Black Hills BKH Form 10-Q filing Q2 FY2026

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 17

Note 6. Earnings Per Share 19

Note 7. Risk Management and Derivatives 19

Note 8. Fair Value Measurements 22

Note 9. Other Comprehensive Income 24

Note 10. Employee Benefit Plans 25

Note 11. Income Taxes 26

Note 12. Business Segment Information 26

Note 13. Selected Balance Sheet Information 29

Note 14. Pending Merger with NorthWestern 30

Note 15. Subsequent Events 30

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 31

Executive Summary 31

Recent Developments 31

Results of Operations 32

Consolidated Summary and Overview 33

Non-GAAP Financial Measure 34

Electric Utilities 35

Gas Utilities 38

Corporate and Other 40

Consolidated Interest Expense, Other Income and Income Tax Expense 40

Liquidity and Capital Resources 41

Cash Flow Activities 41

Capital Resources 43

Credit Ratings 43

Capital Requirements 43

Critical Accounting Estimates 43

New Accounting Pronouncements 44

Item 3. Quantitative and Qualitative Disclosures About Market Risk 44

Item 4. Controls and Procedures 44

PART II. OTHER INFORMATION

Item 1. Legal Proceedings 44

Item 1A. Risk Factors 44

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 44

Item 4. Mine Safety Disclosures 44

Item 5. Other Information 45

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

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

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

See Note 9 for additional disclosures.

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

BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

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

BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Continued)

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

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

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

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY

BLACK HILLS CORPORATION

Condensed Notes to Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2025 Annual Report on Form 10-K)

(1)

Management’s Statement

The unaudited Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we”, or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 2025 Annual Report on Form 10-K.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the June 30, 2026, December 31, 2025, and June 30, 2025, financial information. Certain lines of business in which we operate are highly seasonal and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.

Recently Issued Accounting Standards

Disaggregation of Income Statement Expenses, ASU 2024-03

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

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

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

(2)

Regulatory Matters

We had the following regulatory assets and liabilities:

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.

Colorado Electric

On June 12, 2026, Colorado Electric filed a rate review with the CPUC seeking recovery of infrastructure and operational costs in its electric service. The rate review requested $26.7 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 10.5%. The request seeks to implement new rates in the first quarter of 2027.

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. On June 25, 2026, the KCC approved the abbreviated request with new rates effective July 1, 2026.

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 were 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 were refunded to customers as a one-time bill credit during the second quarter of 2026.

South Dakota Electric

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

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

(3)

Commitments, Contingencies, and Guarantees

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

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

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.

(4)

Revenue

The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three and six months ended June 30, 2026, and 2025. Sales tax and other similar taxes are excluded from revenues.

(5)

Financing

Shelf Registration Statement

We maintain an effective shelf registration statement with the SEC under which we may issue, from time to time, an unspecified amount of senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. In anticipation of the approaching expiration of our previous shelf registration statement on Form S-3 originally filed on June 16, 2023 (Registration No. 333-272739), we filed a new shelf registration statement on Form S-3 on May 19, 2026, (Registration No. 333-296010).

Short-term Debt

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 in Wyoming subject to the LPCS Tariff. Under the agreement, the prospective customer will provide refundable advances 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. As of and for the six months ended June 30, 2026, Wyoming Electric received $285 million in refundable advances from the prospective customer. In July 2026, the parties amended this generation reservation agreement to increase the total refundable advances to $377 million with a new maturity date of August 31, 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.

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:

(a)

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

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

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 June 30, 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 June 30, 2026, our Consolidated Indebtedness to Capitalization Ratio was 0.53 to 1.00. Consolidated Indebtedness, as defined under the terms of our Revolving Credit Facility, does not include the $285 million of Refundable advances for construction as of June 30, 2026, discussed above.

Wyoming Electric

Wyoming Electric was in compliance with all covenants within its financing agreements as of June 30, 2026. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of June 30, 2026, Wyoming Electric's debt to capitalization ratio was 0.48 to 1.00. Debt, as defined under the terms of Wyoming Electric's financing agreements, does not include the $285 million of Refundable advances for construction as of June 30, 2026, discussed above.

