Black Hills Corp: Form 10-K for the period ended Dec 31, 2024

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).

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. 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 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 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. Additionally, we provide non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.

We also own and operate non-regulated power generation and mining assets that are vertically integrated into and primarily support our Electric Utilities. All of these operations are located at our electric generating complexes and are physically integrated into our Electric Utilities’ operations.

Capacity and Demand. System Peak Demand for the Electric Utilities’ retail customers for each of the last three years are listed below:

(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.

As of December 31, 2024, our Electric Utilities’ ownership interests in electric generating plants were as follows:

(a) The PTCs for Peak View flow back to customers through the RESA and ECA mechanisms as a reduction to Colorado Electric’s margins.

(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.

(d) Non-controlling interest is discussed in Note 12 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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:

(a) Wind generation decreased due to the sale of Northern Iowa Windpower assets in March 2023.

(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.

(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. The renewable energy from these PPAs is used to serve our expanding partnerships with LPCS customers.

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:

Purchased Power. We have executed various PPAs to support our Electric Utilities’ capacity and energy needs beyond our regulated power plants’ generation, which include long-term related party agreements with our non-regulated power generation businesses. See additional information in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Coal Mining. We own and operate a single coal mine through our WRDC subsidiary which is reported within our Electric Utilities segment. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine located immediately adjacent to our Gillette Energy Complex in the Powder River Basin in northeastern Wyoming, where our five coal-fired power plants are located. 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. 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. 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). 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. 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.

At December 31, 2024, our Electric Utilities owned the electric transmission and distribution lines shown below:

(a) Electric transmission line miles include voltages of 69 kV and above.

(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. 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. Various legislative or regulatory restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date, these initiatives have not had a material impact on our utilities. In Colorado and Wyoming, our electric utilities are subject to rules which may require competitive bidding for generation supply. Because of these rules, our Electric Utilities face competition from other utilities and non-affiliated IPPs for the right to supply electric energy and capacity when resource plans require additional resources. Additionally, electrification initiatives in our service territories could increase demand for electricity and increase customer growth.

The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess. With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity to foster competition within the wholesale electricity markets. Our non-regulated power generation businesses could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulations requiring utilities to competitively bid generation resources may provide opportunity for IPPs in some regions. To date, these initiatives have not had a material impact on our non-regulated power generation businesses.

Our mining business strategy is to sell nearly all of our production to on-site generation facilities under long-term supply contracts. Historically, any off-site sales have been to consumers within close proximity to WRDC. Coal competes with other energy sources, such as natural gas, nuclear, wind, solar, and hydropower. Costs and other factors relating to these alternative fuels, such as safety, environmental, and availability considerations affect the overall demand for coal as a fuel.

Operating Statistics. See a summary of key operating statistics in the Electric 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.

Gas Utilities

We conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming subsidiaries. Our Gas Utilities transport and distribute natural gas through our distribution network to our retail customers. Additionally, we sell contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-available basis.

We also provide non-regulated services to our regulated customers. 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.

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. The majority of our procured natural gas is transported in interstate pipelines under firm transportation service agreements.

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.

The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities as of December 31, 2024:

The following table summarizes certain information regarding our system infrastructure as of December 31, 2024:

Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating results. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as market price. In particular, demand is often greater in the winter months for heating. Natural gas is used primarily for residential and commercial heating, and demand for this product can depend heavily upon weather throughout our service territories. As a result, a significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters. 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. These initiatives are aimed at increasing competition. Additionally, electrification initiatives in our service territories could negatively impact demand for natural gas and decrease future growth. To date, these initiatives have not had a material impact on our utilities. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial customers, in instances where independent marketers displace us as the seller of natural gas, we still collect fees for transporting the gas through our distribution network.

Operating statistics. 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.

