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What changed in BLACK HILLS CORP /SD/'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of BLACK HILLS CORP /SD/'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+355 added−273 removedSource: 10-K (2026-02-11) vs 10-K (2025-02-12)

Top changes in BLACK HILLS CORP /SD/'s 2025 10-K

355 paragraphs added · 273 removed · 180 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

41 edited+13 added−13 removed39 unchanged
Biggest changeSystem Peak Demand for the Electric Utilities’ retail customers for each of the last three years are listed below: System Peak Demand (in MWs) 2024 2023 2022 Summer Winter Summer Winter Summer Winter Colorado Electric 394 311 411 297 410 334 South Dakota Electric 388 346 378 289 403 355 Wyoming Electric (a) 309 314 312 301 294 281 ____________________ (a) See Recent Developments section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 in this Annual Report on Form 10-K for discussion on recent Wyoming Electric peaks. 12 Table of Contents As of December 31, 2024, our Electric Utilities’ ownership interests in electric generating plants were as follows: Unit Fuel Type Location Ownership Interest % (c) Owned Nameplate Capacity (MWs) In Service Date Colorado Electric: Busch Ranch I Wind Pueblo, Colorado 50% 14.5 2012 Peak View (a) (b) Wind Pueblo, Colorado 100% 60.8 2016 Pueblo Airport Generation #1-2 Natural Gas Pueblo, Colorado 100% 200.0 2011 Pueblo Airport Generation CT #6 Natural Gas Pueblo, Colorado 100% 40.0 2016 AIP Diesel Diesel Oil Pueblo, Colorado 100% 10.0 2001 Diesel #1 and #3-5 Diesel Oil Pueblo, Colorado 100% 8.0 1964 Diesel #1-5 Diesel Oil Rocky Ford, Colorado 100% 10.0 1964 South Dakota Electric: Cheyenne Prairie Natural Gas Cheyenne, Wyoming 58% 58.0 2014 Corriedale (b) Wind Cheyenne, Wyoming 62% 32.5 2020 Wygen III Coal Gillette, Wyoming 52% 60.3 2010 Neil Simpson II Coal Gillette, Wyoming 100% 90.0 1995 Wyodak Plant Coal Gillette, Wyoming 20% 80.5 1978 Neil Simpson CT Natural Gas Gillette, Wyoming 100% 40.0 2000 Lange CT Natural Gas Rapid City, South Dakota 100% 40.0 2002 Ben French Diesel #1-5 Diesel Oil Rapid City, South Dakota 100% 10.0 1965 Ben French CTs #1-4 Natural Gas/Diesel Oil Rapid City, South Dakota 100% 100.0 1977-1979 Wyoming Electric: Cheyenne Prairie Natural Gas Cheyenne, Wyoming 42% 42.0 2014 Cheyenne Prairie CT Natural Gas Cheyenne, Wyoming 100% 40.0 2014 Corriedale (b) Wind Cheyenne, Wyoming 38% 20.0 2020 Wygen II Coal Gillette, Wyoming 100% 95.0 2008 Integrated Generation: Wygen I Coal Gillette, Wyoming 76.5% 68.9 2003 Pueblo Airport Generation #4-5 Natural Gas Pueblo, Colorado 50.1% (d) 200.0 2012 Busch Ranch I Wind Pueblo, Colorado 50% 14.5 2012 Busch Ranch II (b) Wind Pueblo, Colorado 100% 59.4 2019 Total MW Capacity 1,394.4 ____________________ (a) The PTCs for Peak View flow back to customers through the RESA and ECA mechanisms as a reduction to Colorado Electric’s margins.
Biggest changeAs of December 31, 2025, our Electric Utilities’ ownership interests in electric generating plants were as follows: Unit Fuel Type Location Ownership Interest % (c) Owned Nameplate Capacity (MWs) In Service Date Colorado Electric: Busch Ranch I Wind Pueblo, Colorado 50% 14.5 2012 Peak View (a) (b) Wind Pueblo, Colorado 100% 60.8 2016 Pueblo Airport Generation #1-2 Natural Gas Pueblo, Colorado 100% 200.0 2011 Pueblo Airport Generation CT #6 Natural Gas Pueblo, Colorado 100% 40.0 2016 AIP Diesel Diesel Oil Pueblo, Colorado 100% 10.0 2001 Diesel #1-5 Diesel Oil Rocky Ford, Colorado 100% 10.0 1964 South Dakota Electric: Cheyenne Prairie Natural Gas Cheyenne, Wyoming 58% 58.0 2014 Corriedale (b) Wind Cheyenne, Wyoming 62% 32.5 2020 Wygen III Coal Gillette, Wyoming 52% 60.3 2010 Neil Simpson II Coal Gillette, Wyoming 100% 90.0 1995 Wyodak Plant Coal Gillette, Wyoming 20% 80.5 1978 Neil Simpson CT Natural Gas Gillette, Wyoming 100% 40.0 2000 Lange CT Natural Gas Rapid City, South Dakota 100% 40.0 2002 Ben French Diesel #1-5 Diesel Oil Rapid City, South Dakota 100% 10.0 1965 Ben French CTs #1-4 Natural Gas/Diesel Oil Rapid City, South Dakota 100% 100.0 1977-1979 Wyoming Electric: Cheyenne Prairie Natural Gas Cheyenne, Wyoming 42% 42.0 2014 Cheyenne Prairie CT Natural Gas Cheyenne, Wyoming 100% 40.0 2014 Corriedale (b) Wind Cheyenne, Wyoming 38% 20.0 2020 Wygen II Coal Gillette, Wyoming 100% 95.0 2008 Integrated Generation: Wygen I Coal Gillette, Wyoming 76.5% 68.9 2003 Pueblo Airport Generation #4-5 Natural Gas Pueblo, Colorado 50.1% (d) 200.0 2012 Busch Ranch I Wind Pueblo, Colorado 50% 14.5 2012 Busch Ranch II (b) Wind Pueblo, Colorado 100% 59.4 2019 Total MW Capacity 1,386.4 ____________________ (a) The PTCs for Peak View flow back to customers through the RESA and ECA mechanisms as a reduction to Colorado Electric’s margins.
The following table summarizes the mechanisms we have in place for each of our Gas Utilities: Gas Utility Jurisdiction Cost Recovery Mechanisms EECR/DSM Integrity Additions Bad Debt Weather Normal Gas Cost (a) Revenue Decoupling Arkansas Gas ☑ ☑ ☑ ☑ ☑ Colorado Gas (b) ☑ ☑ RMNG (c) Iowa Gas ☑ ☑ ☑ Kansas Gas ☑ ☑ ☑ ☑ Nebraska Gas ☑ ☑ ☑ Wyoming Gas ☑ ☑ ☑ ____________________ (a) All of our Gas Utilities, except where the Choice Gas Program is the only option, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer between rate reviews.
The following table summarizes the mechanisms we have in place for each of our Gas Utilities: Gas Utility Jurisdiction Cost Recovery Mechanisms EECR/DSM Integrity Additions Bad Debt Weather Normal Gas Cost (a) Revenue Decoupling Arkansas Gas ☑ ☑ ☑ ☑ ☑ Colorado Gas ☑ ☑ RMNG (b) Iowa Gas ☑ ☑ ☑ Kansas Gas ☑ ☑ ☑ ☑ Nebraska Gas ☑ ☑ ☑ ☑ Wyoming Gas ☑ ☑ ☑ ____________________ (a) All of our Gas Utilities, except where the Choice Gas Program is the only option, have GCAs that allow us to pass the prudently-incurred cost of gas and certain services through to the customer between rate reviews.
See a summary of key operating statistics in the Gas Utilities segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K. 16 Table of Contents Utility Regulation Characteristics Our Utilities are subject to regulation by a number of federal, state and other organizations, including, but not limited to, the following: • state public utility commissions, which have jurisdiction over services and facilities, rates and charges, accounting, valuation of property, depreciation rates, and various other matters; • the FERC, which oversees the acquisition and disposition of generation, transmission and other facilities, transmission of electricity and natural gas in interstate commerce, proposals to build and operate interstate natural gas pipelines and storage facilities, and wholesale purchases and sales of electric energy, among other things; • the NERC, which, through its regional entities, establishes and enforces mandatory reliability standards, subject to approval by the FERC, to ensure the reliability of the U.S. electric transmission and generation system, and to prevent major system blackouts; • the EPA, which has the responsibility to maintain and enforce national standards under a variety of environmental laws, in some cases delegating authority to state agencies.
See a summary of key operating statistics in the Gas Utilities segment operating results within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K. 17 Table of Contents Utility Regulation Characteristics Our Utilities are subject to regulation by a number of federal, state and other organizations, including, but not limited to, the following: • state public utility commissions, which have jurisdiction over services and facilities, rates and charges, accounting, valuation of property, depreciation rates, and various other matters; • the FERC, which oversees the acquisition and disposition of generation, transmission and other facilities, transmission of electricity and natural gas in interstate commerce, proposals to build and operate interstate natural gas pipelines and storage facilities, and wholesale purchases and sales of electric energy, among other things; • the NERC, which, through its regional entities, establishes and enforces mandatory reliability standards, subject to approval by the FERC, to ensure the reliability of the U.S. electric transmission and generation system, and to prevent major system blackouts; • the EPA, which has the responsibility to maintain and enforce national standards under a variety of environmental laws, in some cases delegating authority to state agencies.
ITEM 1. BUSINESS History and Organization Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us”, or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota (incorporated in South Dakota in 1941).
ITEM 1. BUSINESS History and Organization Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” "BHC," “we,” “us”, or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota (incorporated in South Dakota in 1941).
Our Field Career Path Program (FCPP) promotes career growth for our frontline customer-facing employees through established standards of knowledge, skills, abilities, and performance. Employee Safety and Wellness Safety is one of our company values, a top priority in all we do and deeply embedded in our culture.
Our Field Career Path Program promotes career growth for our frontline customer-facing employees through established standards of knowledge, skills, abilities, and performance. Employee Safety and Wellness Safety is one of our company values, a top priority in all we do and deeply embedded in our culture.
(b) South Dakota Electric transmission line miles include 43 miles within the Common Use System. Material transmission services agreements are included in our disclosures in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Seasonal Variations of Business. Our Electric Utilities are seasonal businesses and weather patterns may impact their operating results.
(b) South Dakota Electric transmission line miles include 131 miles within the Common Use System. Material transmission services agreements are included in our disclosures in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Seasonal Variations of Business. Our Electric Utilities are seasonal businesses and weather patterns may impact their operating results.
Recent Tariff Filings See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current regulatory activity. 19 Table of Contents FERC The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce.
Recent Tariff Filings See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current regulatory activity. 20 Table of Contents FERC The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce.
We operate our business in the United States, reporting our operating results through our Electric Utilities and Gas Utilities segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 225,000 electric utility customers in Colorado, Montana, South Dakota, and Wyoming.
We operate our business in the United States, reporting our operating results through our Electric Utilities and Gas Utilities segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Our Electric Utilities segment generates, transmits and distributes electricity to approximately 227,000 electric utility customers in Colorado, Montana, South Dakota, and Wyoming.
(b) This facility qualifies for PTCs at $29/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service. (c) Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
(b) This facility qualifies for PTCs at $30/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service. (c) Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Black Hills Energy Services provides natural gas supply to approximately 51,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe.
Black Hills Energy Services provides natural gas supply to approximately 48,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe.
(c) South Dakota Electric has WPSC authorization to accumulate certain energy efficiency costs in a regulatory asset with determination of recovery to be made in the next rate review. 18 Table of Contents Gas Utilities The following table provides regulatory information for each of our Gas Utilities: Subsidiary Jurisdiction Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Authorized Rate Base (in millions) Effective Date Additional Regulatory Mechanisms Arkansas Gas (a) AR 9.85% 7.07% (b) 54%/46% $823.4 (c) 10/2024 GCA, Safety and Integrity Rider, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment, Tax Adjustment Rider Colorado Gas (a) CO 9.30% 6.90% 49%/51% $378.4 5/2024 GCA, DSM, Gas Price Risk Management Rider, Energy Assistance Benefit Charge RMNG CO 9.50%-9.70% 6.93% 48%-50%/ 50%-52% $209.3 7/2023 Liquids/Off-system/Market Center Services Revenue Sharing Iowa Gas IA Black-box Settlement 7.21% Black-box Settlement $393.8 1/2025 GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing Kansas Gas KS Black-box Settlemen t Black-box Settlement Black-box Settlemen t Black-box Settlemen t 1/2022 GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Gas Supply Optimization revenue sharing Nebraska Gas (d) NE 9.50% 6.71% 50%/50% $504.2 (e) 3/2021 GCA, Cost of Bad Debt Collected through GCA, Choice Gas Program, SSIR, Bad Debt expense recovered through Choice Supplier Fee, Line Locates Surcharge, HEAT Program Wyoming Gas (a)(d) WY 9.85% 7.33% 49%/51% $450.8 2/2024 GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program ____________________ (a) For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
(c) South Dakota Electric has WPSC authorization to accumulate certain energy efficiency costs in a regulatory asset with determination of recovery to be made in the next rate review. 19 Table of Contents Gas Utilities The following table provides regulatory information for each of our Gas Utilities: Subsidiary Jurisdiction Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Authorized Rate Base (in millions) Effective Date Additional Regulatory Mechanisms Arkansas Gas (a) AR 9.85% 7.07% (b) 54%/46% $823.4 (c) 10/2024 GCA, Safety and Integrity Rider, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment, Tax Adjustment Rider Colorado Gas CO 9.30% 6.90% 49%/51% $378.4 5/2024 GCA, DSM, Gas Price Risk Management Rider, Energy Assistance Benefit Charge RMNG CO 9.50%-9.70% 6.93% 48%-50%/ 50%-52% $209.3 7/2023 Liquids/Off-system/Market Center Services Revenue Sharing Iowa Gas (a) IA Black-box Settlement 7.21% Black-box Settlement $393.8 1/2025 GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing Kansas Gas (a) KS Black-box Settlemen t Black-box Settlement Black-box Settlemen t Black-box Settlemen t 8/2025 GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Gas Supply Optimization revenue sharing Nebraska Gas (a)(d) NE 9.85% 7.29% 49%/51% $781.3 (e) 1/2026 GCA, Cost of Bad Debt Collected through GCA, Choice Gas Program, SSIR, Bad Debt expense recovered through Choice Supplier Fee, HEAT Program, Weather Normalization Adjustment Wyoming Gas (d) WY 9.85% 7.33% 49%/51% $450.8 2/2024 GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program ____________________ (a) For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, cooling demand is often greater in the summer and heating demand is often greater in the winter. 14 Table of Contents Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas.
Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as market price. In particular, cooling demand is often greater in the summer and heating demand is often greater in the winter. Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas.
We produced approximately 3.7 million tons of coal in 2024. The mine provides low-sulfur coal directly to these five power plants via a conveyor belt system, minimizing transportation costs. The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.19 per MMBtu for year ended December 31, 2024) when compared to alternatives.
We produced approximately 3.3 million tons of coal in 2025. The mine provides low-sulfur coal directly to these five power plants via a conveyor belt system, minimizing transportation costs. The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.26 per MMBtu for year ended December 31, 2025) when compared to alternatives.
Demand for natural gas can also be impacted by summer temperatures and precipitation, which can affect demand for irrigation. Competition. We generally have limited competition for the retail distribution of natural gas in our service areas. Various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate.
Demand for natural gas can also be impacted by summer temperatures and precipitation, which can affect demand from agricultural customers. Competition. We generally have limited competition for the retail distribution of natural gas in our service areas. Various restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate.
Our development and retention efforts include internal and external skills training, career development programs, and competitive compensation. Our compensation programs are designed to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective, and legally compliant. We monitor employee engagement through regular engagement surveys to gather valuable insights and feedback.
Our development and retention efforts include skills training, development programs, and competitive compensation. Our compensation programs are designed to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective, and legally compliant. We monitor employee engagement through engagement surveys to gather valuable insights and feedback.
Our Team As of December 31, 2024 As of December 31, 2023 Total employees 2,841 2,874 Women in executive leadership positions (a) 32% 29% Gender diversity (women as a % of total employees) 24% 24% Represented by a union 25% 25% Military veterans 9% 10% Ethnic diversity (non-white employees as a % of total) 15% 15% For the year ended December 31, 2024 For the year ended December 31, 2023 Number of external hires 303 293 External hires gender diversity (as a % of total external hires) 29% 27% External hires ethnic diversity (as a % of total external hires) 25% 24% Turnover rate (b) 11% 12% Retirement rate 3% 3% ____________________ (a) Executive leadership positions are defined as positions with Vice President, Senior Vice President, or Chief in their title.
