Black Hills BKH Form 10-Q filing Q1 FY2025

Consolidated Statements of Income 8

Consolidated Statements of Comprehensive Income 9

Consolidated Balance Sheets 10

Consolidated Statements of Cash Flows 12

Consolidated Statements of Equity 13

Condensed Notes to Consolidated Financial Statements 14

Note 1. Management’s Statement 14

Note 2. Regulatory Matters 15

Note 3. Commitments, Contingencies and Guarantees 16

Note 4. Revenue 16

Note 5. Financing 18

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 25

Note 12. Business Segment Information 26

Note 13. Selected Balance Sheet Information 28

Note 14. Subsequent Events 28

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 29

Executive Summary 29

Recent Developments 29

Results of Operations 30

Consolidated Summary and Overview 30

Non-GAAP Financial Measure 31

Electric Utilities 32

Gas Utilities 35

Corporate and Other 36

Consolidated Interest Expense, Other Income and Income Tax Expense 36

Liquidity and Capital Resources 37

Cash Flow Activities 38

Capital Resources 39

Credit Ratings 39

Capital Requirements 40

Critical Accounting Estimates 40

New Accounting Pronouncements 40

Item 3. Quantitative and Qualitative Disclosures About Market Risk 40

Item 4. Controls and Procedures 40

PART II. OTHER INFORMATION

Item 1. Legal Proceedings 41

Item 1A. Risk Factors 41

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 41

Item 4. Mine Safety Disclosures 41

Item 5. Other Information 41

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.

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 2024 Annual Report on Form 10-K)

(1)

Management’s Statement

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

Use of Estimates and Basis of Presentation

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

Recently Issued Accounting Standards

Improvements to Income Tax Disclosures, ASU 2023-09

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which expands public entities’ annual disclosures by requiring disclosure of tax rate reconciliation amounts and percentages for specific categories, income taxes paid disaggregated by federal and state taxes, and income tax expense disaggregated by federal and state taxes jurisdiction. The ASU is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, with early adoption permitted. We are currently evaluating the impact of ASU 2023-09 on our consolidated financial statement disclosures.

Disaggregation of Income Statement Expenses, ASU 2024-03

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

(2)

Regulatory Matters

We had the following regulatory assets and liabilities:

(a)

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

Regulatory Activity

Colorado Electric

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

Iowa Gas

On May 1, 2024, Iowa Gas filed a rate review with the IUC seeking recovery of significant infrastructure investments in its 5,000-mile natural gas pipeline system. On December 2, 2024, Iowa Gas received final approval from the IUC for a settlement agreement for a general rate increase. The approved Black-box Settlement is expected to generate $15.0 million of new annual revenue based on a weighted average cost of capital of 7.2%. New rates were enacted on January 1, 2025, which replaced interim rates.

Kansas Gas

On February 3, 2025, Kansas Gas filed a rate review with the KCC seeking recovery of significant infrastructure investments in its 4,765-mile natural gas pipeline system. The rate review requests $17.2 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10.5%. The request seeks to implement new rates in the second half of 2025.

Nebraska Gas

On May 1, 2025, Nebraska Gas filed a rate review with the NPSC seeking recovery of significant infrastructure investments in its 12,900-mile natural gas pipeline system. The rate review requests $34.9 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 10.5%. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review. New rates are expected to be effective in the first quarter of 2026.

(3)

Commitments, Contingencies and Guarantees

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

Transfers of Renewable Tax Credits

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

(4)

Revenue

The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three months ended March 31, 2025, and 2024. Sales tax and other similar taxes are excluded from revenues.

(5)

Financing

Short-term Debt

Revolving Credit Facility and CP Program

Our Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following borrowings, outstanding letters of credit, and available capacity as of:

(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:

Financial Covenants

Revolving Credit Facility

We were in compliance with all of our Revolving Credit Facility covenants as of March 31, 2025. We are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Subject to applicable cure periods, a violation of this covenant would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. As of March 31, 2025, 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, 2025. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of March 31, 2025, Wyoming Electric's debt to capitalization ratio was 0.51 to 1.00.