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. The EPA also works with industries and all levels of government, including federal and state governments, in a wide variety of voluntary pollution prevention programs and energy conservation efforts;
• the PHMSA, which is responsible for administering the federal regulatory program to help ensure the safe transportation of natural gas, petroleum, and other hazardous materials by pipelines, including pipelines associated with natural gas storage, and develops regulations and other approaches to risk management to help ensure safety in design, construction, testing, operation, maintenance, and emergency response of pipeline facilities.

Rates and Regulation

Our Utilities are subject to the jurisdiction of the public utility commissions in the states where they operate and the FERC for certain assets and transactions. These commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates, and various other matters. Rate decisions are influenced by many factors, including the cost of providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, general economic conditions, and the political environment. Certain commissions also have jurisdiction over the issuance of debt or securities and the creation of liens on property located in their states to secure bonds or other securities.

The regulatory provisions for recovering the costs of service vary by jurisdiction. Our Utilities have cost recovery mechanisms that allow us to pass the prudently-incurred cost of natural gas, fuel, and purchased power to customers. These mechanisms allow the utility operating in that state to collect or refund the difference between the cost of commodities and certain services embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate review. 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. These tariffs allow the utility a return on the investment.

Electric Utilities

The following table provides regulatory information for each of our Electric Utilities:

(a) 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. Authorized totals for Colorado Electric and Wyoming Electric include amounts recovered through base rates and the authorized regulatory mechanisms.

(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.

(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 following table summarizes the mechanisms we have in place for each of our Electric Utilities:

(a) 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.

(b) South Dakota Electric’s EIA and TFA tariffs were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020, South Dakota Electric received approval from the SDPUC to extend the 6-year moratorium period by an additional 3 years whereby these recovery mechanisms will not be effective prior to July 1, 2026.

(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.

Gas Utilities

The following table provides regulatory information for each of our Gas Utilities:

(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.

(b) Arkansas Gas return on rate base is adjusted to remove certain liabilities from rate review capital structure for comparison with other subsidiaries.

(c) Arkansas Gas rate base is adjusted to include certain liabilities for comparison with other subsidiaries.

(d) The Choice Gas Program mechanisms are applicable to only a portion of Nebraska Gas and Wyoming Gas customers.

(e) Excludes amounts to serve non-jurisdictional and agriculture customers.

The following table summarizes the mechanisms we have in place for each of our Gas Utilities:

(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.

(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.

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.

FERC

The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must maintain tariffs and rate schedules on file with FERC that govern the rates, and terms, and conditions for the provision of FERC-jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping, and reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and their affiliates. Our electric utility subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.

Our Electric Utilities entities are authorized by FERC to make wholesale sales of electric capacity and energy at market-based rates under tariffs on file with FERC. As a condition of their market-based rate authority, Electric Quarterly Reports are filed with FERC. Our Electric Utilities own and operate FERC-jurisdictional interstate transmission facilities and provide open access transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to their compliance with FERC’s regulations.

PUHCA 2005 provides FERC authority with respect to the books and records of a utility holding company. As a utility holding company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and also a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.

PUHCA 2005 reiterated the definition and benefits of EWG status. Under PUHCA 2005, an EWG is an entity or generator engaged, directly or indirectly through one or more affiliates, exclusively in the business of owning, operating or both owning and operating all or part of one or more eligible facilities and selling electric energy at wholesale. Though EWGs are public utilities within the definition set forth in the Federal Power Act and are subject to FERC regulation of rates and charges, they are exempt from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with two EWGs, Wygen I and Pueblo Airport Generation (facilities #4-5). Both of these EWGs have been granted market-based rate authority.

NERC

The Energy Policy Act of 2005 included provisions to create an Electric Reliability Organization, which is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007. Entities that violate standards can be subject to fines and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

Gas Pipeline and Storage Integrity and Safety

We are subject to regulation by PHMSA, which requires the following for certain gas distribution and transmission pipelines and underground storage facilities: inspection and maintenance plans; integrity management programs, including the determination of pipeline integrity risks and periodic assessments on certain pipeline segments; an operator qualification program, which includes certain trainings; a public awareness program that provides certain information; and a control room management plan. 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. 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. 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.

