BLACK HILLS CORP /SD/ (BKH)

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

The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in our 2025 Annual Report on Form 10-K.

Executive Summary

We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for more than 1.37 million customers and 800+ communities we serve. Our aspiration is to be the trusted energy partner across our growing eight-state footprint, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming. Our strategy is centered on four priorities: People & Culture—build a team that wins together, Operational Excellence—relentlessly deliver on our commitment to serve our customers, Transformation—be a simple and connected company and Growth—grow to be a dominant long-term energy provider.

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

We have provided energy and served customers for 142 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations.

Recent Developments

Pending Merger with NorthWestern

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

Business Segment Recent Developments

Electric Utilities

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

•
On April 22, 2026, Wyoming Electric entered into a generation reservation agreement with a prospective new customer seeking to construct a 1.8 GW data center under Wyoming Electric's LPCS Tariff. See Note 3 of the Condensed Notes to Consolidated Financial Statements for additional information.

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

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

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

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

Gas Utilities

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

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Corporate and Other

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

Results of Operations

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three months ended March 31, 2026, and 2025, and our financial condition as of March 31, 2026, and December 31, 2025, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

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

Consolidated Summary and Overview

(a)
Includes inter-segment eliminations.

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

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

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

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

Segment Operating Results

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

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Non-GAAP Financial Measures

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

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

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

(a)
Operations and maintenance expenses which are deemed to be directly attributable to revenue-producing activities include plant operations and maintenance expenses at our electric generation facilities, operations and maintenance expenses at our WRDC coal mine, and electric and gas transmission and distribution expenses. These amounts are included in the table above to calculate gross margin in accordance with GAAP. These amounts excluded operations and maintenance expenses not directly attributable to revenue-producing activities of $25.9 million and $26.9 million for the three months ended March 31, 2026, and 2025, respectively, for the Electric Utilities and $41.2 million and $41.7 million for the three months ended March 31, 2026, and 2025, respectively, for the Gas Utilities.

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Electric Utilities

Operating results for the Electric Utilities were as follows:

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[["","Three Months Ended March 31,"],["","2026","","2025","","2026 vs 2025 Variance"],["","(in millions)"],["Revenue","$","241.6","","$","236.7","","$","4.9"],["Fuel and purchased power","","66.8","","","67.2","","","(0.4",")"],["Electric Utility margin (non-GAAP) (a)","","174.8","","","169.5","","","5.3"],["Operations and maintenance","","65.1","","","68.8","","","(3.7",")"],["Depreciation and amortization","","40.6","","","37.1

[Excerpt truncated for page length; source filing is linked above.]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Summary

We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for 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—transform to 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.

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Recent Developments

Pending Merger with NorthWestern

On August 18, 2025, we entered into the Merger Agreement with NorthWestern and Merger Sub. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further discussion about the pending Merger.

One Big Beautiful Bill Act

See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion surrounding the OBBBA.

Trade Tariffs

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

Business Segment Recent Developments

Electric Utilities

•
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate review activity for Colorado Electric.

•
In December 2025, the Ready Wyoming project was fully completed and placed in service and now interconnects South Dakota Electric’s and Wyoming Electric’s transmission systems. Ready Wyoming was originally announced in November 2021 and construction commenced in late 2023. 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.

•
In 2025, Wyoming Electric continued to grow its large-load demand from existing data center customers, Microsoft and Meta, under its LPCS Tariff. In July 2024, Wyoming Electric announced it would partner with Meta to provide power for its AI data center. Meta's new AI data center plans to transition from construction power to permanent service later in the first quarter of 2026. We are also actively negotiating with prospective new data center customers that would further grow our load pipeline under Wyoming Electric's LPCS Tariff and also through strategic investments in new transmission and generation.

•
In 2025, Wyoming Electric set multiple all-time and winter records for System Peak Demand. The most recent all-time peak of 379 MW was set on June 20, 2025 and the most recent winter peak of 375 MW was set on November 30, 2025. Prior to 2025, the previous all-time and winter peak was 314 MW set on January 11, 2024.

•
On March 28, 2025, South Dakota Electric filed a CPCN with the WPSC for the Lange II project, which was approved in June 2025. The new facility began construction in the third quarter of 2025 and is anticipated to be in service in the fourth quarter of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements.

•
In 2025, Colorado Electric received CPUC approval for the addition of 250 MW of new renewable generation resources in support of its Clean Energy Plan, which included a 50-MW utility-owned battery storage project and a 200-MW solar PPA. On November 3, the CPUC approved the CPCN for the 50-MW battery storage project. During the first quarter of 2026, Colorado Electric expects to execute the 200-MW solar PPA.

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

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•
On March 6, 2025, the state of Wyoming enacted comprehensive wildfire liability mitigation legislation (HB0192), effective July 1, 2025. The legislation provides material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. In November 2025, we filed our WMP with the WPSC and anticipate approval in March 2026.