Our Team As of December 31, 2025 As of December 31, 2024 Total employees 2,795 2,841 Women in executive leadership positions (a) 30% 32% Gender diversity (women as a % of total employees) 24% 24% Represented by a union 25% 25% Military veterans 10% 9% Ethnic diversity (non-white employees as a % of total) 15% 15% For the year ended December 31, 2025 For the year ended December 31, 2024 Number of external hires 306 303 External hires gender diversity (as a % of total external hires) 25% 29% External hires ethnic diversity (as a % of total external hires) 20% 25% Turnover rate (b) 12% 11% Retirement rate 3% 3% ____________________ (a) Executive leadership positions are defined as positions with Vice President, Senior Vice President, or Chief in their title.
Our Electric Utilities own 1,394 MW of generation and 9,196 miles of electric transmission and distribution lines. Our Gas Utilities segment serves approximately 1,128,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming.
Our Electric Utilities own 1,386 MW of generation and 9,478 miles of electric transmission and distribution lines. Our Gas Utilities segment serves approximately 1,138,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming.
Our Electric Utilities generate, transmit, and distribute electricity to our retail customers. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our retail customers. We also sell excess power to other utilities and marketing companies, including our affiliates.
Electric Utilities We conduct electric utility operations through our Colorado, South Dakota, and Wyoming subsidiaries. Our Electric Utilities generate, transmit, and distribute electricity to our retail customers. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our retail customers. We also sell excess power to other utilities and marketing companies, including our affiliates.
For the year ended December 31, 2024 Days Away, Restricted, or Transferred (incidents per 200,000 hours worked) 1.0 Proactive Safety Activities per Employee 6 % of injuries reported within 1 day 91.5% 22 Table of Contents
For the year ended December 31, 2025 Days Away, Restricted, or Transferred (incidents per 200,000 hours worked) 0.6 Proactive Safety Activities per Employee 9 % of injuries reported within 1 day 96.3% 23 Table of Contents
Transmission investments are recovered from wholesale transmission customers under the FERC Formula Transmission rate. The rate base associated with FERC assets is not displayed separate from that collected through the state recovery mechanisms, to avoid double counting. Authorized totals for Colorado Electric and Wyoming Electric include amounts recovered through base rates and the authorized regulatory mechanisms.
(b) For both Wyoming Electric and Colorado Electric retail customers, transmission investments are recovered through retail rates rather than FERC Transmission Tariffs. Transmission investments are recovered from wholesale transmission customers under the FERC Formula Transmission rate. The rate base associated with FERC assets is not displayed separate from that collected through the state recovery mechanisms, to avoid double counting.
Every leader is responsible for creating and implementing an action plan based on their team’s engagement survey results, while the company develops broader action plans to address organization-wide opportunities. Our career development programs include management onboarding, leadership development programs, mentoring programs, stretch opportunities, and more. Internal training opportunities include corporate-wide and specialized training opportunities for different job functions.
Every leader creates and implements action plans based on their team’s engagement survey results, and the company develops broader action plans to address organization-wide opportunities. Our development programs include management onboarding, leadership development, mentoring, stretch opportunities, and more. Internal development opportunities include corporate-wide and specialized learning for different job functions.
Total Employees Number of Employees As of December 31, 2024 Electric Utilities 423 Gas Utilities 1,175 Corporate and Other 1,243 Total 2,841 At December 31, 2024, approximately 18% of our total employees and 20% of our Electric and Gas Utilities employees were eligible for retirement (age 55 with at least 5 years of service). 21 Table of Contents Collective Bargaining Agreements At December 31, 2024, certain employees of our Electric Utilities and Gas Utilities were covered by the collective bargaining agreements as shown in the table below.
Total Employees Number of Employees As of December 31, 2025 Electric Utilities 421 Gas Utilities 1,184 Corporate and Other 1,190 Total 2,795 At December 31, 2025, approximately 18% of our total employees and 19% of our Electric and Gas Utilities employees were eligible for retirement (age 55 with at least 5 years of service). 22 Table of Contents Collective Bargaining Agreements At December 31, 2025, certain employees of our Electric Utilities and Gas Utilities were covered by the collective bargaining agreements as shown in the table below.
We have undertaken initiatives to meet current requirements and to prepare for anticipated future regulations, reduce GHG emissions, and respond to state renewable and energy efficiency goals.
We have undertaken initiatives to meet current requirements and to prepare for anticipated future regulations, reduce GHG emissions, and respond to state renewable and energy efficiency goals. Compliance with future environmental regulations could result in substantial cost.
As of December 31, Retail Customers by Customer Class 2024 2023 2022 Residential 882,232 871,930 864,038 Commercial 85,594 84,917 85,203 Industrial 2,174 2,179 2,189 Transportation 158,355 157,367 155,685 Total Natural Gas Retail Customers at End of Year 1,128,355 1,116,393 1,107,115 As of December 31, Retail Customers by Business Unit 2024 2023 2022 Arkansas Gas 189,240 186,216 183,270 Colorado Gas 215,190 211,155 208,060 Iowa Gas 164,134 163,281 162,801 Kansas Gas 120,225 119,407 118,599 Nebraska Gas 304,429 302,167 301,007 Wyoming Gas 135,137 134,167 133,378 Total Natural Gas Retail Customers at End of Year 1,128,355 1,116,393 1,107,115 We procure natural gas for our distribution customers from a diverse mix of producers, processors, and marketers and generally use financial hedges, physical fixed-price purchases, and market-based price purchases to achieve dollar-cost averaging within our natural gas portfolio.
As of December 31, Retail Customers by Customer Class 2025 2024 2023 Residential 891,484 882,232 871,930 Commercial 86,299 85,594 84,917 Industrial 2,219 2,174 2,179 Transportation 158,150 158,355 157,367 Total Natural Gas Retail Customers at End of Year 1,138,152 1,128,355 1,116,393 16 Table of Contents As of December 31, Retail Customers by Business Unit 2025 2024 2023 Arkansas Gas 191,538 189,240 186,216 Colorado Gas 218,140 215,190 211,155 Iowa Gas 165,049 164,134 163,281 Kansas Gas 120,987 120,225 119,407 Nebraska Gas 306,452 304,429 302,167 Wyoming Gas 135,986 135,137 134,167 Total Natural Gas Retail Customers at End of Year 1,138,152 1,128,355 1,116,393 We procure natural gas for our distribution customers from a diverse mix of producers, processors, and marketers and generally use financial hedges, physical fixed-price purchases, and market-based price purchases to achieve dollar-cost averaging within our natural gas portfolio.
As of December 31, Retail Customers by Customer Class 2024 2023 2022 Residential 192,716 190,776 188,921 Commercial 31,210 30,491 30,404 Industrial 83 84 82 Municipal 1,079 989 1,024 Total Electric Retail Customers at End of Year 225,088 222,340 220,431 As of December 31, Retail Customers by Business Unit 2024 2023 2022 Colorado Electric 101,455 100,907 100,573 South Dakota Electric 77,941 76,479 75,169 Wyoming Electric 45,692 44,954 44,689 Total Electric Retail Customers at End of Year 225,088 222,340 220,431 Capacity and Demand.
As of December 31, Retail Customers by Customer Class 2025 2024 2023 Residential 194,735 192,716 190,776 Commercial 31,240 31,210 30,491 Industrial 86 83 84 Municipal 1,039 1,079 989 Total Electric Retail Customers at End of Year 227,100 225,088 222,340 As of December 31, Retail Customers by Business Unit 2025 2024 2023 Colorado Electric 102,152 101,455 100,907 South Dakota Electric 78,976 77,941 76,479 Wyoming Electric 45,972 45,692 44,954 Total Electric Retail Customers at End of Year 227,100 225,088 222,340 13 Table of Contents Capacity and Demand.
The renewable energy from these PPAs is used to serve our expanding partnerships with LPCS customers. 13 Table of Contents Our Electric Utilities’ weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh for the years ended December 31 were as follows: Fuel and Purchased Power (dollars per MWh) 2024 2023 2022 Coal $ 13.87 $ 13.40 $ 12.76 Natural Gas 15.64 20.20 37.09 Wind — — — Total Generated Weighted Average Fuel Cost 12.90 14.27 17.57 Coal, Natural Gas, Diesel Oil and Other Market Purchases 67.04 55.61 66.35 Wind and Solar Purchases 38.70 34.99 33.78 Total Purchased Power Weighted Average Cost 52.79 51.68 61.56 Total Weighted Average Fuel and Purchased Power Cost $ 24.66 $ 25.39 $ 32.82 Purchased Power.
Our Electric Utilities’ weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh for the years ended December 31 were as follows: Fuel and Purchased Power (dollars per MWh) 2025 2024 2023 Coal $ 16.59 $ 13.87 $ 13.40 Natural Gas 18.00 15.64 20.20 Wind — — — Total Generated Weighted Average Fuel Cost 15.28 12.90 14.27 Coal, Natural Gas, Diesel Oil and Other Market Purchases 51.13 67.04 55.61 Wind and Solar Purchases 38.74 38.70 34.99 Total Purchased Power Weighted Average Cost 46.24 52.79 51.68 Total Weighted Average Fuel and Purchased Power Cost $ 26.98 $ 24.66 $ 25.39 Purchased Power.
(b) The diesel oil-fueled generating units are generally used as supplemental peaking units. Power generated from these units, as a percentage of total power supply, was 0.0% for each of the years presented.
Power generated from these units, as a percentage of total power supply, was 0.0% for each of the years presented.
Utility Number of Employees Union Affiliation Expiration Date of Collective Bargaining Agreement Colorado Electric 109 IBEW Local 667 April 15, 2027 South Dakota Electric 118 IBEW Local 1250 March 31, 2027 South Dakota Electric 6 IBEW Local 1250 September 29, 2028 Wyoming Electric 28 IBEW Local 111 June 30, 2029 Total Electric Utilities 261 Iowa Gas 127 IBEW Local 204 January 31, 2026 Kansas Gas 15 Communications Workers of America, AFL-CIO Local 6407 December 31, 2029 Nebraska Gas 92 IBEW Local 244 March 13, 2025 Nebraska Gas 127 CWA Local 7476 October 30, 2026 Wyoming Gas 13 IBEW Local 111 June 30, 2029 Wyoming Gas 81 CWA Local 7476 October 30, 2026 Total Gas Utilities 455 Total 716 Development and Retention Developing and retaining talent is critical to our continued success.
Utility Number of Employees Union Affiliation Expiration Date of Collective Bargaining Agreement Colorado Electric 101 IBEW Local 667 April 15, 2027 South Dakota Electric 119 IBEW Local 1250 March 31, 2027 South Dakota Electric 7 IBEW Local 1250 September 29, 2028 Wyoming Electric 30 IBEW Local 111 June 30, 2029 Total Electric Utilities 257 Iowa Gas 124 IBEW Local 204 May 1, 2026 Kansas Gas 15 CWA Local 6423 December 31, 2029 Nebraska Gas 92 IBEW Local 244 March 12, 2030 Nebraska Gas 124 CWA Local 7476 October 30, 2026 Wyoming Gas 14 IBEW Local 111 June 30, 2029 Wyoming Gas 76 CWA Local 7476 October 30, 2026 Total Gas Utilities 445 Total 702 Development and Retention Developing, engaging, and retaining talent is critical to our continued success.
These tariffs allow the utility a return on the investment. 17 Table of Contents Electric Utilities The following table provides regulatory information for each of our Electric Utilities: Subsidiary Jurisdiction Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Authorized Rate Base (in millions) Effective Date Additional Regulatory Mechanisms Percentage of Power Marketing Profit Shared with Customers Colorado Electric (c) CO 9.37% 7.43% 48%/52% $653.7 (a) 1/2017 ECA, TCA, PCCA, EECR/DSM, RESA, TEPR, Energy Assistance Benefit Charge, CEPR 90% CO 9.37% 6.02% 67%/33% $57.9 1/2017 CACJA Adjustment Rider N/A FERC 9.80% 6.45% 53%/47% (a) 9/2022 FERC Transmission Tariff N/A South Dakota Electric WY 9.90% 8.13% 47%/53% $46.8 10/2014 ECA 65% SD Black-box Settlement 7.76% Black-box Settlement $543.9 10/2014 ECA, TFA, EIA 70% FERC 10.80% 8.76% 43%/57% $200.4 (b) 2/2009 FERC Transmission Tariff N/A Wyoming Electric WY 9.75% 7.48% 48%/52% $551.2 (a) 3/2023 PCA, EECR/DSM, Rate Base Recovery on Acquisition Adjustment, TCAM N/A FERC 9.90% 8.77% 44%/56% (a) 1/2019 FERC Transmission Tariff N/A ____________________ (a) For both Wyoming Electric and Colorado Electric retail customers, transmission investments are recovered through retail rates rather than FERC Transmission Tariffs.
In addition, some jurisdictions allow us to recover certain costs or earn a return on capital investments placed in service between base rate reviews through approved rider tariffs, such as energy efficiency plan costs and system safety and integrity investments. 18 Table of Contents Electric Utilities The following table provides regulatory information for each of our Electric Utilities: Subsidiary Jurisdiction Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Authorized Rate Base (in millions) Effective Date Additional Regulatory Mechanisms Percentage of Power Marketing Profit Shared with Customers Colorado Electric (a) CO 9.30%-9.50% 6.9% 51%-53%/ 47%-49% $663.8 (b) 3/2025 ECA, TCA, PCCA, EECR/DSM, RESA, TEPR, Energy Assistance Benefit Charge, CEPR 90% FERC 9.80% 6.45% 53%/47% (b) 9/2022 FERC Transmission Tariff N/A South Dakota Electric WY 9.90% 8.13% 47%/53% $46.8 10/2014 ECA, EECR/DSM 65% SD Black-box Settlement 7.76% Black-box Settlement $543.9 10/2014 ECA, TFA, EIA 70% FERC 10.80% 8.76% 43%/57% $207.3 (c) 2/2009 FERC Transmission Tariff N/A Wyoming Electric WY 9.75% 7.48% 48%/52% $551.2 (a) 3/2023 PCA, EECR/DSM, Rate Base Recovery on Acquisition Adjustment, TCAM N/A FERC 9.90% 8.77% 44%/56% (b) 1/2019 FERC Transmission Tariff N/A ____________________ (a) For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
In addition to company-owned regulated underground natural gas storage assets in Arkansas, Colorado, and Wyoming, we also contract with third-party transportation providers for natural gas storage service to provide gas supply during the winter heating season and to meet peak day customer demand for natural gas. 15 Table of Contents The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities as of December 31, 2024: Working Capacity (Mcf) Cushion Gas (Mcf) Total Capacity (Mcf) Maximum Daily Withdrawal Capability (Mcfd) Arkansas Gas 8,442,700 13,149,040 21,591,740 196,000 Colorado Gas 2,361,495 6,164,715 8,526,210 30,000 Wyoming Gas 5,733,900 17,545,600 23,279,500 36,000 Total 16,538,095 36,859,355 53,397,450 262,000 The following table summarizes certain information regarding our system infrastructure as of December 31, 2024: Intrastate Gas Transmission Pipelines Gas Distribution Mains Gas Distribution Service Lines (in Line Miles) Arkansas Gas 875 5,317 1,411 Colorado Gas 682 7,290 2,245 Iowa Gas 173 2,938 3,729 Kansas Gas 339 3,096 1,510 Nebraska Gas 1,313 8,658 2,967 Wyoming Gas 1,266 3,618 1,745 Total 4,648 30,917 13,607 Seasonal Variations of Business.
The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities as of December 31, 2025: Working Capacity (Mcf) Cushion Gas (Mcf) Total Capacity (Mcf) Maximum Daily Withdrawal Capability (Mcfd) Arkansas Gas 8,442,700 13,149,040 21,591,740 196,000 Colorado Gas 2,361,495 6,164,715 8,526,210 30,000 Wyoming Gas 5,733,900 17,545,600 23,279,500 36,000 Total 16,538,095 36,859,355 53,397,450 262,000 The following table summarizes certain information regarding our system infrastructure as of December 31, 2025: Intrastate Gas Transmission Pipelines Gas Distribution Mains Gas Distribution Service Lines (in Line Miles) Arkansas Gas 875 5,221 1,441 Colorado Gas 667 7,238 1,881 Iowa Gas 177 2,952 2,900 Kansas Gas 304 3,107 1,524 Nebraska Gas 1,313 8,712 3,091 Wyoming Gas 1,245 3,631 3,142 Total 4,581 30,861 13,979 Seasonal Variations of Business.