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. 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. 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 CO2 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. 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 CO2 control requirements vary by subcategory. 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 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.

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. 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. 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.

(a) Executive leadership positions are defined as positions with Vice President, Senior Vice President, or Chief in their title.

(b) Includes voluntary and involuntary separations but excludes internships.

Total Employees

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).

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. We have not experienced any labor stoppages in decades.

Development and Retention

Developing and retaining talent is critical to our continued success. 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. 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. 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. Meetings of three or more employees begin with a safety share, a practice which contributes to keeping safety top of mind. We focus our safety efforts on fostering a learning culture with proactive safety engagement with the goal of building capacity and reducing the potential for serious injuries and fatalities.

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The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect our business operations, financial condition, results of operations or cash flows are described below. These risk factors, along with other risk factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our Company.

STRATEGIC RISK

Our continued success is dependent on execution of our business plan and growth strategy, including our capital investment program.

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. Our current plans and strategy may be negatively impacted by disruptive forces and innovations in the marketplace, workforce capabilities, changing political, business or regulatory conditions, and technology advancements.

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. 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. Our capacity requirements and applicable reserve margins are a critical component to serving our customers. Delays in construction, increasing reserve margins, and growing demand put additional pressures on meeting resource adequacy requirements. An inability to successfully adapt to changing conditions and execute our strategic plan, including our capital investment program, could materially affect our financial operating results including earnings, cash flow, and liquidity.

REGULATORY, LEGISLATIVE, AND LEGAL RISKS

We may be subject to unfavorable or untimely federal and state regulatory outcomes.

Our regulated Utilities are subject to cost-of-service/rate-of-return regulation and earnings oversight from federal and eight state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our customer rates are regulated based on an analysis of our costs and investments, as reviewed and approved in regulatory proceedings. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our various regulatory authorities will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in full or timely recovery of our costs with a reasonable return on invested capital. 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.

Each of our Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs, including costs from certain severe weather events, or integrity capital investments) outside of a base rate review in order to stabilize customer rates and reduce regulatory lag. If regulators decide to discontinue these tariff-based recovery mechanisms, it could negatively impact earnings, cash flow and liquidity.

Municipal governments may seek to limit or deny our franchise privileges.

Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising powers of condemnation over all or part of our utility assets within municipal boundaries. We regularly engage in negotiations on renewals of franchise agreements with our municipal governments. We have from time to time faced challenges or ballot initiatives on franchise renewals. Although condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial procedure, the outcome is uncertain. 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.

Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements including those associated with climate change.

Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions (i.e., SO2, NOx, 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. 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. Failure or inability to comply with evolving environmental regulations may result in the imposition of fines, penalties, and injunctive measures affecting operating assets.

Our business segments may not be successful in recovering increased capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. 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. 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. 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. 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.

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. The FERC, NERC, PHMSA, CFTC, EPA, OSHA, SEC, TSA, and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business, which could have a material adverse effect on our financial operating results including earnings, cash flow, and liquidity.

Changes in Federal income tax policy or our inability to use or generate tax credits may adversely affect our financial condition, results of operations, and cash flows, as well as our credit ratings.

We are subject to taxation by the various taxing authorities at the federal, state and local levels where we operate. Sweeping legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes may include numerous provisions that affect businesses, including changes to corporate tax rates, business-related exclusions, transferability of tax credits, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which a change in corporate tax rate will affect our utility customers and the time period over which that change will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies, and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.