Equity

ATM

ATM activity was as follows:

(6)

Earnings Per Share

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

Anti-dilutive shares excluded from the diluted earnings per share computation were not material for the three and six months ended June 30, 2026, and 2025.

(7)

Risk Management and Derivatives

Market and Credit Risk Disclosures

Our activities in the energy industry expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed but not limited to, the following market risks:

• Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, geopolitical events, pandemics, market speculation, imposition of new tariffs, recession, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and
• Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit, and other security agreements.

We perform periodic credit evaluations of our customers and adjust credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses, and any specific customer collection issue that is identified.

Derivatives and Hedging Activity

Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income, and Consolidated Statements of Comprehensive Income are detailed below and in Note 8.

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:

(a)

Term reflects the maximum forward period hedged.

(b)

As of June 30, 2026, 1,401,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c)

Volumes exclude contracts that qualify for the normal purchases and normal sales exception under GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At June 30, 2026, the Company had $0.1 million 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:

Derivatives Designated as Hedge Instruments

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

As of June 30, 2026, $1.1 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three and six months ended June 30, 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.

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 $0.4 million and $4.6 million as of June 30, 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.

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.

(a)

As of June 30, 2026, $0.8 million of our commodity derivative assets and $0.1 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

(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.

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:

(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 Comprehensive Income

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges, and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The following table details reclassifications out of AOCI and into Net income. The amounts in parentheses below indicate decreases to Net income in the Consolidated Statements of Income for the period, net of tax:

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

(10)

Employee Benefit Plans

Components of Net Periodic Expense

The components of net periodic expense were as follows:

Plan Contributions

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

(11)

Income Taxes

Transfers of Production Tax Credits

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

Income Tax (Expense) and Effective Tax Rates

Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025

Income tax (expense) for the three months ended June 30, 2026, was $(5.2) million compared to $(4.4) million reported for the same period in 2025. For the three months ended June 30, 2026, the effective tax rate was 11.4%, which was comparable to 13.3% for the same period in 2025.

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025

Income tax (expense) for the six months ended June 30, 2026, was $(22.8) million compared to $(22.5) million reported for the same period in 2025. For the six months ended June 30, 2026, the effective tax rate was 11.6%, which was comparable to 12.0% for the same period in 2025.

(12)

Business Segment Information

We are a holding company that, through our subsidiaries, conducts our operations through the following two reportable segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our reportable segments are presented as Corporate and Other.

Our operating segments, which are equivalent to our reportable segments, are based on our method of internal reporting, which is generally segregated by differences in products and services. All of our operations and assets are located within the United States.

Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota, and Wyoming. We also own and operate non-regulated power generation and mining businesses that are vertically integrated with our Electric Utilities.

Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming.

Corporate and Other consists of certain unallocated expenses for administrative activities that support our operating segments. Corporate and Other also includes our captive insurance cell, business development activities that are not part of our operating segments, and inter-segment eliminations.

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

Segment information was as follows:

(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.

(a)

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

(13)

Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

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

Changes to allowance for credit losses for the six months ended June 30, 2026, and 2025, respectively, were as follows:

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:

Accrued Liabilities

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

(14)

Pending Merger with NorthWestern

On August 18, 2025, we entered into an Agreement and Plan of Merger (the “Merger Agreement”), with NorthWestern and Merger Sub. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern (the “Merger”), with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills Corporation, which will assume a new corporate name, Bright Horizon Energy Corporation, 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.

o

In March 2026, we reached a settlement agreement with all intervening parties in Nebraska. On May 19, 2026, the NPSC approved the merger.

o

In April 2026, we reached a settlement with the SDPUC Staff, which was filed with the SDPUC. On June 24, 2026, the SDPUC approved the merger.

o

In April 2026, we reached settlements agreements with several parties in Montana, which were filed with the MPSC. Hearings before the MPSC occurred during the second quarter of 2026. The settlement agreements are subject to approval by the MPSC.