Nearly all of the mine’s production is sold to our on-site generation facilities under long-term supply contracts. As of December 31, 2024, we estimated our recoverable reserves to be approximately 175 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering analyses.
As of December 31, 2025, we estimated our recoverable reserves to be approximately 172 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering analyses. The recoverable reserve life is equal to approximately 51 years at the current production levels. Transmission and Distribution.
(b) Includes $183.3 million in 2024 rate base for the 2024 Projected Common Use System formula rate that is updated annually and $17.1 million in rate base for the Transmission Tie that is based on the approved stated rate from 2005.
Authorized totals for Colorado Electric and Wyoming Electric include amounts recovered through base rates and the authorized regulatory mechanisms. (c) Includes $190.2 million in 2025 rate base for the 2025 Projected Common Use System formula rate that is updated annually and $17.1 million in rate base for the Transmission Tie that is based on the approved stated rate from 2005.
If we fail to comply with applicable statutes and the PHMSA Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines. Environmental Matters We have clean energy goals to reduce GHG emissions that are based on prudent and proven solutions while minimizing cost impacts to and ensuring safety of our customers.
If we fail to comply with applicable statutes and the PHMSA Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines. Environmental Matters We are subject to significant state and federal environmental regulations that encourage the use of clean energy technologies and regulate emissions of GHGs.
We also jointly operate an electric transmission system, referred to as the Common Use System, with Basin Electric Power Cooperative and Powder River Energy Corporation. Each participant in the Common Use System individually owns assets that are operated together for a single system. The Common Use System also provides transmission service to our Transmission Tie.
Each participant in the Common Use System individually owns assets that are operated together for a single system. The Common Use System also provides transmission service to our Transmission Tie. South Dakota Electric owns 35% of the Transmission Tie.
Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended December 31 was as follows: Power Supply 2024 2023 2022 Coal 32.5 % 35.0 % 35.1 % Natural Gas 29.4 % 26.4 % 18.8 % Wind (a) 8.6 % 8.9 % 11.4 % Total Generated (b) 70.5 % 70.3 % 65.3 % Coal, Natural Gas, Diesel Oil and Other Market Purchases 14.7 % 24.1 % 29.6 % Wind and Solar Purchases (c) 14.8 % 5.6 % 5.1 % Total Purchased 29.5 % 29.7 % 34.7 % Total 100.0 % 100.0 % 100.0 % ____________________ (a) Wind generation decreased due to the sale of Northern Iowa Windpower assets in March 2023.
(d) Non-controlling interest is discussed in Note 12 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 14 Table of Contents Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended December 31 was as follows: Power Supply 2025 2024 2023 Coal 25.5 % 32.5 % 35.0 % Natural Gas 29.3 % 29.4 % 26.4 % Wind 7.4 % 8.6 % 8.9 % Total Generated (a) 62.2 % 70.5 % 70.3 % Coal, Natural Gas, Diesel Oil and Other Market Purchases 22.9 % 14.7 % 24.1 % Wind and Solar Purchases 14.9 % 14.8 % 5.6 % Total Purchased 37.8 % 29.5 % 29.7 % Total 100.0 % 100.0 % 100.0 % ____________________ (a) The diesel oil-fueled generating units are generally used as supplemental peaking units.
At December 31, 2024, our Electric Utilities owned the electric transmission and distribution lines shown below: Utility State Transmission (a) Distribution (in Line Miles) Colorado Electric Colorado 655 3,222 South Dakota Electric (b) South Dakota, Wyoming 1,234 2,627 Wyoming Electric Wyoming 88 1,370 1,977 7,219 ____________________ (a) Electric transmission line miles include voltages of 69 kV and above.
The Transmission Tie is further discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 15 Table of Contents At December 31, 2025, our Electric Utilities owned the electric transmission and distribution lines shown below: Utility State Transmission (a) Distribution (in Line Miles) Colorado Electric Colorado 655 3,229 South Dakota Electric (b) South Dakota, Wyoming 1,193 2,662 Wyoming Electric Wyoming 366 1,373 2,214 7,264 ____________________ (a) Electric transmission line miles include voltages of 69 kV and above.
Our Gas Utilities own and operate 4,648 miles of intrastate gas transmission pipelines and 44,524 miles of gas distribution mains and service lines, seven natural gas storage sites, more than 50,000 horsepower of compression, and 516 miles of gathering lines. Electric Utilities We conduct electric utility operations through our Colorado, South Dakota, and Wyoming subsidiaries.
Our Gas Utilities own and operate 4,581 miles of intrastate gas transmission pipelines and 44,840 miles of gas distribution mains and service lines, seven natural gas storage sites, more than 50,000 horsepower of compression, and 494 miles of gathering lines. Proposed Merger with NorthWestern BHC and NorthWestern entered into an all-stock business combination on August 18, 2025.
The recoverable reserve life is equal to approximately 47 years at the current production levels. Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less).
Through our Electric Utilities, we own electric transmission and distribution systems composed of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly operate an electric transmission system, referred to as the Common Use System, with Basin Electric Power Cooperative and Powder River Energy Corporation.
We continually assess risk and develop mitigation strategies to manage and ensure compliance across the enterprise successfully and responsibly. For additional information on environmental matters, see Item 1A and Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
For additional information on environmental matters, see Item 1A - Risk Factors and Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 21 Table of Contents Clean Energy Goals In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities by 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities.
(c) For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
The combined company will serve approximately 0.7 million electric utility customers and 1.5 million gas utility customers across eight states. See additional information in Item 1A - Risk Factors and Note 17 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
We are currently evaluating the impact of these rules through our integrated resource plans and believe that costs incurred as a result of the new rules will be recoverable through our regulatory mechanisms. Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies.
We will evaluate the impacts of the final rule at that time. Environmental risk changes frequently with the implementation of new or modified regulations, changing stakeholder interests and needs, and through the introduction of innovative work practices and technologies. We continually assess risk and develop mitigation strategies to manage and ensure compliance across the enterprise successfully and responsibly.
Removed
(d) Non-controlling interest is discussed in Note 12 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Added
The transaction is intended to be tax-free and expected to close in the second half of 2026, subject to the satisfaction or waiver of certain closing conditions, including approvals from the FERC, MPSC, NPSC and SDPUC, clearance under the HSR Act, consent of the FCC, and approval from each company's shareholders.
Removed
(c) Renewable energy purchases increased in 2024 primarily due to Wyoming Electric entering into a new wind PPA effective December 2023 and a new solar energy PPA effective March 2024.
Added
System Peak Demand for the Electric Utilities’ retail customers for each of the last three years are listed below: System Peak Demand (in MWs) 2025 2024 2023 Summer Winter Summer Winter Summer Winter Colorado Electric 396 299 394 311 411 297 South Dakota Electric 379 343 388 346 378 289 Wyoming Electric (a) 379 375 309 314 312 301 ____________________ (a) See Recent Developments section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 in this Annual Report on Form 10-K for discussion on recent Wyoming Electric peaks.
Removed
South Dakota Electric owns 35% of the Transmission Tie. The Transmission Tie is further discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Added
Nearly all of the mine’s production is sold to our on-site generation facilities under long-term supply contracts. Approximately one-half of the mine's production is sold under cost-plus contracts with affiliates.
Removed
In addition, some jurisdictions allow us to recover certain costs or earn a return on capital investments placed in service between base rate reviews through approved rider tariffs, such as energy efficiency plan costs and system safety and integrity investments.
Added
In addition to company-owned regulated underground natural gas storage assets in Arkansas, Colorado, and Wyoming, we also contract with third-party transportation providers for natural gas storage service to provide gas supply during the winter heating season and to meet peak day customer demand for natural gas.
Removed
(b) Colorado Gas's SSIR was approved by the CPUC for a three-year term, effective January 1, 2022 to December 31, 2024. The SSIR was not extended during the most recent rate review. (c) RMNG does not have retail customers and therefore, does not have typical cost recovery mechanisms.
Added
(b) RMNG does not have retail customers and, therefore, does not have typical cost recovery mechanisms.
Removed
See more information in Key Elements of our Business Strategy within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K. We are subject to significant state and federal environmental regulations that encourage the use of clean energy technologies and regulate emissions of GHGs.
Added
On June 11, 2025, the EPA proposed to repeal the GHG reduction requirements commonly referred to as the Clean Power Plan 2.0 which were finalized by the prior administration on May 9, 2024.
Removed
Compliance with future environmental regulations could result in substantial cost. 20 Table of Contents In July of 2019, the EPA adopted the Affordable Clean Energy rule, which required states to develop plans by 2022 for GHG reductions from coal-fired power plants.
Added
Clean Power Plan 2.0 requirements, which established GHG control requirements for existing coal and natural gas fired generation beginning January 1, 2030, are currently in effect as the U.S. Supreme Court denied a motion to stay them. The EPA is anticipated to finalize their proposal in the first half of 2026.
Removed
On May 23, 2023, the EPA proposed to repeal the Affordable Clean Energy rule and at the same time issued a replacement rule to establish emissions limits for GHG emissions from existing coal-fired and oil/gas-fired electric power generating boilers. The EPA also proposed GHG emission limits for existing stationary combustion turbines.
Added
Our goals are compared to a 2005 baseline. Electric Utility goals include Scope 1 emissions from electric utility generating units and Scope 3 emissions from purchased power for sales. Our Gas Utilities goal initially included only Scope 1 emissions from distribution system main and service lines.
Removed
The proposed emissions limitations are based upon the application of carbon capture controls or the use of hydrogen fuel beginning in 2030. In April 2024, the EPA published final rules addressing control of CO 2 emissions from the power sector. The rules regulate new natural gas generating units and provide emission guidelines for existing coal and certain natural gas generation.
Added
In August 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubled the previous target of a 50% reduction by 2035 and expanded the scope of the goal to all Scope 1 sources of methane emissions on our distribution system.
Removed
The rules create subcategories of coal units based on planned retirement date and subcategories of natural gas combustion turbines and combined cycle units based on utilization. The CO 2 control requirements vary by subcategory.
Added
Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-party damage reduction, expanding the use of renewable natural gas and hydrogen, and utilizing carbon credit offsets. During the second quarter of 2025, we published our 2024 Corporate Sustainability Report, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals.
Removed
Human Capital Resources Overview We are committed to retaining, attracting and cultivating a talented, engaged, and thriving team. By making our people and culture a strategic priority, our employees are engaged and empowered to contribute to the success of our business. We are committed to building a workforce that is representative of the communities we serve.
Added
We reported a 38% reduction in electric utility emissions since 2005 and are on track to reduce emissions 40% by 2030 and 70% by 2040. We also continue to advance toward our goal of net zero natural gas utility emissions by 2035.
Removed
Our recruiting strategies support our efforts to attract qualified individuals with targeted efforts to reach underrepresented talent. Our internship program, together with our partnerships and participation in outreach programs with local schools and colleges, attract students to careers in the energy industry. We seek to attract, retain, and cultivate an engaged and thriving team driven to improve life with energy.
Added
Human Capital Resources Overview We are committed to building a diverse workforce that reflects the strength and character of the communities we serve, united by our shared commitment to improving life with energy. We appreciate that every team member brings distinct skills, talents, experiences and perspectives that strengthen our organization.
Removed
We continuously evaluate our recruitment strategies to determine their effectiveness to attract and build a talented, diverse workforce with a sense of belonging. Workforce diversity trends, which include new hires, promotions, and turnover, are monitored at regular intervals throughout the year.
Added
Guided by our core values, we strive to build a culture of belonging. This means every team member can be authentic and is empowered to reach their full potential while contributing to business outcomes that positively impact our stakeholders.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeFailure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. Liability from fires could have a negative impact on our operations or financial performance, and our protocols may not prevent such liability. Environmental factors including precipitation, temperature, humidity and wind speeds have the potential to increase the likelihood and impact of a wildfire event.
Biggest changeEnvironmental factors including precipitation, temperature, humidity and wind speeds have the potential to increase the likelihood and impact of a wildfire event. We invest resources on initiatives designed to mitigate wildfire risks and also established our Emergency PSPS program in 2025.
Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation. • Our customers' focus on energy conservation which may be assisted by emerging technologies.
Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation; and • Our customers' focus on energy conservation which may be assisted by emerging technologies.
Risk of investor pressure over climate risk and/or ESG standards, activist campaigns against coal producers, employee preferences to work for companies with certain sustainability goals, and consumers preference for renewable energy could impact our reputation, ability to attract and retain an appropriately trained workforce, and overall access to capital and/or adequate insurance policies.
Risk of investor pressure over climate risk and/or sustainability standards, activist campaigns against coal producers, employee preferences to work for companies with certain sustainability goals, and consumers preference for renewable energy could impact our reputation, ability to attract and retain an appropriately trained workforce, and overall access to capital and/or adequate insurance policies.
Customer growth and usage may be impacted by the voluntary reduction in consumption of electricity and natural gas by our customers in response to increases in prices and energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, economic conditions (i.e., inflation, recession) impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies.
Customer growth and usage may be impacted by the voluntary reduction in consumption of electricity and natural gas by our customers in response to increases in prices and affordability concerns, energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, economic conditions (i.e., inflation, recession) impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies.
In addition, adverse rate decisions, including rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investments or rate reductions, could be influenced by competitive, economic, political, legislative, public perception and regulatory pressures and adversely impact earnings, cash flow, and liquidity.
In addition, adverse rate decisions, including rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investments or rate reductions, could be influenced by competitive, economic, political, legislative, public perception, affordability concerns and regulatory pressures and adversely impact earnings, cash flow, and liquidity.
The successful execution of our capital investment program depends on, or could be affected by, a variety of factors that include, but are not limited to: access to capital to fund projects, weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity prices, impacts of supply chain disruptions on availability and cost of materials, governmental approvals and permitting, regulatory cost recovery, and return on investment.
The successful execution of our capital investment program depends on, or could be affected by, a variety of factors that include, but are not limited to: access to capital markets on reasonable terms to fund projects, weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity prices, impacts of supply chain disruptions on availability and cost of materials, governmental approvals and permitting, regulatory cost recovery, and return on invested capital.
These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills. 27 Table of Contents • Weather conditions.
These risks could directly influence the demand for electricity and natural gas as well as the need for additional power generation and generating facilities. We could also be exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills; • Weather conditions.
Our operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather, sabotage, cyber-attacks, and environmental regulations. 26 Table of Contents • Replacement power.
Our operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather, sabotage, cyber-attacks, and environmental regulations; • Replacement power.
See Note 13 of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information 29 Table of Contents Our use of derivative financial instruments as hedges against commodity prices and financial market risks could result in material financial losses.
See Note 13 of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information Our use of derivative financial instruments as hedges against commodity prices and financial market risks could result in material financial losses.
Our inability to generate sufficient taxable income in the future to fully use these tax carryforwards before they expire, or to transfer future tax credits as discussed below, could significantly affect our tax obligations and financial results. 24 Table of Contents Our Electric Utilities and non-regulated power generation entities own and operate renewable energy generating facilities.
Our inability to generate sufficient taxable income in the future to fully use these tax carryforwards before they expire, or to transfer future tax credits as discussed below, could significantly affect our tax obligations and financial results. Our Electric Utilities and non-regulated power generation entities own and operate renewable energy generating facilities.
The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient to cover all liabilities to which we may be subject, including liability and losses associated with wildfires, natural gas and storage field explosions, cyber-security breaches, environmental hazards, and natural disasters.
The coverage we currently have in place may not apply to 29 Table of Contents a particular loss, or it may not be sufficient to cover all liabilities to which we may be subject, including liability and losses associated with wildfires, natural gas and storage field explosions, cyber-security breaches, environmental hazards, and natural disasters.
These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections, and other government approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties.
These laws and regulations may result in increased capital, operating, and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections, and other government approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties.
Supply chain challenges could negatively impact our operations. We rely on various suppliers in our supply chain for the materials necessary to execute on our capital investment program that is key to our strategic business plans and to respond to a significant unplanned event such as a natural disaster.
We rely on various suppliers in our supply chain for the materials necessary to execute on our capital investment program that is key to our strategic business plans and to respond to a significant unplanned event such as a natural disaster.
Customer growth and energy use can be negatively impacted by population declines as well as adverse economic factors in our service territories, including recession, inflation, workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment.
Customer growth and energy use can be negatively impacted by population declines or the loss of large-load industrial customers (including data center facilities) as well as adverse economic factors in our service territories, including recession, inflation, workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment.