Equity

At-the-Market Equity Offering Program

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:

The following securities were excluded from the diluted earnings per share computation because of their anti-dilutive nature:

(7)

Risk Management and Derivatives

Market and Credit Risk Disclosures

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

Market Risk

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

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

Credit Risk

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

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

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

Derivatives and Hedging Activity

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

The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps, and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions, are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income.

Through Black Hills Energy Services, our non-regulated natural gas commodity supplier, we buy, sell, and deliver natural gas in Nebraska and Wyoming at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from April 2025 through December 2027. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

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 March 31, 2025, 549,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c)

Volumes exclude derivative contracts that qualify for the normal purchases and normal sales exception permitted by GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At March 31, 2025, the Company posted $0.1 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

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

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, 2025, and 2024. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.

As of March 31, 2025, $2.7 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, 2025, and 2024. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.

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. There were no net unrealized gains or losses included in our Regulatory liability or asset accounts related to these financial instruments as of March 31, 2025. The net unrealized losses included in our Regulatory asset accounts related to these financial instruments were $2.9 million as of December 31, 2024.

(8)

Fair Value Measurements

We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means.

Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps, and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options, and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a credit valuation adjustment based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. For additional information, see Note 1 of our Notes to the Consolidated Financial Statements in our 2024 Annual Report on Form 10-K.

The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.

(a)

As of March 31, 2025, we had no commodity derivative or liabilities, or related gross collateral amounts, that were subject to master netting agreements.

(a)

As of December 31, 2024, $2.2 million of our commodity derivative assets and $0.6 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

Pension and Postretirement Plan Assets

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

Other Fair Value Measures

The carrying amount of cash and cash equivalents, restricted cash and equivalents, and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and are not traded on an exchange; therefore, they are classified as Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets as of:

(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 three months of 2025 and anticipated contributions for 2025 are as follows:

(11)

Income Taxes

Transfers of Production Tax Credits

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the IRA of 2022, or IRA. The IRA contains a tax credit transferability provision that allows us to transfer (e.g. sell) PTCs produced after December 31, 2022, to third parties. In January 2025, under this transferability provision, we entered into an agreement with a third party to sell $17.0 million of our 2024 generated PTCs.

We expect to continue to explore the ability to efficiently monetize our tax credits through third party transferability agreements.

Income Tax (Expense) and Effective Tax Rates

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Income tax (expense) for the three months ended March 31, 2025, was $(18.1) million compared to $(16.9) million reported for the same period in 2024. For the three months ended March 31, 2025, the effective tax rate was 11.7%, which was comparable to 11.4% for the same period in 2024.

(12)

Business Segment Information

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

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

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

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

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

Our Chief Executive Officer, who is considered to be our CODM, reviews financial information presented on an operating segment basis for purposes of making decisions, allocating resources, and assessing financial performance. Our CODM assesses the performance of our operating segments and decides how to allocate resources based on operating income. Our CODM reviews capital expenditures by operating segment rather than any individual or total asset amount.

Segment information was as follows:

(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 three months ended March 31, 2025 and 2024, 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) Subsequent Events

Except as described in Note 2, there have been no events subsequent to March 31, 2025, which would require recognition in the Consolidated Financial Statements or disclosures.