Gas Utilities

•
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate review activity for Arkansas Gas, Iowa Gas, Kansas Gas, and Nebraska Gas.

Corporate and Other

•
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding our corporate Revolving Credit Facility, October 2, 2025 debt offering and ATM program activity.

Results of Operations

Our discussion and analysis for the year ended December 31, 2025, compared to 2024, is included herein. For discussion and analysis for the year ended December 31, 2024, compared to 2023, please refer to Item 7 of Part II, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2024, which was filed with the SEC on February 12, 2025.

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.

2025 Compared to 2024

•
Electric Utilities’ operating income decreased $10.5 million primarily due to higher operating expenses, unplanned generation outages, lower transmission services revenues and unfavorable weather partially offset by new rates and rider recovery;

•
Gas Utilities’ operating income increased $49.5 million primarily due to new rates and rider recovery driven by the Arkansas Gas, Iowa Gas, Kansas Gas, and Nebraska Gas rate reviews and favorable weather partially offset by unfavorable retail customer usage and higher operating expenses;

•
Corporate and Other operating (loss) increased by $4.6 million primarily due to costs related to the pending Merger partially offset by a one-time favorable true-up from the consolidation of our Captive;

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•
Net interest expense increased $18.4 million due to higher interest rates on long-term debt, higher CP Program borrowings and lower interest income partially offset by higher AFUDC debt;

•
Other income, net increased $7.5 million primarily due to higher AFUDC equity driven by construction work-in-progress balances and higher investment income from our Captive;

•
Income tax (expense) increased $7.4 million primarily due to higher pre-tax income and a higher effective tax rate; and

•
Net income attributable to non-controlling interest decreased $2.4 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages.

Segment Operating Results

Non-GAAP Financial Measure

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 Electric and Gas 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 Electric and Gas 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 Electric and Gas 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 $100.9 million, $96.1 million, and $83.0 million for the years ended 2025, 2024, and 2023, respectively, for the Electric Utilities and $157.4 million, $148.7 million, and $154.7 million for the years ended 2025, 2024, and 2023, respectively, for the Gas Utilities.

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Electric Utilities

Operating results for the years ended December 31 for the Electric Utilities were as follows:

2025 Compared to 2024

•
Electric Utility margin increased as a result of:

•
Operations and maintenance expense increased primarily due to $5.5 million of higher outside services expenses, $4.8 million of expenses related to unplanned generation outages, $3.7 million of higher employee costs and $1.5 million from higher insurance expense primarily driven by higher excess liability premiums. Other unfavorable variances, none of which were individually significant, comprised the remainder of the difference when compared to the same period in 2024.

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

•
Taxes other than income taxes were comparable to 2024.

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Operating Statistics

(a)
The increase in industrial revenues and quantities sold for 2025 compared to 2024 was primarily driven by Wyoming Electric LPCS Tariff and BCIS Tariff customers.

(b)
Primarily related to 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 decrease in coal generation for 2025 compared to 2024 was primarily driven by unplanned outages at Wygen III.

(b)
The increase in total purchases for 2025 compared to 2024 was primarily driven by increased demand from Wyoming Electric LPCS Tariff and BCIS Tariff customers and unplanned outages at Wygen III as discussed in (a) above.

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(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. 2024 included unplanned outages at Wygen I and Pueblo Airport Generation #4-5.

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Gas Utilities

Operating results for the years ended December 31 for the Gas Utilities were as follows:

2025 Compared to 2024

•
Gas Utility margin increased as a result of:

•
Operations and maintenance expense increased primarily due to $3.2 million of higher insurance expense primarily driven by higher excess liability premiums, $1.3 million of increased bad debt expense attributable to higher customer billings and $1.3 million of higher IT-related costs. Other unfavorable variances, none of which were individually significant, comprised the remainder of the difference when compared to the same period in 2024.

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

•
Taxes other than income taxes were comparable to 2024.

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.

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(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)
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 their weather normalization mechanisms. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

Corporate and Other

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

Corporate and Other operating results for the years ended December 31 were as follows:

2025 Compared to 2024

•
Operating loss increased primarily due to $9.9 million of costs related to the pending Merger partially offset by a one-time favorable true-up from the consolidation of our Captive.

Consolidated Interest Expense, Other Income (Expense) and Income Tax (Expense)

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2025 Compared to 2024

•
Interest expense, net increased primarily due to higher interest rates on long-term debt, higher CP Program borrowings and lower interest income partially offset by higher AFUDC debt driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects;

•
Other income, net increased due to higher AFUDC equity driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects and higher investment income from our Captive;

•
Income tax (expense) increased primarily due to higher pre-tax income. The effective tax rate was 12.7% for 2025 and 11.3% for 2024. The higher effective tax rate was primarily driven by the non-deductibility of certain costs related to the pending Merger and lower flow-through tax benefits related to repair costs. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

Liquidity and Capital Resources

OVERVIEW

Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our operating activities, Revolving Credit Facility, CP Program, ATM, and ability to access the public and private capital markets through debt and equity securities offerings when necessary. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate.