In recent years, securing adequate insurance coverage has become more difficult and the cost of insurance has increased substantially. We believe that these trends are likely to continue. Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers.
In recent years, securing adequate insurance coverage has become more difficult and the cost of insurance has increased substantially. Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers.
Our supply chain, material costs, and capital investment program may be negatively impacted by: • Unanticipated price increases due to recent macroeconomic factors, such as inflation, including wage inflation, imposition of new tariffs, or rising demand for raw materials associated with the Energy Transition; and • Supply restrictions beyond our control or the control of our suppliers such as disruption of the freight system (e.g. labor union strikes, disruptions of trade routes), new or increased tariffs or quotas, increased environmental threats from weather-related disasters, rising demand for raw materials associated with the Energy Transition, and/or geopolitical unrest.
Our supply chain, material costs, and capital investment program may be negatively impacted by: • Unanticipated price increases due to recent macroeconomic factors, such as imposition of tariffs, inflation, including wage inflation, or rising demand for key materials such as transformers, generation units and equipment to meet the rapid pace of expansion with prospective and existing data center customers; and • Supply restrictions beyond our control or the control of our suppliers such as disruption of the freight system (e.g. labor union strikes, disruptions of trade routes), new or increased tariffs or quotas, increased environmental threats from weather-related disasters, rising demand for key materials, and/or geopolitical unrest.
Any of these risks described above could damage our reputation and public confidence. These risks could also cause us to be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce revenues or cause us to incur higher operating and maintenance costs and penalties.
These risks could also cause us to be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce revenues or cause us to incur higher operating and maintenance costs and penalties.
In addition, we have significant capital investment programs planned for the next five years that are key to our strategic business plan, such as: our Ready Wyoming transmission project; the acquisition of a renewable generating facility and energy storage facility as part of our Colorado Clean Energy Plan; the addition of 99 MWs of natural gas-fired generation in South Dakota; large-scale investments to upgrade existing utility infrastructure; support of customer and community growth needs; and compliance with safety requirements.
In addition, we have significant capital investment programs planned for the next five years that are key to our strategic business plan, such as: our Lange II project; the acquisition of a battery storage facility as part of our Colorado Clean Energy Plan; large-scale investments to upgrade existing utility infrastructure; support of customer and community growth needs; and compliance with safety requirements.
We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2024. If we make changes in our strategic business plan and growth strategy, or if macroeconomic or other conditions adversely affect operations in any of our businesses, we may be required to record a non-cash impairment charge.
If macroeconomic or other conditions adversely affect operations or require us to make changes to our strategic business plan, we may be forced to record a non-cash goodwill impairment charge. We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2025.
Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made.
If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made.
Our operations are subject to various conditions that can result in fluctuations in customer usage, including customer growth and general economic conditions in our service territories, weather conditions, and responses to price increases and technological improvements. Demand for electricity and natural gas can vary greatly based upon: • Fluctuations in customer growth and general economic conditions in our service territories.
Our operations are subject to various conditions that can result in fluctuations in customer usage, including customer growth and general economic conditions in our service territories, weather conditions, and responses to price increases and technological improvements.
If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of any litigation costs or our investment in assets subject to condemnation.
If a municipality sought to pursue this course of action, we cannot assure that we would secure adequate recovery of any litigation costs or our investment in assets subject to condemnation. We also cannot quantify the impact that such action would have on the remainder of our business operations.
These factors could significantly reduce the PTCs and ITCs produced by our wind farms, resulting in increased federal income tax expense. The IRA of 2022 allows for the sale or transfer of renewable tax credits to other taxpayers. We have sold and plan to continue to sell tax credits if market conditions are favorable.
These factors could significantly reduce the PTCs produced by our wind farms, resulting in increased federal income tax expense. The IRA of 2022 allows for the sale or transfer of renewable tax credits to other taxpayers.
Additionally, insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. A loss for which we are not adequately insured could materially affect our financial results.
Additionally, insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. Through our captive insurance cell, we take certain insurance risk on our businesses including certain transmission and employment practice liabilities. A loss for which we are not adequately insured could materially affect our financial results.
The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other nation state actors and individuals. In addition, the advancement of AI has given rise to additional vulnerabilities and potential entry points for cyberattacks.
The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other nation state actors and individuals.
Increased capital and operating costs to comply with increasingly stringent laws and regulations, unexpected engineering, environmental and geological problems, and unanticipated cost overruns. • Supply chain challenges (discussed above). • Workforce capabilities and labor relations (discussed above). • Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses.
Increased capital and operating costs to comply with increasingly stringent laws and regulations, unexpected engineering, environmental and geological problems, and unanticipated cost overruns; • Supply chain challenges (discussed above); • Workforce capabilities and labor relations (discussed above); and • Public opposition.
Recent trends, such as a competitive and tight labor market and declines in employee engagement may lead to higher costs and increased risk of negative outcomes for safety, compliance, customer service, and operations.
Failure to attract and retain an appropriately qualified and engaged workforce could have a negative impact on our operations and long-term business strategy. Recent trends, such as a competitive and tight labor market and declines in employee engagement may lead to higher costs and increased risk of negative outcomes for safety, compliance, customer service, and operations.
Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions (i.e., SO 2 , NO x , volatile organic compounds, particulate matter, and GHG), water quality, wastewater discharges, solid waste, and hazardous waste. These laws and regulations may result in increased capital, operating, and other costs.
Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements including those associated with climate change. 24 Table of Contents Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions (i.e., SO 2 , NO x , volatile organic compounds, particulate matter, and GHG), water quality, wastewater discharges, solid waste, and hazardous waste.
Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes or may require us to increase our level of debt. Further, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability. ITEM 1B.
Requirements to post collateral may cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes or may require us to increase our level of debt.
Such developments could affect the price and/or delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system's power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives.
Such developments could affect the price and/or delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system's power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. 28 Table of Contents As part of our planning process, we estimate the fluctuations in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain.
New or more stringent regulations or other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or capacity reductions of coal-fired power generation facilities or conversion to alternative fuels, and potential decreased production from our combined cycle natural gas-fired generating units.
At the local or state level, such as in Colorado, new or more stringent regulations could require us to incur significant additional costs relating to the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources and potential decreased production from our combined cycle natural gas-fired generating units.
In addition, there is no certainty that costs incurred related to securing against threats will be recovered through rates. Our financial performance depends on the successful operation of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities and a coal mine. The risks associated with managing these operations include: • Operating hazards.
Our financial performance depends on the successful operation of electric generating facilities, electric and natural gas transmission and distribution systems, natural gas storage facilities and a coal mine. The risks associated with managing these operations include the following: • Operating hazards.
Our ability to access capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, general macroeconomic conditions which may drive changes in interest rates and cause volatility in our stock price, changes in the federal or state regulatory environment affecting energy companies, and volatility in commodity prices. 28 Table of Contents In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service.
Our ability to access capital markets and the costs and terms of available financing depend on many factors, including changes in our credit ratings, general macroeconomic conditions which may drive changes in interest rates and cause volatility in our stock price, changes in the federal or state regulatory environment affecting energy companies, and volatility in commodity prices.
An inability to successfully manage challenges in our supply chain network could materially affect our ability to execute our business plan and growth strategy and our financial operating results including earnings, cash flow, and liquidity. 25 Table of Contents Cybersecurity incidents, terrorism, or other malicious acts targeting our key technology systems could disrupt our operations, lead to a loss or misuse of confidential and proprietary information, or cause reputational or other harm.
Our inability to generate, transfer, or sell these credits could have a material impact on our financial condition, results of operations and cash flows. 25 Table of Contents OPERATING RISKS Cybersecurity incidents, terrorism, or other malicious acts targeting our key technology systems could disrupt our operations, lead to a loss or misuse of confidential and proprietary information, or cause reputational or other harm.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many agencies employ mandatory civil penalty structures for regulatory violations.
We cannot definitively estimate the effect of climate and emissions legislation or regulation on our earnings, cash flow and liquidity. Legislative and regulatory requirements may result in compliance penalties. Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many agencies employ mandatory civil penalty structures for regulatory violations.
Each of these factors described above could materially affect demand for electricity and natural gas which would impact our financial operating results including earnings, cash flow and liquidity. If macroeconomic or other conditions adversely affect operations or require us to make changes to our strategic business plan, we may be forced to record a non-cash goodwill impairment charge.
In addition, elimination or reduced financial support of programs that provide energy assistance to our customers, could impact the demand for energy. Each of these factors described above could materially affect demand for electricity and natural gas which would impact our financial operating results including earnings, cash flow and liquidity.
More stringent environmental laws or regulations could result in additional capital investments and costs of operation for existing facilities or impede the development of new facilities. There is uncertainty regarding if and when new climate legislation, regulations or policies will be adopted to reduce or limit GHG and the impact any such regulations would have on us.
More stringent environmental laws or regulations could result in additional capital investments and costs of operation for existing facilities or impede the development of new facilities. Substantial changes in federal climate and emissions policies may create long-term uncertainty in our resource planning and capital investment decisions.
We invest resources on initiatives designed to mitigate wildfire risks and also intend to implement a PSPS framework in 2025. The potential for a wildfire event exists even when effective mitigation procedures are followed. Despite our wildfire mitigation initiatives, a wildfire could be ignited, spread and cause damages, which would subject us to significant liability.
Despite our wildfire mitigation initiatives, we could ignite a wildfire, which could spread and cause damages and would subject us to significant liability.
These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity. We cannot definitively estimate the effect of GHG legislation or regulation on our earnings, cash flow and liquidity. Legislative and regulatory requirements may result in compliance penalties.
Additional rules and regulations associated with electrification initiatives could negatively impact demand for natural gas and limit our capital investments in natural gas assets. These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity.
Removed
We also cannot quantify the impact that such action would have on the remainder of our business operations. 23 Table of Contents Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements including those associated with climate change.
Added
The OBBBA, enacted in July 2025, does not repeal tax credit transferability provisions enacted under the IRA and continues to permit the execution of our transferability agreements as originally agreed upon, but restricts credit transfers to prohibited foreign entities. We have sold and plan to continue to sell tax credits if market conditions are favorable.
Removed
Additional rules and regulations associated with fossil fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution, generation and natural gas storage facilities or our coal mine. Further, these rules could create the need to purchase or build clean-energy fuel sources to fulfill obligations to our customers.
Added
Additionally, artificial intelligence, including generative artificial intelligence, may be used to facilitate or perpetrate these cybersecurity threats, and our use of generative artificial intelligence (and use by our vendors and agents) may subject us to data privacy, legal, and security risks.
Removed
Our inability to generate, transfer, or sell these credits could have a material impact on our financial condition, results of operations and cash flows. OPERATING RISKS Failure to attract and retain an appropriately qualified and engaged workforce could have a negative impact on our operations and long-term business strategy.
Added
In addition, there is no certainty that costs incurred related to securing against threats will be recovered through rates. Liability from fires could have a negative impact on our operations or financial performance, and our protocols may not prevent such liability.
Added
Recent legislation by the states of Wyoming and Montana provide material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. However, the potential for a wildfire event exists even when effective mitigation procedures are followed.
Added
Failure to renew or renegotiate these contracts could lead to labor disruptions, including strikes or boycotts. 26 Table of Contents Supply chain challenges could negatively impact our operations.
Added
An inability to successfully manage challenges in our supply chain network could materially affect our ability to execute our business plan and growth strategy and our financial operating results including earnings, cash flow, and liquidity.
Added
Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses. 27 Table of Contents Any of these risks described above could damage our reputation and public confidence.
Added
Demand for electricity and natural gas can vary greatly based upon the following: • Fluctuations in customer growth and general economic conditions in our service territories.
Added
The rapid growth of data centers may make it more difficult to accurately forecast load demand or to recover additional costs.
Added
Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced customer usage from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition.
Added
If we make changes in our strategic business plan and growth strategy, or if macroeconomic or other conditions adversely affect operations in any of our businesses, we may be required to record a non-cash impairment charge. Goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred.
Added
In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility subsidiaries are adequately capitalized to provide safe and reliable service.
Added
Further, a requirement for our counterparties to post collateral could result in additional costs being passed on to us, thereby decreasing our profitability. 30 Table of Contents RISKS RELATED TO MERGER WITH NORTHWESTERN The ability of BHC and NorthWestern to complete the Merger is subject to various closing conditions, including the receipt of approval of BHC and NorthWestern shareholders and the receipt of consents and approvals from various governmental authorities, which may impose conditions that could adversely affect BHC or NorthWestern or cause the Merger to be abandoned.
Added
Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of BHC common stock or other securities and the future business and financial results of BHC. To complete the Merger, BHC and NorthWestern shareholders must vote to approve a number of proposals related to the Merger and the Merger Agreement.
Added
Further, the Merger is subject to the satisfaction or waiver of certain closing conditions, including, (1) the effectiveness of the registration statement on Form S-4 relating to the Merger (which registration statement was filed on January 30, 2026, and was declared effective on February 6, 2026); (2) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the HSR Act, and approval from the FERC and certain state regulatory commissions, in each case on such terms and conditions that would not result in a material adverse effect on the combined company; (3) the absence of any court order or regulatory injunction prohibiting completion of the Merger; (4) the authorization for listing of shares of BHC Common Stock to be issued in connection with the Merger on the NYSE or other mutually-agreed stock exchange; (5) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (6) compliance by each party in all material respects with its covenants under the Merger Agreement; (7) the absence of a material adverse effect on each party; and (8) receipt by each party of an opinion relating to the anticipated tax-free treatment of the Merger.
Added
If the foregoing conditions are not satisfied or waived, one or both of BHC or NorthWestern would not be required to complete the Merger. BHC and NorthWestern have not yet obtained shareholder approval or all of the regulatory consents and approvals required to complete the Merger.
Added
Governmental or regulatory agencies could seek to block or challenge the Merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the Merger.
Added
BHC and NorthWestern will be unable to complete the Merger until the waiting period under the HSR Act has expired or been terminated and the required governmental approvals have been received. Regulatory authorities may impose certain requirements or obligations as conditions for their approval.
Added
The Merger Agreement may require BHC and/or NorthWestern to accept conditions from these regulators that could adversely impact the combined company. If the required governmental approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then neither BHC nor NorthWestern will be obligated to complete the Merger.
Added
There can be no assurance that a challenge to the Merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.
Added
Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the Merger, governmental authorities could seek to block or challenge the Merger as they deem necessary or desirable in the public interest.
Added
In addition, in some jurisdictions, a private party could initiate an action under the antitrust laws challenging or seeking to enjoin the Merger, before or after they are completed. BHC or NorthWestern may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.
Added
The special meetings at which the BHC shareholders and the NorthWestern shareholders will vote on the transactions contemplated by the Merger Agreement may take place before all regulatory approvals have been obtained and, in cases where they have not been obtained, before the terms of any conditions to obtain such regulatory approvals that may be imposed are known.
Added
As a result, if shareholder approval of the transactions contemplated by the Merger Agreement is obtained at such meetings, BHC and NorthWestern may make decisions after the meetings to waive a condition or approve certain actions required to obtain the necessary approvals without seeking further shareholder approval. Such actions could have an adverse effect on the combined company.
Added
If BHC and NorthWestern are unable to complete the Merger, or there is a significant delay in completing the Merger, BHC would be subject to a number of risks, including the following: • BHC would not realize the anticipated benefits of the Merger, including, among other things, increased operating efficiencies and future cost savings; • the attention of management of BHC may have been diverted to the Merger rather than to its own operations and the pursuit of other opportunities that could have been beneficial to BHC; • the potential loss of key personnel during the pendency of the Merger as employees may experience uncertainty about their future roles with the combined company; • BHC will have been subject to certain restrictions on the conduct of its business, which may prevent BHC from making certain acquisitions or dispositions or pursuing certain business opportunities while the Merger is pending; 31 Table of Contents • the trading price of BHC common stock or other securities may decline to the extent that the current market prices reflect a market assumption that the Merger will be completed; and • the parties may be liable for damages to one another, or have to pay a termination fee, under the Merger Agreement.
Added
BHC can provide no assurance that the various closing conditions will be satisfied and that the required governmental approvals and other approvals will be obtained, or that any required conditions will not materially adversely affect the combined company following the Merger.
Added
In addition, BHC can provide no assurance that these conditions will not result in the abandonment or delay of the Merger. The occurrence of these events individually or in combination could have a material adverse effect on BHC's results of operations and the trading price of BHC common stock or other securities.
Added
The Merger Agreement contains provisions that limit BHC's ability to pursue alternatives to the Merger, could discourage a potential acquirer of BHC from making a favorable alternative transaction proposal and, in certain circumstances, could require BHC to pay a termination fee to NorthWestern.