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

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

Executive Summary

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

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

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

Recent Developments

Business Segment Recent Developments

Electric Utilities

• See Note 2 of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for Colorado Electric.
• On March 6, 2025, the state of Wyoming enacted comprehensive wildfire mitigation legislation (HB192), effective July 1, 2025. The legislation provides material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. The legislation provides a utility a presumption of reasonableness and prudency for compliance with an approved wildfire mitigation plan.
• On February 12, 2025, Wyoming Electric set a new all-time and winter peak load of 344 MW, surpassing the previous all-time and winter peak of 318 MW set on January 20, 2025. Prior to 2025, the previous all-time and winter peak was 314 MW set on January 11, 2024.
• During the first quarter of 2025, Wyoming Electric continued construction of its approximately 260-mile, $350 million Ready Wyoming electric transmission expansion project, which is expected to be completed and in service by year-end 2025. Wyoming Electric has procured all required regulatory approvals and land rights-of-way and is constructing the project in multiple segments. The first 12-mile transmission line segment and two substations near Cheyenne, Wyoming, were completed and energized in 2024, adding approximately $40 million of rate base being recovered through the TCAM.
• During the first quarter of 2025, South Dakota Electric continued its Lange II construction project, which is planned to be in-service by the second half of 2026. On March 28, 2025, South Dakota Electric filed a request with the WPSC for the Lange II project.
• During the first quarter of 2025, Colorado Electric continued to pursue the addition of 350 MW of new renewable generation resources in support of its Clean Energy Plan. In 2024, the CPUC approved the addition of a 100-MW utility-owned solar project, 50-MW utility-owned battery storage project and a 200-MW solar PPA. Colorado Electric plans to file a CPCN for the battery storage project by mid-2025. Negotiations with counterparties for the other two projects are ongoing, which will drive final cost and timing of projects.

Gas Utilities

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

Corporate and Other

• See Note 5 of the Condensed Notes to Consolidated Financial Statements for ATM program activity.
• On January 17, 2025, Fitch affirmed BHC's long-term issuer rating at BBB+ with a negative outlook. Following the affirmation, the parties jointly withdrew the rating. See Liquidity and Capital Resources section below for additional information on our credit ratings.

Results of Operations

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

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

Consolidated Summary and Overview

(a)

Includes inter-segment eliminations.

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

The variance to the prior year included the following:

• Electric Utilities’ operating income decreased $10.3 million primarily due to higher operating expenses and current year unplanned generation outages;
• Gas Utilities’ operating income increased $20.7 million primarily due to new rates and rider recovery driven by the Arkansas Gas and Colorado Gas rate reviews and favorable winter heating season weather partially offset by higher operating expenses;
• Interest expense increased $7.3 million primarily due to higher interest rates and lower interest income on lower cash and cash equivalents balances; and
• Net income attributable to non-controlling interest decreased $1.6 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages.

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 $26.9 million and $21.5 million for the three months ended March 31, 2025 and 2024, respectively, for the Electric Utilities and $41.7 and $35.8 million for the three months ended 2025 and 2024, 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 March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Electric Utility margin increased as a result of the following:

Operations and maintenance expense increased primarily due to $2.8 million of expenses related to unplanned generation outages, $2.8 million of higher outside services expenses; $1.9 million of higher employee-related expenses and $1.3 million of higher insurance expense.

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

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

Operating Statistics

(a)

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

(b)

Includes company uses and line losses.

(a)

The shift between coal generation and coal, natural gas, oil and other market purchases for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to unplanned outages at Wygen III.

(b)

The increase in wind and solar GWh purchased for the three months ended March 31, 2025, compared to the same period in 2024 was primarily due to a new solar PPA. In 2022, Wyoming Electric entered into a new solar PPA with third party to purchase up to 150 MW of solar energy, upon construction of new renewable generation facility (owned by third party). The solar facility was placed in service in March 2024. The renewable energy from the PPA is used to serve our expanding partnerships with LPCS customers.

(a)

The shift between South Dakota Electric's generated and purchased GWh for the three months ended March 31, 2025, compared to the same period in 2024 is primarily due to unplanned outages at Wygen III.

(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 its solar PPA from the facility that was placed in service in March 2024.

(a)

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

(a)

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

(b)

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

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 March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Gas Utility margin increased as a result of the following:

Operations and maintenance expense increased primarily due to $4.1 million of higher employee related expenses, $1.8 million of higher insurance expense, and $1.4 million of higher bad debt expense driven by increased revenues.

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

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

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 revenue.

(b)

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

Corporate and Other

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

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Operating loss was comparable to the same period in the prior year.

Consolidated Interest Expense, Other Income and Income Tax Expense

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Interest expense, net increased primarily due to higher interest rates and lower interest income on lower cash and cash equivalents balances.

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

Income tax (expense) was comparable to the same period in the prior year. For the three months ended March 31, 2025, the effective tax rate was 11.7%, which was comparable to 11.4% for the same period in 2024.