We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption, during periods of high natural gas prices, and during the construction season, which typically peaks in spring and summer.

We believe that our cash on hand, operating cash flows, existing borrowing capacity, and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to support and grow our business.

The following table provides an informational summary of our liquidity and capital structure as of December 31:

(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 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

Future Financing Plans

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

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CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the years ended December 31:

Operating Activities:

2025 Compared to 2024

Net cash provided by operating activities was $45.9 million lower which was attributable to:

•
Total earnings (net income plus non-cash adjustments) were $37.7 million higher primarily as a result of new rates and rider recovery, increased demand from LPCS Tariff and BCIS Tariff customers partially offset by higher operating expenses and higher net interest expense.

•
Net inflows from changes in certain operating assets and liabilities were $86.0 million lower, primarily attributable to:

o
Cash outflows increased by approximately $50.3 million as a result of changes in accounts receivable and other current assets primarily due to higher natural gas in storage inventories driven by fluctuations in commodity prices;

o
Cash inflows decreased by approximately $4.8 million as a result of changes in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, remediation costs for our manufactured gas plant site in Iowa and changes in other working capital requirements; and

o
Cash inflows decreased by approximately $30.9 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of our Winter Storm Uri regulatory asset as recovery is now complete in most of our jurisdictions.

•
Cash outflows decreased $2.4 million from other operating activities.

Investing Activities:

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2025 Compared to 2024

Net cash used in investing activities was $82.2 million higher which was attributable to:

•
Cash outflows from capital expenditures (which are net of contributions in aid of construction) increased $75.6 million primarily as a result of the Ready Wyoming and Lange II projects and prior year receipts related to contributions in aid of construction for data center projects in Wyoming partially offset by prior year expenditures from Black Hills Energy Renewable Resources' acquisition of an RNG production facility at a landfill in Dubuque, Iowa; and

•
Cash outflows increased $6.6 million for other investing activities primarily due to higher AFUDC debt driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects.

Financing Activities:

2025 Compared to 2024

Net cash provided by financing activities was $364.7 million higher which was primarily attributable to:

•
Cash outflows increased $15.6 million due to the increased dividend rate per share and increased number of common shares outstanding;

•
Cash inflows increased $37.8 million due to increased issuances of common stock;

•
Net inflows from changes in short-term and long-term debt (repayments) borrowings increased $332.4 million due to timing of repayments and borrowing activity. Proceeds from the issuance of $450 million of senior unsecured notes in October 2025 were used to repay our $300 million senior unsecured notes in January 2026. In 2024, proceeds from the issuance of $450 million senior unsecured notes in May 2024, along with available cash and short-term borrowings under our existing facilities, were used to repay $600 million senior unsecured notes in August 2024;

•
Distributions to non-controlling interests decreased $7.6 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages; and

•
Cash outflows decreased by $2.5 million for other financing activities.

CAPITAL RESOURCES

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, subordinate debt securities, common stock, preferred stock, warrants, and other securities. Our current shelf registration statement expires in 2026 and we expect to file a new shelf registration statement to replace it.

Short-term Debt

For more information on our Revolving Credit Facility and CP Program, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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Long-term Debt

For information on our long-term debt, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Financial Covenants

The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of December 31, 2025. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Equity

For information regarding equity, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Utility Money Pool

As a utility holding company, we are required to establish a cash management program to address lending and borrowing activities between our utilities and the Company. We have established utility money pool agreements which address these requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool agreements, our utilities may, at their option, borrow and extend short-term loans to the utility money pool at market-based rates. While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.

CREDIT RATINGS

Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows from routine operations, and the credit ratings of counterparties. After assessing the current operating performance, liquidity, and credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing market rates for companies with comparable credit ratings. We note that credit ratings are not recommendations to buy, sell, or hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

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

(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 ratings of South Dakota Electric as of the date of this report:

(a)
On August 19, 2025, S&P affirmed A rating.

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CAPITAL REQUIREMENTS

Capital Expenditures

Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital expenditure program during the next five years. A key strategic focus is to modernize and harden our utility infrastructure to meet customers’ and communities’ varied energy needs and ensure the continued delivery of safe, reliable and cost-effective energy. In addition, we invest in the expansion, capacity, and integrity of our systems to meet customer growth. A significant portion of our capital expenditures are included in utility rate base and eligible for recovery from our utility customers with regulatory approval. Those capital expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.

To meet our electric customers’ continued expectations of high levels of reliability, a key strength of the Company, our Electric Utilities utilize an integrity program to ensure the timely repair and replacement of aging infrastructure.