Added
Under the Merger Agreement, BHC and NorthWestern have agreed, subject to certain exceptions with respect to unsolicited proposals, not to directly or indirectly solicit competing acquisition proposals or to enter into discussions concerning, or provide confidential information in connection with, any unsolicited alternative acquisition proposals.
Added
Additionally, the BHC board of directors and the NorthWestern board of directors are each required to recommend the approval of the applicable transaction-related proposals to its respective shareholders, subject to certain exceptions.
Added
Prior to the approval of the transaction-related proposals by their respective shareholders, the BHC board of directors or the NorthWestern board of directors may change its recommendation in response to an unsolicited proposal for an alternative transaction, if such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that the proposal constitutes or would reasonably be expected to lead to a “Superior NorthWestern Proposal” or “Superior BHC Proposal”, as applicable (as such terms are defined in the Merger Agreement), and that failure to take such action would be inconsistent with their fiduciary duties under applicable law to the applicable company and its shareholders under applicable law, subject to complying with certain procedures set forth in the Merger Agreement.
Added
Prior to the approval of the transaction-related proposals by their respective shareholders, the BHC board of directors and the NorthWestern board of directors may also change its recommendation upon the occurrence of a “NorthWestern Intervening Event” or “BHC Intervening Event”, as applicable (as such terms are defined in the Merger Agreement), and such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that failing to change its recommendation would be inconsistent with its fiduciary duties under applicable law, subject to complying with certain procedures set forth in the Merger Agreement.
Added
The Merger Agreement is subject to a “force-the-vote” provision, which means neither BHC nor NorthWestern would have an independent right to terminate the Merger Agreement to accept a superior proposal.
Added
These provisions could discourage a third party that may have an interest in acquiring all or a significant part of BHC from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher market value than the market value proposed to be received or realized in the merger, or might result in a potential acquirer proposing to pay a lower price than it would otherwise have proposed to pay.
Added
As a result of these restrictions, BHC may not be able to enter into an agreement with respect to a more favorable alternative transaction, or may be able to do so only by incurring potentially significant liability to NorthWestern.
Added
The Merger Agreement contains certain customary termination rights for each of BHC and NorthWestern; provided, that, either party would be required to pay to the other a termination fee equal to $100 million upon termination of the Merger Agreement in certain circumstances involving (i) a change in recommendation by such party’s board of directors (including, in certain circumstances, the failure of such party to publicly reaffirm its recommendation upon request) or (ii) a party entering into a definitive agreement in respect of a competing transaction within twelve months of termination of the Merger Agreement in certain circumstances involving a potential competing acquisition proposal.
Added
Members of the management and the boards of directors of BHC and NorthWestern have interests in the Merger that are different from, or in addition to, those of other shareholders and that could have influenced their decisions to support or approve the Merger.
Added
In considering whether to approve the transactions contemplated by the Merger Agreement, BHC shareholders and NorthWestern shareholders should recognize that some of the members of management and the boards of directors of BHC and NorthWestern have interests in the Merger that differ from, or are in addition to, their interests as shareholders of BHC and shareholders of NorthWestern.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

9 edited+2 added−6 removed1 unchanged
Biggest changeThese procedures also include notification to a cross-functional management team to assess incident materiality and an escalation process to members of our senior management team and our Board of Directors. 30 Table of Contents Governance Our Board of Directors is responsible for the oversight of risks from cybersecurity threats.
Biggest changeEscalation protocols ensure timely notification to senior management and our Board of Directors when materiality thresholds are met. Governance Our Board of Directors is responsible for the oversight of risks from cybersecurity threats. Our Chief Information and Transformation Officer provides our Board of Directors quarterly reports that summarize material cybersecurity threats and the countermeasures taken to mitigate the associated risks.
Our cybersecurity risk management program, which is discussed above, is led by our CSO, who has 34 years of experience in various roles involving managing information security of large-scale global security operations, including developing cybersecurity strategy and implementing effective information and cybersecurity programs. Our CSO maintains industry certifications, including an ISC2 Certified Information Systems Security Professional certification.
Our cybersecurity risk management program is led by our CSO, who has 35 years of experience in various roles involving managing information security of large-scale global security operations, including developing cybersecurity strategies and implementing effective information and cybersecurity programs. Our CSO maintains industry certifications, including an ISC2 Certified Information Systems Security Professional certification.
Our enterprise risk management team works closely with our CSO and IT risk management team to evaluate and address material cybersecurity risks in alignment with our business strategy and operational needs.
The enterprise risk management team works closely with our CSO and security governance and risk management team to evaluate and address material cybersecurity risks in alignment with our business strategy and operational needs.
The CSO, in his capacity, regularly informs the Chief Information Officer and other members of our senior management team of all aspects related to cybersecurity risks and incidents.
The CSO, provides regular updates to the Chief Information and Transformation Officer and other members of our senior management team regarding all aspects related to cybersecurity risks and incidents.
Risk Management and Strategy Our enterprise risk management program, which includes cybersecurity risks that are identified through our cybersecurity risk management program, is designed to identify, report, and manage relevant material risks and opportunities. Management of the identified risks is embedded into business processes and key decision making at every level of the Company.
Risk Management and Strategy Our enterprise risk management program, which incorporates cybersecurity risks that are identified through our dedicated cybersecurity risk management program, is designed to identify, report, and manage material risks and improvement opportunities, embedding risk management into business processes and decision-making at all levels.
Our Chief Information Officer provides our Board of Directors quarterly reports that summarize material cybersecurity threats and the countermeasures taken to mitigate the associated risks. These reports address a variety of topics including updates on strategic cyber initiatives, industry trends, threat vulnerability assessments, and efforts to prevent, detect, and respond to internal and external critical threats.
These reports address a variety of topics including updates on strategic cyber initiatives, industry trends, threat vulnerability assessments, and efforts to prevent, detect, and respond to internal and external critical threats. From time to time, our Board of Directors also engages third-party consultants to provide further education about cybersecurity risks.
We also utilize government and industry-related security intelligence sources, and actively participate in industry peer groups and public-private partnerships to assist in the identification of potential threats. We conduct ongoing cybersecurity training and monthly email phishing drills for all employees. We also have a cybersecurity incident response plan and procedures to manage cybersecurity incidents.
Additionally, we utilize government and industry intelligence sources, and actively participate in peer groups and public-private partnerships to stay ahead of emerging threats. To strengthen our human defenses, we conduct ongoing cybersecurity training and monthly phishing simulations for all employees and contractors. Our cybersecurity incident response plan includes procedures for identification, classification, communication, containment, eradication, recovery and communication of incidents.
The industry-standard security frameworks that we apply to our cyber environment include various security and risk assessments, such as internal threat assessments and internal control self-assessments. Because we are aware of the risks associated with third-party providers, we conduct third-party provider security assessments and benchmarking before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards.
Our cybersecurity risk management program is staffed by full-time cybersecurity professionals that utilizes a variety of tools and leverages industry-standard frameworks and assessments, including threat analysis and control self-assessments. Recognizing the risks associated with third-party providers, we conduct rigorous security assessments and benchmarking prior to engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards.
We expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure, and other assets. To date, we have not experienced a cybersecurity incident that has had a material impact on our business or results of operations.
Recent incidents in the utility sector underscore the disruptive potential of cyberattacks on critical infrastructure, with adversaries leveraging emerging technologies such as artificial intelligence to exploit vulnerabilities and evade detection. To date, we have not experienced a cybersecurity incident that has had a material impact on our business or results of operations.
Removed
ITEM 1C. CYBERSECURITY The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other nation state actors, and individuals. In addition, the advancement of AI has given rise to additional vulnerabilities and potential entry points for cyberattacks.
Added
ITEM 1C. CYBERSECURITY As a provider of essential utility services, our operations rely on complex information and operational technology systems that are increasingly targeted by sophisticated cyber adversaries, including nation-state actors, cyber-criminals, hacktivist organizations, and insiders.
Removed
We have a cybersecurity risk management program that is managed by a team of full-time cybersecurity professionals that utilizes a variety of tools and techniques to identify and assess material cybersecurity threats, their potential impact and opportunities for mitigation.
Added
These assessments include vendor risk questionnaires, review of System and Organization Controls reports and continuous monitoring by our security governance and risk team. 38 Table of Contents We regularly engage assessors and auditors to validate the effectiveness of our controls and identify areas for improvement.
Removed
These assessments include evaluation of risk profiles through vendor questionnaires, review of System and Organization Controls attestation reports and monitoring on an ongoing basis by our IT risk management team. This approach is designed to mitigate risks related to data breaches or other security incidents originating from third-parties.
Removed
We regularly engage with third-party assessors and auditors as part of our ongoing cybersecurity risk assessment process to leverage specialized knowledge and insights and to identify areas for continued focus, improvement, compliance, and effectiveness of mitigation.
Removed
These procedures include steps to identify, classify, communicate, contain, eradicate, and recover from a cybersecurity incident .
Removed
From time to time, our Board of Directors also engages third-party consultants to provide further education about cybersecurity risks.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

6 edited+4 added−5 removed0 unchanged
Biggest changeShe served as VP Electric Utilities from 2021 to 2023, Vice President Regulatory and Finance from 2018 to 2021, and Vice President Regulatory from 2016 to 2018. Ms. Jones has a total of 23 years of experience with the Company and has advanced through roles of increasing responsibility in finance, accounting, corporate services, regulatory, and utility operations. Erik D.
Biggest changeJones has a total of 24 years of experience with the Company and has advanced through roles of increasing responsibility in finance, accounting, corporate services, regulatory, and utility operations. Darren Nakata , age 52, joined the Company as Senior Vice President and Chief Legal Officer, Corporate Secretary and Chief Compliance Officer in October 2025. For the prior two decades Mr.
Prior to joining the company, she was Vice President of Human Resources for ACCO Brands, a publicly traded global consumer goods company, from 2021 to October 2024, Director and Vice President Human Resources for Compass Minerals from 2018 to 2021, and held various leadership roles at Union Pacific from 2004 to 2018. 32 Table of Contents PART II
Prior to joining the Company, she was Vice President of Human Resources for ACCO Brands, a publicly traded global consumer goods company, from 2021 to October 2024, Director and Vice President Human Resources for Compass Minerals from 2018 to 2021, and held various leadership roles at Union Pacific from 2004 to 2018. 40 Table of Contents PART II
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 of this Annual Report. 31 Table of Contents INFORMATION ABOUT OUR EXECUTIVE OFFICERS Phillip A.
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 of this Annual Report. 39 Table of Contents INFORMATION ABOUT OUR EXECUTIVE OFFICERS Linden R. Evans, age 63, has been President and Chief Executive Officer since 2019.
Keller announced that he will resign from the Company, effective February 28, 2025. Kimberly F. Nooney , age 54, has been Senior Vice President and Chief Financial Officer since April 1, 2023. She served as Vice President – Treasurer from 2015 to 2023, and also served as the Corporate Controller from 2018 to 2022. Ms.
Nooney , age 55, has been Senior Vice President and Chief Financial Officer since 2023. She served as Vice President – Treasurer from 2015 to 2023, and also served as the Corporate Controller from 2018 to 2022. Ms.
Nooney has a total of 28 years of experience with the Company across numerous roles within accounting, internal audit, corporate development, accounting systems, treasury, and financial planning and analysis. Sarah A. Wiltse , age 46, joined the Company as Senior Vice President and Chief Human Resources Officer on October 28, 2024.
Nooney has a total of 29 years of experience with the Company across numerous roles within accounting, internal audit, corporate development, accounting systems, treasury, and financial planning and analysis. Don Redden , age 54, joined the Company as Senior Vice Present and Chief Information and Transformation Officer in July 2025. Prior to joining the Company, Mr.
Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 23 years of experience with the Company. Marne M. Jones , age 51, has been Senior Vice President Utilities since June 15, 2023.
He served as - President and Chief Operating Officer from 2016 to 2018, and President and Chief Operating Officer - Utilities from 2004 to 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr.
Removed
Casey , age 62, joined the Company as Senior Vice President and Chief Legal Officer on November 13, 2024. Prior to joining the company, he led the Indianapolis office of Calfee, Halter & Griswold from 2019 to November 2024 and co-chaired the firm's energy and utilities practice. Mr.
Added
Evans has 24 years of experience with the Company. As previously disclosed, Mr. Evans will retire following consummation of the Merger. Marne M. Jones , age 52, has been Senior Vice President Chief Utility Officer since 2025.
Removed
Casey also served as Vice President of Administration and General Counsel for Prairie State Generating Company from 2015 to 2018 and Vice President and Deputy General Counsel-Regulatory for NiSource from 2009 to 2015. Linden R.
Added
She served as Senior Vice President Utilities from 2023 to 2025, Vice President Electric Utilities from 2021 to 2023, Vice President Regulatory and Finance from 2018 to 2021, and Vice President Regulatory from 2016 to 2018. Ms.
Removed
Evans, age 62, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer - Utilities from 2004 through 2015. Mr.
Added
Nakata held various leadership roles at companies and law firms, including NW Natural, a publicly traded natural gas, water, wastewater and renewable energy company, Vestas, a publicly traded global wind energy company, and Cravath, Swaine & Moore, a global law firm. Prior to becoming an attorney, he was an engineering consultant for several years. Kimberly F.
Removed
Keller , age 61, has been Senior Vice President and Chief Information Officer since July 27, 2020.
Added
Redden had over 25 years of IT leadership experience, including Vice President of Information Technology at Otter Tail Corporation, a publicly traded utility and diversified operations company, and leadership roles at Crary Industries, Microsoft, and the City of Moorhead. Sarah A. Wiltse , age 47, has been Senior Vice President and Chief Human Resources Officer since October 2024.
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Prior to joining the company, he was an Information Technology consultant to Ontic Inc., a global provider of parts and services for legacy aerospace platforms, from January 2020 to July 2020, and Chief Information Officer for BBA Aviation, a global aviation support and aftermarket services provider, from 2012 to January 2020. As previously disclosed, Mr.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeSECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS See Item 12 in this Annual Report on Form 10-K for information regarding Securities Authorized for Issuance Under Equity Compensation Plans. 33 Table of Contents ISSUER PURCHASES OF EQUITY SECURITIES The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2024: Period Total Number of Shares Purchased (a) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs October 1, 2024 - October 31, 2024 1 $ 60.93 — — November 1, 2024 - November 30, 2024 1 $ 57.92 — — December 1, 2024 - December 31, 2024 3,238 $ 60.96 — — Total 3,240 $ 60.96 — — ____________________ (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.
Biggest changeISSUER PURCHASES OF EQUITY SECURITIES The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2025: Period Total Number of Shares Purchased (a) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs October 1, 2025 - October 31, 2025 1 $ 60.49 — — November 1, 2025 - November 30, 2025 4,373 $ 69.30 — — December 1, 2025 - December 31, 2025 1 $ 72.46 — — Total 4,375 $ 69.30 — — ____________________ (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.
DIVIDENDS For information concerning dividends, our dividend policy and factors that may limit our ability to pay dividends, see “ Key Elements of our Business Strategy ” and “ Liquidity and Capital Resources ” under Item 7 , Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
DIVIDENDS For information concerning dividends, our dividend policy and factors that may limit our ability to pay dividends, see “ Liquidity and Capital Resources ” under Item 7 , Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
COMPARATIVE STOCK PERFORMANCE The following performance graph compares the cumulative total stockholder return from Black Hills Corporation common stock, as compared with the S&P 500 Index, S&P 500 Utilities index, and our Performance Peer Group for the past five years. The graph assumes an initial investment of $100 on December 31, 2019, and assumes all dividends were reinvested.
COMPARATIVE STOCK PERFORMANCE The following performance graph compares the cumulative total stockholder return from BHC common stock, as compared with the S&P 500 Index, S&P 500 Utilities index, and our Performance Peer Group for the past five years. The graph assumes an initial investment of $100 on December 31, 2020, and assumes all dividends were reinvested.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of January 31, 2025, we had 3,102 common shareholders of record and approximately 82,684 beneficial owners.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of January 31, 2026, we had 2,975 common shareholders of record and approximately 95,000 beneficial owners.
As of December 31, 2019 2020 2021 2022 2023 2024 Black Hills Corporation $ 100.00 $ 80.92 $ 96.19 $ 99.15 $ 79.38 $ 90.09 S&P 500 100.00 118.40 152.39 124.79 157.59 197.02 S&P 500 Utilities 100.00 100.48 118.24 120.09 111.59 137.73 Performance Peer Group (a) 100.00 98.84 115.76 117.09 106.90 127.32 ____________________ (a) Performance Peer Group represents the Edison Electric Institute Index, which was used in our 2024 Proxy Statement filed with the SEC on March 15, 2024.