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, and the issuance of common stock under our ATM program or in an opportunistic block trade. In 2025, we plan to renew our Equity Distribution Sales Agreement, which allows us to sell shares of common stock, from time to time, through our ATM program utilizing our shelf registration statement. We also plan to re-finance our $300 million, 3.95%, senior unsecured notes due January 2026, at or before maturity date.

CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the three months ended March 31, 2025:

Operating Activities:

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Net cash provided by operating activities was $5.6 million lower than the same period in 2024. The variance to the prior year was primarily attributable to:

• Total earnings (net income plus non-cash adjustments) were $27.3 million higher for the three months ended March 31, 2025, compared to the same period in the prior year primarily due the sale of our 2024 PTCs in January 2025.
• Net outflows from changes in certain operating assets and liabilities were $35.0 million higher, primarily attributable to changes in materials, supplies, fuel, accounts receivable, and other current assets driven by fluctuations in commodity prices and weather conditions.

Investing Activities:

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Net cash used in investing activities was $21.7 million lower than the same period in 2024. The variance to the prior year was primarily attributable to lower capital expenditures which were primarily driven by timing of projects and the prior year Black Hills Energy Renewable Resources' acquisition of a RNG production facility at a landfill in Dubuque, Iowa.

Financing Activities:

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Net cash used in financing activities was $62.1 million higher than the same period in 2024. The variance to the prior year was primarily attributable to:

• Cash outflows increased $73.9 million as a result of repayments of debt in excess of proceeds from debt offerings.
• Cash inflows increased $14.4 million due to higher issuances of common stock; and
• Cash outflows increased $4.2 million due to increased dividends paid on common stock.

CAPITAL RESOURCES

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

CREDIT RATINGS

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

Rating Agency Senior Unsecured Rating Outlook

S&P (a) BBB+ Stable

Moody's (b) Baa2 Stable

(a)

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

(b)

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

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

Rating Agency Senior Secured Rating

S&P A

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

CAPITAL REQUIREMENTS

Capital Expenditures

(a)

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

(b)

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

(c)

Includes actual capital expenditures for the three months ended March 31, 2025.

Common Stock Dividends

Dividends paid on our common stock totaled $48.6 million for the three months ended March 31, 2025, or $0.676 per share. On April 22, 2025, our board of directors declared a quarterly dividend of $0.676 per share payable June 1, 2025, equivalent to an annual dividend of $2.704 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility, and our future business prospects.

Critical Accounting Estimates

A summary of our critical accounting estimates is included in our 2024 Annual Report on Form 10-K. There were no material changes made as of March 31, 2025.

New Accounting Pronouncements

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of March 31, 2025. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 2025.

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

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2025, there have been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely, to materially affect our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 3 in Item 8 of our 2024 Annual Report on Form 10-K.

ITEM 1A. RISK FACTORS

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

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

The following table contains monthly information about our acquisitions of equity securities for the three months ended March 31, 2025:

(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, 2025.

Item 6. Exhibits 41

Signatures 42

GLOSSARY OF TERMS AND ABBREVIATIONS

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

AFUDC Allowance for Funds Used During Construction

AOCI Accumulated Other Comprehensive Income (Loss)

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

ASU Accounting Standards Update as issued by the FASB

ATM At-the-market equity offering program

Availability The availability factor of a power plant is the percentage of the time that it is available to provide energy.

BHC Black Hills Corporation; the Company

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

Black Hills Colorado IPP Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation

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

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

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

Black Hills Energy Renewable Resources (BHERR) Black Hills Energy Renewable Resources, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings

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

Black Hills Non-regulated Holdings Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation

Black Hills Utility Holdings Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)

Black Hills Wyoming Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation

Busch Ranch I A 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.

Busch Ranch II A 59.4 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a PPA expiring in November 2044.

CEPR Clean Energy Plan Rider, which is a 1.5% surcharge to fund Colorado Electric's recovery of renewable energy projects under the Clean Energy Plan. In conjunction with the implementation of the CEPR in January 2025, the RESA surcharge was reduced from 2.0% to 1.5%.

Choice Gas Program Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.