Our Gas Utilities utilize a programmatic approach to system-wide pipeline replacement, particularly in high consequence areas. Under the programmatic approach, obsolete, at-risk and vintage materials are replaced in a proactive and systematic time frame. We have removed all cast- and wrought-iron from our natural gas transmission and distribution systems and continue to replace aging infrastructure through programs that prioritize safety and reliability for our customers. Our Gas Utilities are authorized to use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments, between rate reviews, which allow timely recovery of costs incurred in repairing and replacing the gas delivery systems with a return on the investment.

As of December 31, 2025, we estimate our five-year capital investment to be approximately $4.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure, supporting customer and community growth needs, and complying with safety requirements. Our actual 2025 and forecasted capital expenditures for the next five years from 2026 through 2030 are as follows:

(a)
Includes accruals for property, plant and equipment as disclosed as supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements in this Annual Report on Form 10-K. 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

Our historical capital expenditures by reportable segment are shown in Note 16 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Repayments of Indebtedness

For information relating to repayments of our short- and long-term debt and associated interest payments, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Unconditional Purchase Obligations

We have unconditional purchase obligations which include the energy and capacity costs associated with our PPAs, transmission services agreements, and natural gas capacity, transportation and storage agreements. Additionally, our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. For additional information. see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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Common Stock Dividends

2025 represented our 55th consecutive year of increasing dividends. In January 2026, our Board of Directors declared a quarterly dividend of $0.703 per share, equivalent to an annual dividend of $2.812 per share. We continue to target a dividend payout ratio of 55% to 65% of net income. A dependable and increasing dividend is an important component of our strategy for delivering long-term value for our shareholders. Pursuant to the Merger Agreement, we agreed we would not increase our dividends by more than 4% over the prior year dividend amount during the pendency of the Merger without NorthWestern's consent.

Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment opportunities, and other factors, and will be evaluated and approved by our Board of Directors.

Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

The table below provides our dividends paid, dividend payout ratio, and dividends paid per share for the three years ended December 31:

Defined Benefit Pension Plan

We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The unfunded status of the Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the Pension Plan is $42.2 million as of December 31, 2025, compared to $41.4 million as of December 31, 2024. See further information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Collateral Requirements

Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions, and the amounts owed by or to the counterparty. At December 31, 2025, we had sufficient liquidity to cover collateral that could be required to be posted under these contracts. The cash collateral we were required to post at December 31, 2025, was not material. See Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Guarantees

We provide various guarantees, which represent off-balance sheet commitments, supporting certain of our subsidiaries under specified agreements or transactions. For more information on these guarantees, see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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Critical Accounting Estimates

We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. We continue to closely monitor the macroeconomic environment and related impacts on our critical accounting estimates including, but not limited to, collectability of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-lived assets, and contingent liabilities. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual results may differ from our estimates and to the extent there are material differences between these estimates, judgments or assumptions, and actual results, our financial statements will be affected. We believe the following accounting estimates are the most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates and related disclosures with our Audit Committee.

The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description and Significant Accounting Policies” of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Regulation

Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or may not match our related costs and allowed return on invested capital at any given time.

Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.

To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers, and a state regulatory commission subsequently determines that such costs should not have been paid by the customers, we may be required to refund such costs.

As of December 31, 2025, and 2024, we had total regulatory assets of $394.7 million and $427.7 million, respectively, and total regulatory liabilities of $588.2 million and $568.7 million, respectively. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

Goodwill

We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns with our financial planning process.

Accounting standards for testing goodwill for impairment require the application of either a qualitative or quantitative assessment to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. Under either the qualitative or quantitative assessment, the estimated fair value of a reporting unit is compared with its carrying amount, including goodwill. If the carrying amount exceeds fair value, then an impairment loss would be recognized in an amount equal to that excess, limited to the amount of goodwill allocated to that reporting unit.

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Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industry. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as financial estimates from comparative peer companies and recent sales transactions for comparable assets within the utility and energy industry. Varying by reporting unit, weighted average cost of capital in the range of 6.7% to 7.2% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2025. Although 1.75% was used for a long-term growth rate projection, the short-term projected growth rate is higher with planned recovery of capital investments through rider mechanisms and rate reviews. Under the market approach, we estimate fair value using multiples derived from enterprise value to EBITDA for comparative peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.

The estimates and assumptions used in our impairment assessments are based on available market information and we believe they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated.

For the years ended December 31, 2025, 2024, and 2023, there were no impairment losses recorded. At December 31, 2025, the fair value exceeded the carrying value at all reporting units.

See Item 1A - Risk Factors and Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss.

The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax return in a different period than they are reported in the financial statements.

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would be made in the period such determination was made. These adjustments may increase or decrease earnings. Although we believe our assumptions, judgments, and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.

See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

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