We have reduced our consolidated federal and state income tax liabilities in prior years through tax credits, net operating losses, and charitable contribution deductions. A reduction in or disallowance of these tax benefits could adversely affect our earnings and cash flows. We have not fully used these allowed tax benefits in our previous tax filings and have carried them forward to use against future taxable income. 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. These facilities produce PTCs and ITCs used to reduce our federal tax obligations. The amount of tax credits we earn depends on the date the qualifying generating facilities are placed in service and various operating and economic factors, including facility generation, transmission constraints, unfavorable trends in pricing for wind or solar energy, adverse weather conditions, the breakdown or failure of equipment, and the applicable tax credit rate. 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. 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.

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. If we are unable to successfully attract and retain an appropriately qualified workforce and maintain high levels of employee engagement, and maintain satisfactory collective bargaining agreements, safety, service reliability, customer satisfaction, and our results of operations could be adversely affected. As part of our strategic business plans, we will need to attract and retain personnel who are qualified and engaged to implement our strategy and may need to retrain or re-skill certain employees to support our long-term objectives.

Our businesses have collective bargaining agreements with labor unions and approximately 25% of our employees are represented by unions. Failure 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. 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. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, uninsured losses or losses in excess of current insurance coverage, increased costs of insurance, damage to our reputation, regulatory recovery risk, litigation risk, the potential for a credit downgrade or the inability to access capital markets on reasonable terms.

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. Our largest customers also rely on our supply chain and delays in critical materials could impact their ability to operate and grow as planned. 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.

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.

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.

To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive information including personal information about our customers and employees. Cybersecurity incidents, terrorism, or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or natural gas operations. Attacks targeting other key technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. 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. Any disruption of our electric and/or natural gas operations could result in a loss of service to customers and associated revenues, as well as significant expense to repair damages and remedy security breaches. In addition, any theft, loss, and/or fraudulent use of customer, shareowner, employee, or proprietary data could subject us to significant litigation, liability, and costs, as well as adversely impact our reputation with customers and regulators, among others. We maintain cyber risk insurance to mitigate a portion, but not all, of these risks and losses.

As discussed in Item 1C in this Annual Report on Form 10-K, we have instituted security measures and safeguards to protect our operational systems and information technology assets against cybersecurity threats, including certain safeguards required by NERC. Despite our implementation of security measures and safeguards, all of our technology systems may still be vulnerable to disability, failures, or unauthorized access.

In recent years, the TSA issued security directives that included several new cybersecurity requirements for critical pipeline owners and operators. Such directives or other requirements may require expenditure of significant additional resources to respond to cybersecurity incidents, to continue to modify or enhance protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. Increased costs and the operational impacts of compliance and changes in cybersecurity requirements, including any failure to comply with government regulations or any failure in our cybersecurity protective measures may result in enforcement actions, all of which may have a material adverse effect on our business and our financial operating results including earnings, cash flow, and liquidity. 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. Operating hazards such as leaks, mechanical problems and accidents, including fires or explosions, could impact employee and public safety, reliability, and customer confidence.
• Inherent dangers. Electricity and natural gas can be dangerous to employees and the general public. Failures of or contact with power lines, natural gas pipelines, or service facilities and equipment may result in fires (discussed above), explosions, property damage, and personal injuries, including death. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully covered by our insurance.
• Weather, natural conditions, and disasters including impacts from climate change (discussed below).
• Acts of sabotage, terrorism, or other malicious physical attacks. Damage to our facilities due to deliberate acts could lead to outages or other adverse effects.
• Equipment and processes. Breakdown or failure of equipment or processes, unavailability, or increased cost of equipment, and performance below expected levels of output or efficiency.
• Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and natural gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically or with cyber means, our ability to sell or deliver utility services and satisfy our contractual obligations may be hindered.
• Natural gas supply for generation and distribution. Our regulated Utilities and non-regulated entities purchase natural gas from a number of suppliers for our generating facilities and for distribution to our customers. 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. We may incur increased cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities.
• Governmental permits. The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate.
• Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and contractual agreements, including those that restrict the timing of generation plant scheduled outages.
• Increased costs. 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.

