in the workplace, ensure that we comply with all mine safety regulations, and support regulatory and industry efforts to improve the health and safety of our employees along with the industry as a whole.

Under the recently enacted Dodd-Frank Act, each operator of a coal or other mine is required to include certain mine safety results in its periodic reports filed with the SEC. Our mining operation, consisting of Wyodak Mine, is subject to regulation by the federal Mine Safety and Health Administration ("MSHA") under the Federal Mine Safety and Health Act of 1977 (the “Mine Act”). Below we present the following information regarding certain mining safety and health matters for the three month period ended March 31, 2026. In evaluating this information, consideration should be given to factors such as: (i) the number of citations and orders will vary depending on the size of the coal mine, (ii) the number of citations issued will vary from inspector to inspector and mine to mine, and (iii) citations and orders can be contested and appealed, and in that process, are often reduced in severity and amount, and are sometimes dismissed. The information presented includes:

•

Total number of violations of mandatory health and safety standards that could significantly and substantially contribute to the cause and effect of a coal or other mine safety or health hazard under section 104 of the Mine Act for which we have received a citation from MSHA;

•

Total number of orders issued under section 104(b) of the Mine Act;

•

Total number of citations and orders for unwarrantable failure of the mine operator to comply with mandatory health and safety standards under section 104(d) of the Mine Act;

•

Total number of imminent danger orders issued under section 107(a) of the Mine Act; and

•

Total dollar value of proposed assessments from MSHA under the Mine Act.

The table below sets forth the total number of citations and/or orders issued by MSHA to Wyodak Mine under the indicated provisions of the Mine Act, together with the total dollar value of proposed MSHA assessments received during the three months ended March 31, 2026, and legal actions pending before the Federal Mine Safety and Health Review Commission (FMSHRC), together with the Administrative Law Judges thereof, for Wyodak Mine, our only mining complex. All citations were abated within 24 hours of issue.

     Mine/ MSHA
Identification Number

     Mine Act Section 104 S&S Citations issued during three months ended March 31, 2026

     Mine Act Section 104(b) Orders (#)

     Mine Act Section 104(d) Citations and Orders (#)

     Mine Act Section 110(b)(2) Violations (#)

     Mine Act Section 107(a) Imminent Danger Orders (#)

     Total Dollar Value of Proposed MSHA Assessments (a)

     Total Number of Mining Related Fatalities (#)

     Received Notice of Potential to Have Pattern Under Section 104(e) (yes/no)

     Legal Actions Pending as of Last Day of Period (#) (b)

     Legal Actions Initiated During Period (#)

     Legal Actions Resolved During Period (#)

     Wyodak Mine - 4800083

     0

     0

     0

     0

     0

     $

     0

     0

     No

     0

     0

     0

(a)

The types of proceedings by class: (1) Contests of citations and orders – none; (2) contests of proposed penalties – none; (3) complaints for compensation – none; (4) complaints of discharge, discrimination or interference under Section 105 of the Mine Act – none; (5) applications for temporary relief – none; and (6) appeals of judges' decisions or orders to the FMSHRC – none.