As of December 31, 2020 2021 2022 2023 2024 2025 Black Hills Corporation $ 100.00 $ 118.88 $ 122.53 $ 98.10 $ 111.34 $ 137.97 S&P 500 100.00 128.71 105.40 133.10 166.40 196.16 S&P 500 Utilities 100.00 117.67 119.51 111.05 137.07 159.06 Performance Peer Group (a) 100.00 117.12 118.47 108.16 128.82 143.83 ____________________ (a) Performance Peer Group represents the Edison Electric Institute Index, which was used in our 2025 Proxy Statement filed with the SEC on March 14, 2025.
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UNREGISTERED SECURITIES ISSUED There were no unregistered securities sold during 2024.
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UNREGISTERED SECURITIES ISSUED There were no unregistered securities sold during 2025. 41 Table of Contents SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS See Item 12 in this Annual Report on Form 10-K for information regarding Securities Authorized for Issuance Under Equity Compensation Plans.

Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

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Biggest changeMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 34 Executive Summary 34 Key Elements of our Business Strategy 34 Recent Developments 38 Results of Operations - Consolidated Summary and Overview 39 Non-GAAP Financial Measure 40 Electric Utilities 40 Gas Utilities 43 Corporate and Other 44 Consolidated Interest Expense, Other Income (Expense) and Income Tax Benefit (Expense) 44 Liquidity and Capital Resources 45 Cash Flow Activities 46 Capital Resources 47 Credit Ratings 48 Capital Requirements 49 Critical Accounting Estimates 50 ITEM 7A.
Biggest changeMANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 42 Executive Summary 42 Recent Developments 43 Results of Operations - Consolidated Summary and Overview 44 Non-GAAP Financial Measure 45 Electric Utilities 46 Gas Utilities 49 Corporate and Other 50 Consolidated Interest Expense, Other Income (Expense) and Income Tax Benefit (Expense) 50 Liquidity and Capital Resources 51 Cash Flow Activities 52 Capital Resources 53 Credit Ratings 54 Capital Requirements 55 Critical Accounting Estimates 57 ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 52 2 Table of Contents ITEM 8.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 59 2 Table of Contents ITEM 8.
Business Description and Significant Accounting Policies 64 Note 2. Regulatory Matters 72 Note 3. Commitments, Contingencies and Guarantees 75 Note 4. Revenue 77 Note 5. Property, Plant and Equipment 79 Note 6. Jointly Owned Facilities 80 Note 7. Asset Retirement Obligations 80 Note 8. Financing 81 Note 9. Risk Management and Derivatives 84 Note 10.
Business Description and Significant Accounting Policies 71 Note 2. Regulatory Matters 80 Note 3. Commitments, Contingencies and Guarantees 82 Note 4. Revenue 85 Note 5. Property, Plant and Equipment 86 Note 6. Jointly Owned Facilities 87 Note 7. Asset Retirement Obligations 88 Note 8. Financing 88 Note 9. Risk Management and Derivatives 92 Note 10.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 54 Management’s Report on Internal Controls Over Financial Reporting 54 Reports of Independent Registered Public Accounting Firm 55 Consolidated Statements of Income 58 Consolidated Statements of Comprehensive Income 59 Consolidated Balance Sheets 60 Consolidated Statements of Cash Flows 62 Consolidated Statements of Equity 63 Notes to Consolidated Financial Statements 64 Note 1.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 61 Management’s Report on Internal Controls Over Financial Reporting 61 Reports of Independent Registered Public Accounting Firm 62 Consolidated Statements of Income 65 Consolidated Statements of Comprehensive Income 66 Consolidated Balance Sheets 67 Consolidated Statements of Cash Flows 69 Consolidated Statements of Equity 70 Notes to Consolidated Financial Statements 71 Note 1.
Fair Value Measurements 87 Note 11. Other Comprehensive Income 88 Note 12. Variable Interest Entity 89 Note 13. Employee Benefit Plans 90 Note 14. Share-based Compensation Plans 94 Note 15. Income Taxes 96 Note 16. Business Segment Information 99 Note 17. Subsequent Events 101
Fair Value Measurements 95 Note 11. Other Comprehensive Income 97 Note 12. Variable Interest Entities 98 Note 13. Employee Benefit Plans 99 Note 14. Share-based Compensation Plans 104 Note 15. Income Taxes 106 Note 16. Business Segment Information 109 Note 17. Pending Merger with NorthWestern 111 Note 18. Subsequent Events 112

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeConsolidated Summary and Overview For the Years Ended December 31, 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions, except per share amounts) Operating income (loss): Electric Utilities $ 233.0 $ 248.8 $ (15.8 ) $ 214.3 $ 34.5 Gas Utilities 271.3 228.8 42.5 244.2 (15.4 ) Corporate and Other (a) (1.2 ) (4.9 ) 3.7 (3.3 ) (1.6 ) Operating Income 503.1 472.7 30.4 455.2 17.5 Interest expense, net (181.7 ) (167.9 ) (13.8 ) (161.0 ) (6.9 ) Other income (expense), net (1.4 ) (3.2 ) 1.8 1.8 (5.0 ) Income tax (expense) (36.3 ) (25.6 ) (10.7 ) (25.2 ) (0.4 ) Net income 283.7 276.0 7.7 270.8 5.2 Net income attributable to non-controlling interest (10.6 ) (13.8 ) 3.2 (12.4 ) (1.4 ) Net income available for common stock $ 273.1 $ 262.2 $ 10.9 $ 258.4 $ 3.8 Weighted average common shares outstanding, Diluted 69.9 67.1 2.8 65.0 2.1 Total earnings per share of common stock, Diluted $ 3.91 $ 3.91 $ — $ 3.97 $ (0.06 ) (a) Includes inter-segment eliminations. 2024 Compared to 2023 • Electric Utilities’ operating income decreased $15.8 million primarily due to unfavorable impacts from unplanned generation outages in 2024, lower off-system excess energy sales, higher insurance expense, and one-time benefits in 2023 from a gain on the sale of Northern Iowa Windpower assets, a gain on sale of land to support data center growth, and a recovery from our business interruption insurance.
Biggest changeConsolidated Summary and Overview For the Years Ended December 31, 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions, except per share amounts) Operating income (loss): Electric Utilities $ 222.5 $ 233.0 $ (10.5 ) $ 248.8 $ (15.8 ) Gas Utilities 320.8 271.3 49.5 228.8 42.5 Corporate and Other (a) (5.8 ) (1.2 ) (4.6 ) (4.9 ) 3.7 Operating Income 537.5 503.1 34.4 472.7 30.4 Interest expense, net (200.1 ) (181.7 ) (18.4 ) (167.9 ) (13.8 ) Other income (expense), net 6.1 (1.4 ) 7.5 (3.2 ) 1.8 Income tax (expense) (43.7 ) (36.3 ) (7.4 ) (25.6 ) (10.7 ) Net income 299.8 283.7 16.1 276.0 7.7 Net income attributable to non-controlling interest (8.2 ) (10.6 ) 2.4 (13.8 ) 3.2 Net income available for common stock $ 291.6 $ 273.1 $ 18.5 $ 262.2 $ 10.9 Weighted average common shares outstanding, Diluted 73.2 69.9 3.3 67.1 2.8 Total earnings per share of common stock, Diluted $ 3.98 $ 3.91 $ 0.07 $ 3.91 $ (0.00 ) (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; 44 Table of Contents • 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.
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.
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.
For the years ended December 31, 2024, 2023, and 2022, there were no impairment losses recorded. At December 31, 2024, 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.
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.
At December 31, 2024, 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, 2024, was not material. See Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
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.
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.
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.
Common Stock Dividends 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.
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.
As of December 31, 2024, 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.
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.
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.
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.
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 comparable sales transactions and enterprise value to EBITDA for comparative peer companies for each respective reporting unit.
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.
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 1.35 million customers and 800+ communities we serve.
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.
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. Critical Accounting Estimates We prepare our consolidated financial statements in conformity with GAAP.
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. 56 Table of Contents Critical Accounting Estimates We prepare our consolidated financial statements in conformity with GAAP.
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 recent sales transactions for comparable assets 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.
For discussion and analysis for the year ended December 31, 2023, compared to 2022, 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, 2023, which was filed with the SEC on February 14, 2024.
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.
A key strategic focus is to modernize and harden our utility infrastructure to meet customers’ and communities’ varied energy needs, ensure the continued delivery of safe, reliable and cost-effective energy and reduce GHG emissions intensity. In addition, we invest in the expansion, capacity, and integrity of our systems to meet customer growth.
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 for safety, reliability, and integrity of our system and is 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.
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.
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.
See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
For the year ended December 31, Contracted generating facilities Availability (a) by fuel type 2024 2023 2022 Coal (b) 89.8% 93.7% 91.5% Natural gas and diesel oil (b) 92.9% 92.1% 96.1% Wind 90.6% 92.5% 93.7% Total availability 91.7% 92.6% 94.4% Wind Capacity Factor (a) 36.7% 37.4% 34.7% (a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
For the year ended December 31, Contracted generating facilities Availability (a) by fuel type 2025 2024 2023 Coal (b) 77.7% 89.8% 93.7% Natural gas and diesel oil (b) 92.6% 92.9% 92.1% Wind 82.5% 90.6% 92.5% Total availability 86.9% 91.7% 92.6% Wind Capacity Factor (a) 34.2% 36.7% 37.4% (a) Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our Revolving Credit Facility and CP Program. 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.
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.
Varying by reporting unit, weighted average cost of capital in the range of 6.3% to 6.5% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2024.
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.
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, 2024.
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.
The following table provides an informational summary of our liquidity and capital structure as of December 31: 2024 2023 (dollars in millions) Cash and cash equivalents $ 16.1 $ 86.6 Available capacity under Revolving Credit Facility and CP Program (a) 612.7 746.3 Available liquidity $ 628.8 $ 832.9 Capital structure Short-term debt $ 133.8 $ 600.0 Long-term debt 4,250.2 3,801.2 Total debt 4,384.0 4,401.2 Total stockholders' equity (excludes non-controlling interest) 3,501.5 3,215.3 Total capitalization $ 7,885.5 $ 7,616.5 Debt to capitalization 55.6 % 57.8 % Long-term debt to total debt 96.9 % 86.4 % (a) Available capacity under Revolving Credit Facility and CP Program represents $750 million of total borrowing capacity less outstanding borrowings and letters of credit.
The following table provides an informational summary of our liquidity and capital structure as of December 31: 2025 2024 (dollars in millions) Cash and cash equivalents $ 182.8 $ 16.1 Available capacity under Revolving Credit Facility and CP Program (a) 746.8 612.7 Available liquidity $ 929.6 $ 628.8 Capital structure Short-term debt $ - $ 133.8 Long-term debt 4,701.1 4,250.2 Total debt 4,701.1 4,384.0 Total stockholders' equity (excludes non-controlling interest) 3,823.6 3,501.5 Total capitalization $ 8,524.7 $ 7,885.5 Debt to capitalization 55.1 % 55.6 % Long-term debt to total debt 100.0 % 96.9 % (a) Available capacity under Revolving Credit Facility and CP Program represents $750 million of total borrowing capacity less outstanding borrowings and letters of credit.
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.
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.
(c) Includes inter-segment rent and non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe. 43 Table of Contents Revenue Quantities Sold and Transported For the year ended December 31, For the year ended December 31, By Business Unit 2024 2023 2022 2024 2023 2022 (in millions) (Dth in millions) Arkansas Gas $ 248.8 $ 268.9 $ 311.3 29.9 30.2 32.3 Colorado Gas 278.8 313.6 320.9 31.0 32.8 34.3 Iowa Gas 162.3 213.6 283.9 37.3 37.9 40.9 Kansas Gas 130.4 155.6 191.4 34.8 35.5 38.6 Nebraska Gas 304.5 366.1 384.8 80.3 82.2 85.1 Wyoming Gas 144.6 166.4 176.8 37.0 36.4 36.7 Total Revenue and Quantities Sold $ 1,269.4 $ 1,484.2 $ 1,669.1 250.3 255.0 267.9 For the year ended December 31, 2024 2023 2022 Heating Degree Days Actual Variance From Normal Actual Variance From Normal Actual Variance From Normal Arkansas Gas (a) 2,998 (20)% 3,197 (17)% 3,844 2% Colorado Gas 5,662 (7)% 5,916 (4)% 6,325 4% Iowa Gas 5,543 (16)% 5,921 (12)% 7,037 7% Kansas Gas (a) 4,092 (12)% 4,387 (8)% 4,968 7% Nebraska Gas 5,172 (13)% 5,579 (8)% 6,220 4% Wyoming Gas 6,641 (10)% 7,385 8% 7,644 12% Combined (b) 5,517 (11)% 6,006 (4)% 6,536 5% (a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins.
(b) Includes inter-segment rent and non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe. 49 Table of Contents Revenue Quantities Sold and Transported For the year ended December 31, For the year ended December 31, By Business Unit 2025 2024 2023 2025 2024 2023 (in millions) (Dth in millions) Arkansas Gas $ 286.5 $ 248.8 $ 268.9 32.5 29.9 30.2 Colorado Gas 251.8 278.8 313.6 30.6 31.0 32.8 Iowa Gas 197.6 162.3 213.6 39.6 37.3 37.9 Kansas Gas 160.4 130.4 155.6 37.0 34.8 35.5 Nebraska Gas 344.5 304.5 366.1 85.1 80.3 82.2 Wyoming Gas 142.0 144.6 166.4 36.4 37.0 36.4 Total Revenue and Quantities Sold $ 1,382.8 $ 1,269.4 $ 1,484.2 261.2 250.3 255.0 For the year ended December 31, 2025 2024 2023 Heating Degree Days Actual Variance From Normal Actual Variance From Normal Actual Variance From Normal Arkansas Gas (a) 3,256 (9)% 2,998 (20)% 3,197 (17)% Colorado Gas 5,416 (7)% 5,662 (7)% 5,916 (4)% Iowa Gas 6,318 (1)% 5,543 (16)% 5,921 (12)% Kansas Gas (a) 4,530 --- 4,092 (12)% 4,387 (8)% Nebraska Gas (a) 5,630 (3)% 5,172 (13)% 5,579 (8)% Wyoming Gas 6,727 (7)% 6.641 (10)% 7,385 8% Combined (b) 5,802 (5)% 5.517 (11)% 6,006 (4)% (a) Arkansas Gas and Kansas Gas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins.
We anticipate growing our dividend in line with our targeted 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.
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.
Operating Statistics Revenue Quantities Sold and Transported For the year ended December 31, For the year ended December 31, By Customer Class 2024 2023 2022 2024 2023 2022 (in millions (Dth in millions) Retail Revenue - Residential $ 691.9 $ 830.3 $ 942.3 56.7 60.1 66.9 Commercial 266.3 337.3 399.2 28.4 29.4 32.4 Industrial 23.7 33.1 63.0 6.0 5.7 7.7 Other Retail (a) 40.7 48.1 48.8 — — — Subtotal Retail Revenue - Gas (b) 1,022.6 1,248.8 1,453.3 91.1 95.2 107.0 Transportation 178.2 176.8 173.3 159.2 159.8 160.9 Other (c) 68.6 58.6 42.5 — — — Total Revenue and Quantities Sold $ 1,269.4 $ 1,484.2 $ 1,669.1 250.3 255.0 267.9 (a) Includes Black Hills Energy Services revenue under the Choice Gas Program.
Operating Statistics Revenue Quantities Sold and Transported For the year ended December 31, For the year ended December 31, By Customer Class 2025 2024 2023 2025 2024 2023 (in millions (Dth in millions) Retail Revenue - Residential $ 770.2 $ 691.9 $ 830.3 59.9 56.7 60.1 Commercial 292.9 266.3 337.3 29.4 28.4 29.4 Industrial 27.2 23.7 33.1 5.2 6.0 5.7 Other Retail (a) 34.6 40.7 48.1 — — — Subtotal Retail Revenue - Gas 1,124.9 1,022.6 1,248.8 94.5 91.1 95.2 Transportation 194.4 178.2 176.8 166.7 159.2 159.8 Other (b) 63.5 68.6 58.6 — — — Total Revenue and Quantities Sold $ 1,382.8 $ 1,269.4 $ 1,484.2 261.2 250.3 255.0 (a) Includes Black Hills Energy Services revenue under the Choice Gas Program.
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.
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.
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 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.