Chief Operating Decision Maker (CODM) Chief Executive Officer

CIAC Contribution in aid of construction

Clean Energy Plan 2030 Ready Plan that establishes a roadmap and preferred resource portfolio for Colorado Electric to achieve the State of Colorado’s requirement calling upon electric utilities to reduce greenhouse gas emissions by a minimum of 80% from 2005 levels by 2030. The recommended resource portfolio proposes the addition of 350 MW of clean energy resources to Colorado Electric's system. Colorado legislation allows electric utilities to own up to 50% of the renewable generation assets added to comply with the Clean Energy Plan.

Colorado Electric Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Parent Holdings, providing electric services to customers in Colorado (doing business as Black Hills Energy).

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

Consolidated Indebtedness to Capitalization Ratio Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.

Cooling Degree Day A cooling degree day is equivalent to each degree that the average of the high and the low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.

CP Program Commercial Paper Program

CPCN Certificate of Public Convenience and Necessity

CPUC Colorado Public Utilities Commission

CT Combustion Turbine

Dth Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)

FASB Financial Accounting Standards Board

Fitch Fitch Ratings Inc.

GAAP Accounting principles generally accepted in the United States of America

Heating Degree Day A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.

HomeServe We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.

Integrated Generation Non-regulated power generation and mining businesses (Black Hills Electric Generation and WRDC) that are vertically integrated within our Electric Utilities segment.

Iowa Gas Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).

IPP Independent Power Producer

IRS United States Internal Revenue Service

IUC Iowa Utilities Commission

Kansas Gas Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).

KCC Kansas Corporation Commission

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 completed by the second half of 2026. The fast-start, dispatchable generation will be comprised of six reciprocating internal combustion engines, with technology to support strong system resiliency, including crucial black start capability to respond quickly to electric load changes. The addition of these resources will replace aging gas-fired and diesel resources planned for retirement in 2027 and support updated planning reserve margin requirements.

Large Power Contract Service (LPCS) Tariff Innovative tariff solution developed in collaboration with Microsoft and approved by the WPSC in 2016. The LPSC is applicable to Wyoming Electric retail customers with new loads of 13 MW or greater who agree to Black Hills Energy-dispatched, customer-owned generation, on-site for the purpose of providing backup service for the customer’s load and maintaining reliability. If the parties agree through negotiations to electric service through this tariff, a Large Power Service Agreement will be executed. The associated service agreement provides qualifying customers with market-based energy rates and access to renewable energy resources that is not served from utility-owned generation (i.e. minimal capital model for Wyoming Electric). Customers shall not participate in the PCA or TCAM to the extent of service received under the tariff.

MMBtu Million British thermal units

Moody's Moody's Investors Service, Inc.

MW Megawatts

MWh Megawatt-hours

N/A Not applicable

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

NPSC Nebraska Public Service Commission

OCI Other Comprehensive Income

PPA Power Purchase Agreement

PTC Production Tax Credit

Pueblo Airport Generation Pueblo Airport Generating Station located in Pueblo, Colorado includes 440 MW of combined cycle gas-fired power generation plants jointly owned by Colorado Electric (240 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP operates this facility. The plants commenced operation on January 1, 2012.

Ready Wyoming A 260-mile, multi-phase transmission expansion project in Wyoming. This transmission project is expected to serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and expanding access to power markets and renewable resources. The project is expected to help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region.

RESA Renewable Energy Standard Adjustment is an incremental retail rate limited to 1.5% for Colorado Electric customers that provides funding for renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard.

Revolving Credit Facility Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended on May 31, 2024, and will terminate on May 31, 2029. This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment.

RNG Renewable natural gas

SEC United States Securities and Exchange Commission

Service Guard Comfort Plan Appliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.

S&P S&P Global Ratings, a division of S&P Global Inc.

South Dakota Electric Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).

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

Wind Capacity Factor Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.

Winter Storm Uri February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.

WPSC Wyoming Public Service Commission

WRDC Wyodak Resources Development Corp., a coal mine which is a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities at our Gillette Energy Complex (doing business as Black Hills Energy).

Wygen 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).

PART I. FINANCIAL INFORMATION