• On December 22, 2025, we filed a joint application with the FERC. The initial public comment period closed on January 20, 2026. On May 29, 2026, we received approval for the Merger from the FERC.
• 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 by year-end 2026, subject to the satisfaction of certain closing conditions and remaining regulatory approval from the MPSC as mentioned above.

(15)

Subsequent Events

Except as described below, there have been no events subsequent to June 30, 2026, which would require recognition in the Consolidated Financial Statements or disclosures.

See Note 5 for information regarding Wyoming Electric's amended and extended generation reservation agreement.

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 and Colorado Electric.
• During the second 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. On August 4, 2026, South Dakota Electric filed an application with the SDPUC for a PIRP rider which requests recovery of $320 million of Lange II project costs outside of a general rate review. If approved by the SDPUC, the rider is anticipated to be effective on December 1, 2026.
• On March 12, 2026, the state of South Dakota enacted comprehensive wildfire liability mitigation legislation (Senate Bill 36), effective July 1, 2026. The legislation provides material liability protections for a utility that complies with its published wildfire mitigation plan. On July 2, 2026, South Dakota Electric filed its WMP with the SDPUC. Under Senate Bill 36, a utility's WMP is valid and current if it is on file and all annual reports are timely filed with the SDPUC. In 2025, the state of Wyoming enacted similar legislation. In November 2025, Wyoming Electric filed its WMP with the WPSC, which was approved on July 9, 2026.
• 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. In July 2026, the parties amended this generation reservation agreement to increase the total refundable advances and extended the maturity date to August 31, 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. See Note 5 of the Condensed Notes to Consolidated Financial Statements for additional information.
• On June 30, 2026, Wyoming Electric submitted an IRP to the WPSC. The IRP, which is based on 20-year planning period including a near-term planning period through 2033, identified a near-term capacity shortfall of 95 MW beginning in 2027. Based on its forecasts and analysis, Wyoming Electric recommends the addition of natural gas-fired generation and battery storage assets to meet the identified resource need. Wyoming Electric's IRP does not address any LPCS Tariff capacity needs, which are handled separately under customer-specific agreements.
• On June 19, 2026, Wyoming Electric filed a request with the WPSC to establish an LCTCAM tariff. The LCTCAM tariff provides a framework to directly recover transmission investment costs from LPCS customers who are served by, and benefit from, the transmission facility. The proposed mechanism is designed to ensure that customers not directly served by those facilities are protected from bearing those costs. The filing requests WPSC approval of the LCTCAM tariff by September 1, 2026, with an effective date of January 1, 2027.
• In 2026, Wyoming Electric has set multiple all-time records for System Peak Demand. The most recent all-time peak of 439 MW was set on July 20, 2026. Prior to 2026, the previous all-time peak was 379 MW set on June 20, 2025.
• 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.

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.

Corporate and Other

• See Note 5 of the Condensed Notes to Consolidated Financial Statements for information regarding recent financing activities.
• During the second quarter of 2026, we published our 2025 Corporate Sustainability Report, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals. We reported a 43% reduction in electric utility emissions intensity compared to 2005, driven by the addition of renewable and natural gas resources and the retirement of aging power plants. We also reduced natural gas utility emissions by 25% since 2022, including a 53% reduction from transfer stations, reflecting progress toward our net-zero by 2035 goal through expanded leak detection and repair efforts.

Results of Operations

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2026, and 2025, and our financial condition as of June 30, 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

(a)

Includes inter-segment eliminations.

Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025:

• Electric Utilities' operating income increased $12.1 million primarily due to new rates and rider recovery driven by the Wyoming Electric's recently completed Ready Wyoming project;
• Gas Utilities' operating income increased $7.6 million primarily due to new rates and rider recovery driven by the Nebraska Gas and Kansas Gas rate reviews partially offset by higher operating expenses;
• Corporate and Other operating loss increased $5.2 million primarily due to costs related to the pending merger with NorthWestern; and
• Net interest expense increased $2.7 million primarily due to higher rates on increased debt.