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. While we maintain insurance, obtain warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased expenses, liability, or liquidated damage payments.

The nature of our business subjects us to climate-related risk, stemming from both physical risk and transition risk of climate change, over varying time horizons.

Physical risks of climate change refer to risks to our facilities or operations that may result from changes in the physical climate, such as changes to temperature and weather patterns. Our utility businesses are seasonal businesses and weather conditions and patterns can have a material impact on our operating results. To the extent weather conditions are affected by climate change, fluctuations in commodity prices and customers’ energy usage could be magnified. Climate change may lead to increased intensity and frequency of storms, resulting in increased likelihood of wildfires, wind, and extreme temperature events. Severe weather events, such as snow and ice storms (e.g., Winter Storm Uri), wildfires, and strong winds could impact our operations, including our ability to provide energy safely, reliably, and profitably and our ability to complete construction, expansion, or refurbishment of facilities as planned. Climate change may intensify these events or increase the frequency of their occurrence. Over time, we may need to make additional investments to protect our facilities from physical risks of climate change.

Transition risks of climate change include changes to the energy systems as a result of new technologies, changing customer demand, and/or expectations and voluntary GHG reduction goals, as well as local, state, or federal regulatory requirements (discussed above). Policies such as a carbon or methane tax could increase costs associated with fossil fuel usage, resulting in higher operating costs including costs of energy generation, construction, and transportation. Risks of the transition to a low-carbon economy could result in shrinking customer demand for fossil fuel-based energy sources. This could come from increased use of behind the meter technology, such as residential solar and storage. 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.

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. 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. 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 Utilities are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our Utilities have historically generated lower revenues, income and cash flows when weather conditions are cooler than normal in the summer and warmer than normal in the winter. 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. 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. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells, and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us could decline. 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.

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.

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. 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. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes in macroeconomic conditions including recession, inflation, and interest rates, changes in our regulatory environment, industry-specific market conditions, changes in business operations, changes in competition, or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of either or both of our operating segments, which may result in an impairment charge. See additional information in “Critical Accounting Estimates” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

FINANCIAL RISKS

A sub-investment grade credit rating could impact our ability to access capital markets.

Our senior unsecured debt rating is Baa2 (Stable outlook) by Moody’s and BBB+ (Stable outlook) by S&P. Reduction of our investment grade credit ratings could impair our ability to refinance or repay our existing debt and complete new financings on reasonable terms. A credit rating downgrade, particularly to sub-investment grade, could also result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities, potentially significantly increasing our cost of capital and other associated operating costs which may not be recoverable through existing regulatory rate structures and contracts with customers.

We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures or otherwise execute our operating strategy.

Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, pay dividends and fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of debt and equity offerings, and proceeds from asset sales. 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.

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. Possible additional measures would be evaluated in the context of then-prevailing market conditions, prudent financial management, and any applicable regulatory requirements.

We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be insufficient to cover a significant loss.

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. 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. 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. Further, the proceeds of any such insurance may not be received in a timely manner.

Costs associated with our healthcare plans and other benefits could increase significantly.

The costs of providing healthcare benefits to our employees and retirees have increased significantly in recent years. We believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees, will continue to rise. Significant regulatory developments have required, and likely will continue to require, changes to our current employee benefit plans and supporting administrative processes. Our electric and natural gas utility rates are regulated on a state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a regulatory proceeding. Within our utility rates, we have generally recovered the cost of providing employee benefits. As employee benefit costs continue to rise, however, there is no assurance that the utility commissions will allow recovery of these increased costs. Rising employee benefit costs, or inadequate recovery of such costs, may adversely affect our financial operating results including earnings, cash flow, and liquidity.

We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments are dependent upon cash distributions to the holding company from the subsidiaries.

As a holding company, our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working capital, equity, or debt service funds.