(b) 2024 included unplanned outages at Wygen I and Pueblo Airport Generation #4-5. 42 Table of Contents Gas Utilities Operating results for the years ended December 31 for the Gas Utilities were as follows: 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions) Total revenue $ 1,269.4 $ 1,484.2 $ (214.8 ) $ 1,669.1 $ (184.9 ) Cost of natural gas sold 524.3 783.2 (258.9 ) 965.1 (181.9 ) Gas Utility margin (non-GAAP) 745.1 701.0 44.1 704.0 (3.0 ) Operations and maintenance 320.7 328.7 (8.0 ) 317.3 11.4 Depreciation and amortization 124.7 113.9 10.8 114.7 (0.8 ) Taxes other than income taxes 28.4 29.6 (1.2 ) 27.8 1.8 473.8 472.2 1.6 459.8 12.4 Operating income $ 271.3 $ 228.8 $ 42.5 $ 244.2 $ (15.4 ) 2024 Compared to 2023 Gas Utility margin increased as a result of: (in millions) New rates and rider recovery $ 48.7 Mark-to-market on non-utility natural gas commodity contracts 4.9 Retail customer growth and usage 3.6 Weather (15.9 ) Other 2.8 $ 44.1 Operations and maintenance expense decreased primarily due to $10.8 million of lower employee-related expenses driven by lower headcount, $2.9 million decreased bad debt expense attributable to lower customer billings, and $1.2 million of lower training expense partially offset by $3.3 million of higher insurance expense and $2.8 million of higher IT-related expenses.
(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. 48 Table of Contents Gas Utilities Operating results for the years ended December 31 for the Gas Utilities were as follows: 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions) Total revenue $ 1,382.8 $ 1,269.4 $ 113.4 $ 1,484.2 $ (214.8 ) Cost of natural gas sold 572.3 524.3 48.0 783.2 (258.9 ) Gas Utility margin (non-GAAP) 810.5 745.1 65.4 701.0 44.1 Operations and maintenance 328.0 320.7 7.3 328.7 (8.0 ) Depreciation and amortization 131.4 124.7 6.7 113.9 10.8 Taxes other than income taxes 30.3 28.4 1.9 29.6 (1.2 ) 489.7 473.8 15.9 472.2 1.6 Operating income $ 320.8 $ 271.3 $ 49.5 $ 228.8 $ 42.5 2025 Compared to 2024 • Gas Utility margin increased as a result of: (in millions) New rates and rider recovery $ 60.9 Weather 10.9 Transport and transmission 3.3 Retail customer growth 4.3 Retail customer usage (11.0 ) Other (3.0 ) $ 65.4 • 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.
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.
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.
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. 51 Table of Contents See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
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.
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 fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
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.
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. 38 Table of Contents Results of Operations Our discussion and analysis for the year ended December 31, 2024, compared to 2023, is included herein.
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.
Electric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses, depreciation and amortization expenses, and taxes other than income taxes from the measure. Electric Utility margin is calculated as operating revenue less cost of fuel and purchased power.
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.
See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 49 Table of Contents On January 24, 2025, our Board of Directors declared a quarterly dividend of $0.676 per share, equivalent to an annual dividend rate of $2.704 per share.
For additional information. see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 55 Table of Contents 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.
Investing Activities: 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions) Capital expenditures $ (744.2 ) $ (555.6 ) $ (188.6 ) $ (604.4 ) $ 48.8 Other investing activities (1.8 ) 18.9 (20.7 ) 0.5 18.4 Net cash (used in) investing activities $ (746.0 ) $ (536.7 ) $ (209.3 ) $ (603.9 ) $ 67.2 2024 Compared to 2023 Net cash used in investing activities was $209.3 million higher which was attributable to: • Cash outflows from capital expenditures (which are net of contributions in aid of construction) increased $188.6 million primarily as a result of Wyoming Electric's Ready Wyoming electric transmission expansion project and Black Hills Energy Renewable Resources' acquisition of a RNG production facility at a landfill in Dubuque, Iowa. 46 Table of Contents • Cash outflows increased $20.7 million for other investing activities primarily due to 2023 proceeds from the sale of Northern Iowa Windpower assets and a sale of land to support data center growth.
Investing Activities: 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions) Capital expenditures $ (819.8 ) $ (744.2 ) $ (75.6 ) $ (555.6 ) $ (188.6 ) Other investing activities (8.4 ) (1.8 ) (6.6 ) 18.9 (20.7 ) Net cash (used in) investing activities $ (828.2 ) $ (746.0 ) $ (82.2 ) $ (536.7 ) $ (209.3 ) 52 Table of Contents 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.
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.
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.
Regarding the addition of 99 MWs of generation, South Dakota Electric expects to request a CPCN from the WPSC in the first quarter of 2025. • Published Wildfire Mitigation Plan: 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.
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.
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, Colorado Gas, Iowa Gas, Kansas Gas and Wyoming Gas. • See Key Elements of our Business Strategy section above for discussion of recent developments related to BHERR's purchase of a RNG production facility in Iowa.
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.
See Key Elements of our Business Strategy section above for additional information. 41 Table of Contents For the year ended December 31, Quantities Generated and Purchased by Business Unit 2024 2023 2022 (in GWh) Generated: Colorado Electric 865.0 653.9 474.4 South Dakota Electric 2,045.4 2,018.5 1,890.0 Wyoming Electric 866.5 908.3 905.8 Integrated Generation 1,600.7 1,802.5 1,768.6 Total Generated 5,377.6 5,383.2 5,038.8 Purchased: Colorado Electric 447.4 588.2 1,005.4 South Dakota Electric 590.7 604.6 826.4 Wyoming Electric 1,147.7 1,028.5 757.2 Integrated Generation 62.1 55.2 85.1 Total Purchased 2,247.9 2,276.5 2,674.1 Total Generated and Purchased 7,625.5 7,659.7 7,712.9 For the year ended December 31, 2024 2023 2022 Degree Days Actual Variance from Normal Actual Variance from Normal Actual Variance from Normal Heating Degree Days: Colorado Electric 4,926 (8)% 5,330 1% 5,551 9% South Dakota Electric 6,311 (13)% 6,969 (4)% 7,495 6% Wyoming Electric 6,272 (10)% 6,783 (1)% 7,051 3% Combined (a) 5,676 (10)% 6,185 (1)% 6,518 6% Cooling Degree Days: Colorado Electric 1,269 11% 1,046 (10)% 1,362 9% South Dakota Electric 913 49% 497 (21)% 814 27% Wyoming Electric 491 7% 329 (30)% 701 47% Combined (a) 989 20% 713 (15)% 1,040 18% (a) Degree days are calculated based on a weighted average of total customers by state.
(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. 47 Table of Contents For the year ended December 31, Quantities Generated and Purchased by Business Unit 2025 2024 2023 (in GWh) Generated: Colorado Electric 742.4 865.0 653.9 South Dakota Electric 1,758.1 2,045.4 2,018.5 Wyoming Electric 891.7 866.5 908.3 Integrated Generation 1,675.1 1,600.7 1,802.5 Total Generated 5,067.3 5,377.6 5,383.2 Purchased: Colorado Electric 350.3 447.4 588.2 South Dakota Electric 1,034.0 590.7 604.6 Wyoming Electric 1,637.1 1,147.7 1,028.5 Integrated Generation 54.9 62.1 55.2 Total Purchased 3,076.3 2,247.9 2,276.5 Total Generated and Purchased 8,143.6 7,625.5 7,659.7 For the year ended December 31, 2025 2024 2023 Degree Days Actual Variance from Normal Actual Variance from Normal Actual Variance from Normal Heating Degree Days: Colorado Electric 5,104 (1)% 4,926 (8)% 5,330 1% South Dakota Electric 6,511 (7)% 6,311 (13)% 6,969 (4)% Wyoming Electric 6,378 (5)% 6,272 (10)% 6,783 (1)% Combined (a) 5,850 (4)% 5,676 (10)% 6,185 (1)% Cooling Degree Days: Colorado Electric 1,016 (13)% 1,269 11% 1,046 (10)% South Dakota Electric 778 18% 913 49% 497 (21)% Wyoming Electric 337 (30)% 491 7% 329 (30)% Combined (a) 796 (7)% 989 20% 713 (15)% (a) Degree days are calculated based on a weighted average of total customers by state.
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.
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.
Revenue Quantities Sold For the year ended December 31, For the year ended December 31, By Business Unit 2024 2023 2022 2024 2023 2022 (in millions) (in GWh) Colorado Electric $ 276.9 $ 285.7 $ 321.1 2,392.7 2,397.2 2,440.0 South Dakota Electric 322.0 321.1 335.2 2,556.5 2,554.3 2,626.2 Wyoming Electric 234.3 212.2 197.7 2,190.1 2,124.1 1,903.7 Integrated Generation 42.9 46.0 46.2 95.9 120.6 293.0 Total Revenue and Quantities Sold $ 876.1 $ 865.0 $ 900.2 7,235.2 7,196.2 7,262.9 For the year ended December 31, Quantities Generated and Purchased by Fuel Type 2024 2023 2022 (in GWh) Generated: Coal 2,478.3 2,683.4 2,708.8 Natural Gas 2,239.1 2,021.4 1,454.2 Wind 660.2 678.5 875.8 Total Generated 5,377.6 5,383.3 5,038.8 Purchased: Coal, Natural Gas, Diesel Oil and Other Market Purchases (a) 1,117.8 1,842.9 2,280.8 Wind and Solar (a) 1,130.1 433.5 393.3 Total Purchased 2,247.9 2,276.4 2,674.1 Total Generated and Purchased 7,625.5 7,659.7 7,712.9 (a) The shift in purchases by fuel type for 2024 compared to 2023 is primarily due to Wyoming Electric's new wind and solar energy PPAs, which replaced market purchases from other fuel types, and are used to serve our LPCS customers.
Revenue Quantities Sold For the year ended December 31, For the year ended December 31, By Business Unit 2025 2024 2023 2025 2024 2023 (in millions) (in GWh) Colorado Electric $ 287.3 $ 276.9 $ 285.7 2,218.1 2,392.7 2,397.2 South Dakota Electric 341.6 322.0 321.1 2,683.2 2,556.5 2,554.3 Wyoming Electric 270.0 234.3 212.2 2,676.8 2,190.1 2,124.1 Integrated Generation 43.9 42.9 46.0 88.7 95.9 120.6 Total Revenue and Quantities Sold $ 942.8 $ 876.1 $ 865.0 7,666.8 7,235.2 7,196.2 For the year ended December 31, Quantities Generated and Purchased by Fuel Type 2025 2024 2023 (in GWh) Generated: Coal (a) 2,075.0 2,478.3 2,683.4 Natural Gas 2,389.4 2,239.1 2,021.4 Wind 602.9 660.2 678.5 Total Generated 5,067.3 5,377.6 5,383.3 Purchased: Coal, Natural Gas, Diesel Oil and Other Market Purchases 1,860.6 1,117.8 1,842.9 Wind and Solar 1,215.7 1,130.1 433.5 Total Purchased (b) 3,076.3 2,247.9 2,276.4 Total Generated and Purchased 8,143.6 7,625.5 7,659.7 (a) The decrease in coal generation for 2025 compared to 2024 was primarily driven by unplanned outages at Wygen III.
Consolidated Interest Expense, Other Income (Expense) and Income Tax (Expense ) 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions) Interest expense, net $ (181.7 ) $ (167.9 ) $ (13.8 ) $ (161.0 ) $ (6.9 ) Other income (expense), net (1.4 ) (3.2 ) 1.8 1.8 (5.0 ) Income tax (expense) (36.3 ) (25.6 ) (10.7 ) (25.2 ) (0.4 ) 2024 Compared to 2023 Interest expense, net increased due to higher interest rates partially offset by higher interest income and higher AFUDC debt driven by higher construction work-in-progress balances.
Consolidated Interest Expense, Other Income (Expense) and Income Tax (Expense ) 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions) Interest expense, net $ (200.1 ) $ (181.7 ) $ (18.4 ) $ (167.9 ) $ (13.8 ) Other income (expense), net 6.1 (1.4 ) 7.5 (3.2 ) 1.8 Income tax (expense) (43.7 ) (36.3 ) (7.4 ) (25.6 ) (10.7 ) 50 Table of Contents 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.
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. 50 Table of Contents As of December 31, 2024, and 2023, we had total regulatory assets of $427.7 million and $480.1 million, respectively, and total regulatory liabilities of $568.7 million and $566.6 million, respectively.
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.
Our actual 2024 and forecasted capital expenditures for the next five years from 2025 through 2029 are as follows: 35 Table of Contents Actual (a) Forecasted (b) Capital Expenditures by Segment (minor differences may result due to rounding) 2024 2025 2026 2027 2028 2029 (in millions) Electric Utilities $ 382 $ 550 $ 432 $ 383 $ 615 $ 435 Gas Utilities 403 431 386 412 447 447 Corporate and Other 13 21 41 27 27 27 Total $ 798 $ 1,002 $ 859 $ 822 $ 1,089 $ 909 (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.
Our actual 2025 and forecasted capital expenditures for the next five years from 2026 through 2030 are as follows: Actual (a) Forecasted (b) Capital Expenditures by Segment (minor differences may result due to rounding) 2025 2026 2027 2028 2029 2030 (in millions) Electric Utilities $ 481 $ 471 $ 367 $ 455 $ 356 $ 391 Gas Utilities 397 396 455 507 591 552 Corporate and Other 11 39 22 21 22 25 Total $ 890 $ 906 $ 844 $ 983 $ 969 $ 968 (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.
Financing Activities: 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions) Dividends paid on common stock $ (182.3 ) $ (168.1 ) $ (14.2 ) $ (156.7 ) $ (11.4 ) Common stock issued 181.4 118.3 63.1 90.1 28.2 Short-term and long-term debt borrowings (repayments), net (16.2 ) (260.6 ) 244.4 115.4 (376.0 ) Distributions to non-controlling interests (17.4 ) (18.3 ) 0.9 (17.4 ) (0.9 ) Other financing activities (8.4 ) (13.0 ) 4.6 0.9 (13.9 ) Net cash provided by (used in) financing activities $ (42.9 ) $ (341.7 ) $ 298.8 $ 32.3 $ (374.0 ) 2024 Compared to 2023 Net cash used in financing activities was $298.8 million lower which was primarily attributable to: • Cash outflows increased $14.2 million due to increased dividends paid on increased shares of common stock outstanding; • Cash inflows increased $63.1 million due to higher issuances of common stock; • Net outflows from changes in short-term and long-term debt (repayments) borrowings decreased $244.4 million due to: o Net cash inflows increased $669.4 million as a result of net borrowing activity under our Revolving Credit Facility and CP Program; and o Cash inflows decreased $350 million due to issuances of $450 million of senior unsecured notes in May 2024 compared to issuances of $350 million of senior unsecured notes in March 2023 and $450 million of senior unsecured notes in September 2023; and o Cash outflows increased $75 million due to repayment of our $600 million senior unsecured notes in August 2024 compared to repayment of our $525 million senior unsecured notes in November 2023. • Cash outflows decreased by $4.6 million for other financing activities primarily due to lower financing costs from the May 2024 debt offering compared to the March 2023 and September 2023 debt offerings.
Financing Activities: 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions) Dividends paid on common stock $ (197.9 ) $ (182.3 ) $ (15.6 ) $ (168.1 ) $ (14.2 ) Common stock issued 219.2 181.4 37.8 118.3 63.1 Short-term and long-term debt borrowings (repayments), net 316.2 (16.2 ) 332.4 (260.6 ) 244.4 Distributions to non-controlling interests (9.8 ) (17.4 ) 7.6 (18.3 ) 0.9 Other financing activities (5.9 ) (8.4 ) 2.5 (13.0 ) 4.6 Net cash provided by (used in) financing activities $ 321.8 $ (42.9 ) $ 364.7 $ (341.7 ) $ 298.8 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.
Electric Utilities Operating results for the years ended December 31 for the Electric Utilities were as follows: 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions) Total revenue $ 876.1 $ 865.0 $ 11.1 $ 900.2 $ (35.2 ) Fuel and purchased power: 206.4 200.1 6.3 266.3 (66.2 ) Electric Utility margin (non-GAAP) 669.7 664.9 4.8 633.9 31.0 Operations and maintenance 252.6 236.2 16.4 244.8 (8.6 ) Depreciation and amortization 145.3 142.6 2.7 135.9 6.7 Taxes other than income taxes 38.8 37.3 1.5 38.9 (1.6 ) 436.7 416.1 20.6 419.6 (3.5 ) Operating income $ 233.0 $ 248.8 $ (15.8 ) $ 214.3 $ 34.5 2024 Compared to 2023 Electric Utility margin increased as a result of: (in millions) New rates and rider recovery $ 15.8 Retail customer growth and usage 3.8 Weather 2.7 Off-system excess energy sales (7.8 ) 2023 Wygen I revenue recovery under business interruption insurance (a) (5.0 ) Unplanned generation outages (4.0 ) Other (0.7 ) $ 4.8 (a) In 2021, Wygen I experienced an unplanned outage which resulted in lost revenue.