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025:

• Electric Utilities’ operating income increased $16.9 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 lower residential and commercial customer usage and unfavorable weather;
• Gas Utilities’ operating income increased $1.0 million primarily due to new rates and rider recovery driven by the Nebraska Gas, Kansas Gas, and Arkansas Gas rate reviews partially offset by unfavorable weather and higher operating expenses;
• Corporate and Other operating loss increased $6.3 million primarily due to costs related to the pending merger with NorthWestern; and
• Net interest expense increased $3.2 million primarily due to higher rates on increased debt partially offset by higher AFUDC debt.

Segment Operating Results

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

Non-GAAP Financial Measures

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

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

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

(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 $23.9 million, $25.4 million, $50.7 million, and $52.3 million for the three and six months ended June 30, 2026, and 2025, respectively, for the Electric Utilities and $38.9 million, $39.4 million, $81.6 million, and $81.2 million for the three and six months ended June 30, 2026, and 2025, respectively, for the Gas Utilities.

Electric Utilities

Operating results for the Electric Utilities were as follows:

(a)

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

Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025:

• Electric Utility margin increased as a result of the following:

• Operations and maintenance expense decreased primarily due to $3.2 million of lower expenses driven by prior year unplanned generation outages and $1.2 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 were comparable to the same period in the prior year.

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025:

• Electric Utility margin increased as a result of the following:

• Operations and maintenance expense decreased primarily due to $4.5 million of lower outside services expenses and $3.2 million of lower expenses driven by prior year unplanned generation outages.
• Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.
• Taxes other than income taxes were comparable to the same period in the prior year.

Operating Statistics

(a)

The increase in industrial quantities sold for the three and six months ended June 30, 2026, compared to the same periods in 2025, was primarily driven by Wyoming Electric's large-load customers under the LPSC and BCIS Tariffs.

(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.

(a)

The increase in total purchases for the six months ended June 30, 2026, compared to the same period in 2025, was primarily driven by generation outages and increased demand from Wyoming Electric's large-load customers under the LPCS and BCIS Tariffs.

(a)

As discussed in footnote (a) in the Quantities Generated and Purchased by Fuel Type table above, the increase in Wyoming Electric's purchases for the three and six months ended June 30, 2026, compared to the same periods in 2025, is primarily driven by increased demand from large-load customers under the LPCS and BCIS Tariffs.

(a)

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

Gas Utilities

Operating results for the Gas Utilities were as follows:

(a)

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

Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025:

• Gas Utility margin increased as a result of the following:

• Operations and maintenance expense increased primarily due to higher outside services expenses and office and facilities expenses partially offset by lower employee related expenses.
• Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.
• Taxes other than income taxes were comparable to the same period in the prior year.

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025:

• Gas Utility margin increased as a result of the following:

• Operations and maintenance expense decreased primarily due to $5.1 million of lower employee related expenses partially offset by $3.2 million of higher outside services expenses.
• Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.
• Taxes other than income taxes were comparable to the same period in the prior year.

Operating Statistics

(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.

(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 June 30, 2026, Compared to the Three Months Ended June 30, 2025:

• Operating loss increased primarily due to $4.1 million of costs related to the pending merger with NorthWestern.

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025:

• Operating loss increased primarily due to $8.6 million of costs related to the pending merger with NorthWestern.

Consolidated Interest Expense, Other Income and Income Tax Expense

Three Months Ended June 30, 2026, Compared to the Three Months Ended June 30, 2025:

• Interest expense, net, increased compared to the same period in the prior year as higher interest expense primarily driven by higher debt 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 June 30, 2026, the effective tax rate was 11.4%, which was comparable to 13.3% for the same period in 2025.

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025:

• Interest expense, net, increased compared to the same period in the prior year due to higher interest expense primarily driven by higher debt balances partially offset by higher AFUDC debt driven by construction work-in-progress 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 six months ended June 30, 2026, the effective tax rate was 11.6%, which was comparable to 12.0% 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:

(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, the issuance of common stock under our ATM or in a secondary offering and refundable advances from customers. We plan to re-finance our $400 million, 3.15%, senior unsecured notes due January 2027, at or before the maturity date.

Wyoming Electric entered into a generation reservation agreement with a prospective data center customer who will provide refundable advances totaling $377 million under the agreement maturing August 31, 2026. In the absence of an extension of this agreement, we will evaluate a range of financing alternatives to address repayment of the refundable advances, including available capacity under our Revolving Credit Facility, potential short-term loan arrangements, and issuances under our ATM.

CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the six months ended June 30, 2026:

Operating Activities:

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025

• Total earnings (net income plus non-cash adjustments) were $11.1 million higher than the same period in the prior year primarily as a result of increased Electric and Gas Utility margins due to new rates and rider recovery partially offset by higher financing costs.
• Net inflows from changes in certain operating assets and liabilities were $42.7 million lower, primarily attributable to:

o

Cash inflows increased by $49.3 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 $52.1 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 $39.9 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 nearly all jurisdictions.

• Cash outflows from other operating activities increased by $13.5 million primarily driven by settlement of contractor retainage balances from Wyoming Electric's recently completed Ready Wyoming project and higher costs from cloud computing arrangements.

Investing Activities:

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025

• Cash outflows from capital expenditures increased $113.7 million primarily driven by the Lange II project and Wyoming Electric’s milestone payments for long lead-time generation equipment.
• Cash outflows from other investing activities were comparable to the same period in the prior year.

Financing Activities:

Six Months Ended June 30, 2026, Compared to the Six Months Ended June 30, 2025

• Dividends paid on common stock increased $9.0 million due to the increased dividend rate per share and increased number of common shares outstanding.
• Cash inflows decreased $14.9 million due to decreased issuances of common stock under our ATM.
• Net cash outflows increased $199.9 million primarily as a result of the repayment of $300 million, 3.95% senior unsecured notes on their January 15, 2026 maturity date partially offset by net borrowing activity under our CP Program.
• Distributions to non-controlling interests increased due to higher net income from Black Hills Colorado IPP primarily driven by prior year unplanned generation outages.
• Cash inflows increased due to $285.0 million of refundable advances from a prospective customer for long lead-time generation equipment. See Note 5 of the Condensed Notes to Consolidated Financial Statements for additional information.
• Cash outflows from other financing activities were comparable to the same period in the prior year.

CAPITAL RESOURCES

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

CREDIT RATINGS

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

Rating Agency Senior Unsecured Rating Outlook

S&P (a) BBB+ Stable

Moody's (b) Baa2 Stable

(a)

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

(b)

On August 19, 2025, Moody's affirmed our Baa2 rating and maintained a Stable outlook.

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

Rating Agency Senior Secured Rating

S&P A

CAPITAL REQUIREMENTS

Capital Expenditures

(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 $106.6 million for the six months ended June 30, 2026, or $0.703 per share. On July 28, 2026, our board of directors declared a quarterly dividend of $0.703 per share payable September 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 June 30, 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 June 30, 2026. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, 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 June 30, 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.

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 June 30, 2026:

(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 June 30, 2026.

Item 6. Exhibits 45

Signatures 46

GLOSSARY OF TERMS AND ABBREVIATIONS

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

AFUDC Allowance for Funds Used During Construction

AOCI Accumulated Other Comprehensive Income (Loss)

APSC Arkansas Public Service Commission

Arkansas Gas Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).

ASU Accounting Standards Update as issued by the FASB

ATM At-the-market equity offering program

BHC Black Hills Corporation; the Company

BHSC Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)

Black-box Settlement Settlement with a utility's commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.

Black Hills Electric Generation Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.

Black Hills Electric Parent Holdings Black Hills Electric Utility Holdings, LLC., a direct, wholly-owned subsidiary of Black Hills Corporation

Black Hills Energy The name used to conduct the business of our Utilities

Black Hills Energy Services Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs.

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.

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).

IRP Integrated Resource Plan

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.

LCTCAM Large Customer Transmission Cost Adjustment Mechanism

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

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

Phase-in Plan Rate (PIPR) Rider South Dakota law provides for a utility to begin recovering costs outside of a general rate review for investments in new generation facilities.

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.

System Peak Demand Represents the highest point of retail customer usage for a single hour.

TCAM Transmission Cost Adjustment Mechanism is a WPSC-approved tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmission costs.

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).

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).

PART I. FINANCIAL INFORMATION