There is no assurance as to the amount, if any, of future dividends to the holding company because these subsidiaries depend on future earnings, capital requirements, and financial conditions to fund such dividends. See “Liquidity and Capital Resources” within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 8 of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information regarding these restrictions and their impact on our liquidity.

Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and other retiree benefit plans.

Assumptions related to interest rates, expected return on investments, mortality, and other key actuarial assumptions have a significant impact on our funding requirements and the expense recognized related to our pension and other retiree benefit plans. An adverse change to key assumptions associated with our defined benefit retirement plans may require significant, unplanned contributions to the plans which could adversely affect our financial operating results including earnings, cash flow, and liquidity. 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.

We use various financial and physical derivatives, including futures, forwards, options, and swaps to manage commodity price and interest rate risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP may not consistently match up with the gains or losses on the commodities being hedged. For Black Hills Energy Services under the Choice Gas Program, and in certain instances within our regulated Utilities where unrealized and realized gains and losses from derivative instruments are not approved for regulatory accounting treatment, fluctuating commodity prices may cause fluctuations in reported financial results due to mark-to-market accounting treatment.

To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity prices, or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are not followed.

Additionally, our exchange-traded futures contracts are subject to futures margin posting requirements. To the extent we are unable to meet these requirements, this could have a significant impact on our business by reducing our ability to execute derivative transactions to reduce commodity price uncertainty and to protect cash flows. 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.

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. 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.

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. 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.

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. 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. 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.

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. 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. These procedures include steps to identify, classify, communicate, contain, eradicate, and recover from a cybersecurity incident. These 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.

Governance

Our Board of Directors is responsible for the oversight of risks from cybersecurity threats. 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. From time to time, our Board of Directors also engages third-party consultants to provide further education about cybersecurity 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.

Through oversight of the cybersecurity risk management program, our CSO is continually informed about the status of the program, including the effectiveness of the process and controls to monitor, prevent, detect, mitigate, and remediate cybersecurity incidents. The CSO is also made aware of the latest developments in cybersecurity, including potential threats and innovative risk management techniques. 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.

See Item 1 for a description of our principal business properties.

In addition to the properties disclosed in the Item 1, we own or lease several facilities throughout our service territories including a corporate headquarters building and various office, service center, storage, shop, and warehouse space. Substantially all of the tangible utility properties of South Dakota Electric and Wyoming Electric are subject to liens securing first mortgage bonds issued by South Dakota Electric and Wyoming Electric, respectively.

Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within Item 8, Note 3, “Commitments, Contingencies and Guarantees”, of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Executive Summary

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

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

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

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. 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. 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. 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). The new wind generation facility was placed in service in December 2023 and the solar facility was placed in service in March 2024. The renewable energy from these PPAs is used to serve our expanding partnerships with LPCS customers.
• 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. 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.

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. Our Electric Utilities own and operate 1,394 MWs of generation capacity and 9,196 miles of transmission and distribution lines and our Gas Utilities own and operate approximately 49,000 miles of natural gas transmission and distribution pipelines.

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.

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. Recent examples of our efforts within our integrity program include:

• Continued Construction on Ready Wyoming Project: In November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. Construction of the 260-mile, multi-phase transmission expansion project commenced in late 2023 and the first phase was placed in service in December 2024. 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. 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. The IRP outlines a range of options over a 20-year planning horizon to meet long-term forecasted energy needs while strengthening reliability and resiliency of the grid. The analysis focused on the least-cost resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving the Company’s generation emissions reduction goals. South Dakota Electric's resource plan in the near-term planning period through 2026 includes the conversion of Neil Simpson II to dual fuel (natural gas and coal) in 2025, and addition of 99 MWs of utility-owned, dispatchable natural gas generation by the second half of 2026. 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. Additionally, we continue to engage stakeholders including community and local agencies regulators, legislative bodies and our industry peers to define, review and advance our wildfire management and mitigation plans, including our PSPS, which we expect to formalize by mid-2025.