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. 45 Table of Contents Electric Utilities Operating results for the years ended December 31 for the Electric Utilities were as follows: 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions) Total revenue $ 942.8 $ 876.1 $ 66.7 $ 865.0 $ 11.1 Fuel and purchased power: 259.6 206.4 53.2 200.1 6.3 Electric Utility margin (non-GAAP) 683.2 669.7 13.5 664.9 4.8 Operations and maintenance 271.2 252.6 18.6 236.2 16.4 Depreciation and amortization 152.4 145.3 7.1 142.6 2.7 Taxes other than income taxes 37.1 38.8 (1.7 ) 37.3 1.5 460.7 436.7 24.0 416.1 20.6 Operating income $ 222.5 $ 233.0 $ (10.5 ) $ 248.8 $ (15.8 ) 2025 Compared to 2024 • Electric Utility margin increased as a result of: (in millions) New rates and rider recovery $ 25.0 Retail customer growth and usage 1.9 Transmission services (5.9 ) Weather (2.7 ) Off-system excess energy sales (1.8 ) Other (3.0 ) $ 13.5 • 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.
The table below provides our dividends paid, dividend payout ratio, and dividends paid per share for the three years ended December 31: 2024 2023 2022 (Dividends Paid in millions) Common Stock Dividends Paid $ 182.3 $ 168.1 $ 156.7 Dividend Payout Ratio 66 % 64 % 61 % Dividends Per Share $ 2.60 $ 2.50 $ 2.41 Our three-year compound annualized dividend growth rate was 4.3%.
The table below provides our dividends paid, dividend payout ratio, and dividends paid per share for the three years ended December 31: 2025 2024 2023 (Dividends Paid in millions) Common Stock Dividends Paid $ 197.9 $ 182.3 $ 168.1 Dividend Payout Ratio 68 % 66 % 64 % Dividends Per Share $ 2.70 $ 2.60 $ 2.50 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 $41.4 million as of December 31, 2024, compared to $39.5 million as of December 31, 2023. See further information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
See further information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
We also plan to re-finance our $300 million, 3.95%, senior unsecured notes due January 2026, at or before maturity date. 45 Table of Contents CASH FLOW ACTIVITIES The following tables summarize our cash flows for the years ended December 31: Operating Activities: 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions) Net income $ 283.7 $ 276.0 $ 7.7 $ 270.8 $ 5.2 Non-cash adjustments to Net income 350.5 313.5 37.0 295.7 17.8 Total earnings 634.2 589.5 44.7 566.5 23.0 Changes in certain operating assets and liabilities: Materials, supplies and fuel, Accounts receivable and other current assets (12.5 ) 255.9 (268.4 ) (259.9 ) 515.8 Accounts payable and accrued liabilities 28.8 (109.9 ) 138.7 89.4 (199.3 ) Regulatory assets 90.0 236.8 (146.8 ) 203.9 32.9 Net inflow from changes in certain operating assets and liabilities 106.3 382.8 (276.5 ) 33.4 349.4 Other operating activities (21.2 ) (27.9 ) 6.7 (15.1 ) (12.8 ) Net cash provided by operating activities $ 719.3 $ 944.4 $ (225.1 ) $ 584.8 $ 359.6 2024 Compared to 2023 Net cash provided by operating activities was $225.1 million lower which was attributable to: • Total earnings (net income plus non-cash adjustments) were $44.7 million higher primarily as a result of increased Electric and Gas Utility margins due to new rates, rider recovery and customer growth, partially offset by unfavorable weather, higher operating expenses and higher financing costs. • Net inflows from changes in certain operating assets and liabilities were $276.5 million lower, primarily attributable to: o Cash inflows decreased by approximately $268.4 million as a result of changes in accounts receivable and other current assets primarily due to lower collections on pass-through revenues and lower natural gas in storage inventories driven by fluctuations in commodity prices and timing of injections and withdrawals; o Cash outflows decreased by approximately $138.7 million as a result of increases in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, payment timing of natural gas and power purchases, and changes in other working capital requirements; and o Cash inflows decreased by approximately $146.8 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of deferred gas and fuel cost adjustments driven by fluctuations in commodity prices. • Cash outflows decreased $6.7 million from other operating activities primarily due to lower costs from cloud computing arrangements.
Additionally, our current shelf registration statement expires in 2026 and we expect to file a new shelf registration statement to replace it. 51 Table of Contents CASH FLOW ACTIVITIES The following tables summarize our cash flows for the years ended December 31: Operating Activities: 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions) Net income $ 299.8 $ 283.7 $ 16.1 $ 276.0 $ 7.7 Non-cash adjustments to Net income 372.1 350.5 21.6 313.5 37.0 Total earnings 671.9 634.2 37.7 589.5 44.7 Changes in certain operating assets and liabilities: Materials, supplies and fuel, Accounts receivable and other current assets (62.8 ) (12.5 ) (50.3 ) 255.9 (268.4 ) Accounts payable and accrued liabilities 24.0 28.8 (4.8 ) (109.9 ) 138.7 Regulatory assets 59.1 90.0 (30.9 ) 236.8 (146.8 ) Net inflow from changes in certain operating assets and liabilities 20.3 106.3 (86.0 ) 382.8 (276.5 ) Other operating activities (18.8 ) (21.2 ) 2.4 (27.9 ) 6.7 Net cash provided by operating activities $ 673.4 $ 719.3 $ (45.9 ) $ 944.4 $ (225.1 ) 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.
Depreciation and amortization increased primarily due to a higher asset base driven by capital expenditures. Taxes other than income taxes were comparable.
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.
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 recent ATM program activity and our May 16, 2024, debt offering. • On May 31, 2024, we amended and restated our corporate Revolving Credit Facility.
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. 53 Table of Contents 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.
Taxes other than income taxes were comparable. 40 Table of Contents Operating Statistics Revenue Quantities Sold For the year ended December 31, For the year ended December 31, By Customer Class 2024 2023 2022 2024 2023 2022 (in millions) (in GWh) Retail Revenue - Residential $ 234.8 $ 224.5 $ 246.2 1,471.9 1,438.5 1,513.1 Commercial 263.6 254.5 272.4 2,091.4 2,074.4 2,087.8 Industrial 168.9 157.3 163.9 2,169.8 2,094.8 1,912.5 Municipal 17.0 17.5 20.5 147.1 150.9 159.3 Other Retail 14.3 12.3 6.2 — — — Subtotal Retail Revenue - Electric 698.6 666.1 709.2 5,880.2 5,758.6 5,672.7 Wholesale 26.8 34.2 44.8 589.4 699.7 947.0 Market - off-system sales 34.8 50.9 48.6 765.6 737.9 643.2 Transmission 52.2 47.1 40.5 — — — Other (a) 63.7 66.7 57.1 — — — Total Revenue and Quantities Sold $ 876.1 $ 865.0 $ 900.2 7,235.2 7,196.2 7,262.9 Other Uses, Losses or Generation, net (b) 390.3 463.5 450.0 Total Energy 7,625.5 7,659.7 7,712.9 (a) 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.
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. 46 Table of Contents Operating Statistics Revenue Quantities Sold For the year ended December 31, For the year ended December 31, By Customer Class 2025 2024 2023 2025 2024 2023 (in millions) (in GWh) Retail Revenue - Residential $ 248.2 $ 234.8 $ 224.5 1,461.5 1,471.9 1,438.5 Commercial 279.4 263.6 254.5 2,068.1 2,091.4 2,074.4 Industrial (a) 201.0 168.9 157.3 2,615.4 2,169.8 2,094.8 Municipal 17.8 17.0 17.5 142.1 147.1 150.9 Other Retail 14.0 14.3 12.3 — — — Subtotal Retail Revenue - Electric 760.4 698.6 666.1 6,287.1 5,880.2 5,758.6 Wholesale 21.7 26.8 34.2 483.0 589.4 699.7 Market - off-system sales 51.9 34.8 50.9 896.7 765.6 737.9 Transmission 45.2 52.2 47.1 — — — Other (b) 63.6 63.7 66.7 — — — Total Revenue and Quantities Sold $ 942.8 $ 876.1 $ 865.0 7,666.8 7,235.2 7,196.2 Other Uses, Losses or Generation, net (c) 476.8 390.3 463.5 Total Energy 8,143.6 7,625.5 7,659.7 (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.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2024: Rating Agency Senior Unsecured Rating Outlook S&P (a) BBB+ Stable Moody’s (b) Baa2 Stable Fitch (c) BBB+ Negative (a) On May 9, 2024, S&P reported BBB+ rating and maintained a Stable outlook.
The following table represents the credit ratings and rating outlook of BHC as of the date of this report: Rating Agency Senior Unsecured Rating Outlook S&P (a) BBB+ Stable Moody’s (b) Baa2 Stable (a) On August 19, 2025, S&P affirmed our BBB+ rating and maintained a Stable outlook.
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.
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. 57 Table of Contents Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit.
This project is also expected to attract data center and blockchain customers, enable economic growth in Wyoming, expand access to renewable resources and facilitate additional renewable development across wind- and sun-rich resource areas. • Advanced South Dakota IRP: In June 2021, South Dakota Electric submitted an IRP to the SDPUC and WPSC.
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.
Gas Utility margin is calculated as operating revenue less cost of natural gas sold. Our Electric and Gas Utility margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs.
We define Electric and Gas Utility margin as operating revenue less cost of fuel, purchased power and cost of natural gas sold.
(b) On January 8, 2025, Moody's reported our Baa2 rating and maintained a Stable outlook. (c) On January 17, 2025, Fitch affirmed its BBB+ rating for BHC and maintained a Negative outlook.
(b) On August 19, 2025, Moody's affirmed our Baa2 rating and maintained a Stable outlook.
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.
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.
Corporate and Other Corporate and Other operating results, including inter-segment eliminations, for the years ended December 31 were as follows: 2024 2023 2024 vs 2023 Variance 2022 2023 vs 2022 Variance (in millions) Operating (loss) $ (1.2 ) $ (4.9 ) $ 3.7 $ (3.3 ) $ (1.6 ) 2024 Compared to 2023 Operating (loss) decreased primarily due to lower unallocated outside services expenses and a gain on the sale of a Corporate asset.
Corporate and Other operating results for the years ended December 31 were as follows: 2025 2024 2025 vs 2024 Variance 2023 2024 vs 2023 Variance (in millions) Operating (loss) $ (5.8 ) $ (1.2 ) $ (4.6 ) $ (4.9 ) $ 3.7 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.
(b) Heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.
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.
For additional information. see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 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.
See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. 58 Table of Contents
On July 11, 2024, Wyoming Electric announced it will partner with Meta to provide power for its newest AI data center to be constructed in Cheyenne, Wyoming.
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.
However, while these fluctuating costs impact Electric and Gas Utility margin as a percentage of revenue, they only impact total Electric and Gas Utility margin if the costs cannot be passed through to our customers. Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures.
Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures.
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. See above in Key Elements of our Business Strategy for forecasted capital expenditure requirements.
The following table represents the credit ratings of South Dakota Electric as of the date of this report: Rating Agency Senior Secured Rating S&P (a) A (a) On August 19, 2025, S&P affirmed A rating. 54 Table of Contents 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.
The effective tax rate was higher primarily due to a $8.2 million tax benefit in 2023 from a Nebraska income tax rate decrease. 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.
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.
The project is expected to be completed in multiple segments through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems. The project will provide customers long-term price stability and greater flexibility as power markets develop in the Western States.
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.
(b) Retail gas revenues decreased in 2024 compared to 2023 primarily due to lower commodity prices. Our Utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer. Customer billing rates are adjusted periodically to reflect changes in our cost of energy.
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.
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. • See Key Elements of our Business Strategy section above for discussion of recent developments related to our partnership with Meta, construction progress on our Ready Wyoming project, Colorado Electric's Clean Energy Plan, South Dakota Electric's IRP and the addition of 99 MWs of new generation, and publishing of our first formal WMP and plans to formalize our PSPS. • In 2024, Wygen I and Pueblo Airport Generation #4-5 experienced unplanned generation outages that had a $8.3 million negative impact to Operating income.
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.
By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations. Key Elements of our Business Strategy Explore opportunities as an energy solutions provider. A key strategic initiative is to grow our business through innovative energy solutions with new customers and partnerships.
By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations. 42 Table of Contents Recent Developments Pending Merger with NorthWestern On August 18, 2025, we entered into the Merger Agreement with NorthWestern and Merger Sub.
Removed
We see value creation by recruiting new customers and expanding existing partnerships with data centers and blockchain customers; exploring energy markets; and expanding our transmission capabilities. A few recent examples of our initiatives to grow our business as an energy solutions provider include: • Announced Partnership with Meta.
Added
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.
Removed
Wyoming Electric plans to procure market energy under its LPCS Tariff with customized energy resources essential to Meta's operations and sustainability objectives. • Innovatively served LPCS load: In 2022, Wyoming Electric entered into two new PPAs with third parties to purchase up to 106 MWs of wind energy and up to 150 MWs of solar energy, upon construction of new renewable generation facilities (owned by third parties).
Added
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.
Removed
The new wind generation facility was placed in service in December 2023 and the solar facility was placed in service in March 2024.
Added
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.
Removed
The renewable energy from these PPAs is used to serve our expanding partnerships with LPCS customers. 34 Table of Contents • Expanded BCIS Load: We have supported enabling legislation in Wyoming for the growing blockchain businesses while implementing our own BCIS Tariff to serve these customers.
Added
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.
Removed
We currently have agreements with two customers to provide up to 130 MWs in Cheyenne, Wyoming under this Tariff. Energy is sourced through the electric energy market and delivered through our Electric Utilities’ infrastructure. Under these agreements, the customers are responsible for costs of service, and the load is interruptible to prioritize the needs of Wyoming Electric’s existing retail customers.
Added
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.
Removed
Modernize and operate utility infrastructure to provide customers with safe, reliable, cost-effective electric and natural gas service. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that spans nearly 1,600 miles.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

6 edited+0 added−0 removed24 unchanged
Biggest changeA hypothetical 100 basis point increase in the benchmark rate on our variable rate debt would have increased annual pretax interest expense by approximately $0.3 million and $0.9 million for the years ended December 31, 2024, and 2023, respectively. See Note 8 for further information on cash amounts outstanding under short- and long-term variable rate borrowings.
Biggest changeA hypothetical 100 basis point increase in the benchmark rate on our variable rate debt would not materially impact pre-tax interest expense for the years ended December 31, 2025, and 2024, respectively. See Note 8 for further information on cash amounts outstanding under short- and long-term variable rate borrowings.
To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin. 52 Table of Contents Black Hills Energy Services Through our non-regulated natural gas commodity supplier, we buy and sell natural gas in Nebraska and Wyoming at competitive prices by managing commodity price risk.
To manage such risk, we restrict wholesale off-system sales to amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load requirements plus a required reserve margin. 59 Table of Contents Black Hills Energy Services Through our non-regulated natural gas commodity supplier, we buy and sell natural gas in Nebraska and Wyoming at competitive prices by managing commodity price risk.
At December 31, 2024, and 2023, a 10% change in market prices for our derivative instruments would not materially impact pre-tax income, the fair values of our derivative assets and liabilities, or OCI. See additional commodity risk and derivative information in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
At December 31, 2025, and 2024, a 10% change in market prices for our derivative instruments would not materially impact pre-tax income, the fair values of our derivative assets and liabilities, or OCI. See additional commodity risk and derivative information in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Interest Rate Risk Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and anticipated debt refinancings. At December 31, 2024, we had no interest rate swaps in place.
Interest Rate Risk Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and anticipated debt refinancings. At December 31, 2025, we had no interest rate swaps in place.
See more information in Notes 1 and 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 53 Table of Contents
See more information in Notes 1 and 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 60 Table of Contents
Further details of past swap agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. At December 31, 2024, 96.9% of our debt is fixed rate debt, which limits our exposure to variable interest rate fluctuations.
Further details of past swap agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. At December 31, 2025, 99.8% of our debt is fixed rate debt, which limits our exposure to variable interest rate fluctuations.

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