BLACK HILLS CORP /SD/ 10-Q

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 OR ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ Commission File Number 001-31303 Black Hills Corporation Incorporated in South Dakota IRS Identification Number 46-0458824 7001 Mount Rushmore Road Rapid City , South Dakota 57702 Registrant’s telephone number ( 605 ) 721-1700 Former name, former address, and former fiscal year if changed since last report NONE Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the Registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large Accelerated Filer x Accelerated Filer ☐ Non-accelerated Filer ☐ Smaller Reporting Company ☐ Emerging Growth Company ☐ If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes ☐ No ☒ Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol(s) Name of each exchange on which registered Common stock of $1.00 par value BKH New York Stock Exchange Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date. Class Outstanding at May 4, 2026 Common stock, $1.00 par value 76,128,592 shares Table of Contents 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 2 Table of Contents G LOSSARY 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. 3 Table of Contents 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 4 Table of Contents 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). 5 Table of Contents 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. 6 Table of Contents 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. 7 Table of Contents 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. 8 Table of Contents 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. 9 Table of Contents 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. 10 Table of Contents 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. 11 Table of Contents 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 12 Table of Contents 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) Manage ment’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 methodologie s. 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. 13 Table of Contents (2) Regul atory 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. 14 Table of Contents 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) Comm itments, 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. 15 Table of Contents (4) Rev enue 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) Fin ancing 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 . 16 Table of Contents 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 17 Table of Contents (6) Earning s 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 Mana gement 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 . 18 Table of Contents 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 ) 19 Table of Contents 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 a nd $ 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. 20 Table of Contents 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. 21 Table of Contents 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. (9) Other Compr ehensive 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 ) 22 Table of Contents 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 ) (10) Employe e 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 23 Table of Contents (11) Inco me 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 . (12) Business Segme nt 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. 24 Table of Contents 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. 25 Table of Contents 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 Balan ce 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 26 Table of Contents (14) Pending M erger 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. (15) Subs equent 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. 27 Table of Contents 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 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. See Note 3 of the Condensed Notes to Consolidated Financial Statements for additional information. • 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. 28 Table of Contents 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. 29 Table of Contents 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. 30 Table of Contents 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. 31 Table of Contents 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. 32 Table of Contents 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. 33 Table of Contents 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. 34 Table of Contents 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 35 Table of Contents 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. 36 Table of Contents C ASH 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: o 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; o 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 o 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. 37 Table of Contents 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. C APITAL RESOURCES See Note 5 of the Condensed Notes to Consolidated Financial Statements for recent financing updates and financial covenants information. C REDIT 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 38 Table of Contents C APITAL 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. 39 Table of Contents 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) 40 Table of Contents 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 41