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

As of December 31, 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. Our actual 2024 and forecasted capital expenditures for the next five years from 2025 through 2029 are as follows:

(in millions)

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

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

Efficiently plan, construct and operate power generation facilities to serve our Electric Utilities. We best serve customers and communities when generation is vertically integrated into our Electric Utilities and we retain control of the fuel source. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to supply cost-effective electricity to our customers. These generation assets can be rate-based or non-regulated assets within our Electric Utilities segment. However, we believe that generation assets that are rate-based provide the most effective long-term benefits to customers.

Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs (operations located near energy hubs), efficiency in converting fuel into energy, and low per-unit operating and maintenance costs. In addition, we operate our plants with high levels of Availability as compared to industry benchmarks.

Rate-Based Generation: Rate-based generation assets offer several advantages for customers and shareholders, including:

• When generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run; especially when compared to power otherwise purchased from the open market through wholesale contracts or PPAs that are periodically re-priced to reflect current and varying market conditions;
• Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;
• The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of capital;
• The value of controlling load to most effectively serve our customer demand; and
• Investors are provided a long-term and stable return on their investment.

Integrated Generation: Our Electric Utilities segment also includes a power generation business that owns non-regulated generating facilities that are contracted through long-term power purchase agreements with our electric utilities. Our power generation business has an experienced staff with significant expertise in planning, building and operating power plants. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the Company’s generation assets. Our power generation business competitively bids for energy and capacity through requests for proposals by our Electric Utilities for energy resources necessary to serve customers. This business can bid competitively due to construction expertise, fuel supply advantages and by co-locating new plants at our existing Electric Utilities’ energy complexes, reducing infrastructure and operating costs. All power plants within this business are contracted to our Electric Utilities under long-term contracts, located at our utility-generating complexes and physically integrated into our Electric Utilities’ operations.

Generation Fuel Supply: Our generating facilities are strategically located close to energy hubs that help reduce fuel supply costs. Our Colorado and Wyoming gas-fired generating facilities are located close to major natural gas energy hubs that provide trading liquidity and transparent pricing. Due to their location in the resource rich areas of Colorado and Wyoming, natural gas supply to fuel our gas-fired generation can be sourced at competitive prices. Our coal-fired power plants, all located at the Gillette Energy Complex in northeastern Wyoming, are supplied by our adjacent WRDC coal mine. WRDC provides approximately 3.7 million tons of low-sulfur coal directly to these 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. Nearly all the mine’s production is sold to these on-site generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus contracts with affiliates.

Reducing our carbon footprint by proactively integrating alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. A critical component of our strategy involves sustainable operations and reducing emissions. We are committed to cleaner energy and a low carbon future, integrating the Energy Transition and more renewable energy into our overall strategy and decision making. We strongly believe that multiple energy sources, working together, will provide the solutions for a cleaner and resilient energy future.

Many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting GHG emission reduction targets. Federal legislation for renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely drive the need for significant investment in our Electric Utilities and Gas Utilities segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility, we are responsible for providing safe, reliable and cost-effective sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with standards and regulations that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.

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. 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. 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. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-party damage reduction, expanding the use of RNG and hydrogen, and utilizing carbon credit offsets.

During the second quarter of 2024, we published our 2023 Corporate Sustainability Report, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals. We reported a 27% reduction in GHG emissions from our natural gas distribution system since 2022 and are on track to achieve our goal of net zero emissions by 2035. Additionally, we have reduced our electric utility GHG emissions by nearly one-third since 2005 and are on track to achieve our goals to reduce electric emissions intensity by 40% by 2030 and 70% by 2040 compared to 2005.

Our goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This keeps our customers at the forefront of our decision-making, which is central to our values. More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. Recent efforts to support this interest include:

• Advanced Colorado Clean Energy Plan: Colorado Electric's Clean Energy Plan supports its voluntary election to reduce carbon emissions 80% from 2005 levels by 2030. On April 17, 2024, Colorado Electric filed its 120-Day report with the CPUC, recommending the addition of renewable energy resources to advance its Clean Energy Plan. In December 2024, the CPUC approved a preferred portfolio of 100 MWs of utility-owned solar generation, 50 MWs of utility-owned battery storage and a 200 MWs solar PPA. Colorado Electric plans to file a CPCN for utility-owned resources by mid-2025. New resources are expected to be placed in service in 2027-2028.
• Established Green Forward and Expanded RNG Interconnect Projects: In 2022 and 2023, we filed regulatory applications to launch Green Forward, a voluntary RNG and carbon offset program, to eligible residential and small business natural gas customers to offset up to 100% or more of the emissions from their natural gas usage. Our teams continue to evaluate attractive RNG investment opportunities across our agriculture-rich service territories and explore value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with 10 projects actively injecting RNG into our natural gas system.
• Acquired RNG Production Facility: In January 2024, Black Hills Energy Renewable Resources acquired a RNG production facility at a landfill in Dubuque, Iowa. The facility currently injects RNG into the natural gas distribution system serving Dubuque, which is owned and operated by Iowa Gas. This acquisition represents our entry into the production of RNG as a nonregulated business while leveraging our expertise in owning and operating regulated natural gas pipeline systems, including RNG interconnections. The RNG produced from the landfill facility captures methane that would otherwise vent into the atmosphere. It is delivered under long-term contracts to a third party that purchases the RNG and its related environmental attributes, in conformity with the EPA's Renewable Fuel Standard Program.

Inflation Reduction Act

The IRA, enacted in August 2022, features spending and tax incentives on clean energy provisions. Most notably, the IRA includes provisions that extend and expand the production and investment tax credits for wind and solar; includes energy storage, EVs, RNG, and carbon capture and sequestration; and contains a tax credit transferability provision that allows us to transfer (e.g. sell) PTCs produced after December 31, 2022, to third parties. In June 2024, under this transferability provision, we entered into an agreement with a third party to sell $16.9 million of our 2023 generated PTCs. In January 2025, we entered into a similar agreement with a third party to sell $17.0 million of our 2024 generated PTCs. We expect to continue to explore the ability to efficiently monetize our tax credits through third party transferability agreements. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.

Deliver a competitive total return to investors and maintain an investment grade credit rating. We are proud of our track record of annual dividend increases for shareholders. 2024 represented our 54th consecutive year of increasing dividends. In January 2025, our Board of Directors declared a quarterly dividend of $0.676 per share, equivalent to an annual dividend of $2.704 per share. 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 require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings-accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating.

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. We are currently assessing insurance recovery opportunities.
• On January 20, 2025, Wyoming Electric set a new all-time and winter peak load of 318 MWs, surpassing the previous all-time and winter peak load of 314 MWs set on January 11, 2024. Prior to 2024, the previous winter peak was 301 megawatts in December 2023 and the all-time peak was 312 megawatts in July 2023.

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.

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

Results of Operations

Our discussion and analysis for the year ended December 31, 2024, compared to 2023, is included herein. 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.

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

Consolidated Summary and Overview

(in millions, except per share amounts)

(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. These unfavorable variances were partially offset by new rates and rider recovery and retail customer growth and usage.
• Gas Utilities’ operating income increased $42.5 million primarily due to new rates and rider recovery driven by the Colorado Gas, Iowa Gas, RMNG and Wyoming Gas rate reviews, retail customer growth and usage, favorable mark-to-market on commodity contracts, and lower employee-related expenses partially offset by $15.9 million of unfavorable weather and higher depreciation driven by capital expenditures;
• Corporate and other operating loss decreased $3.7 million due to lower unallocated operating expenses;
• Net interest expense increased $13.8 million primarily due to higher interest rates partially offset by increased interest income and increased AFUDC debt driven by higher construction work-in-progress balances;
• Other (expense), net decreased $1.8 million primarily due to higher AFUDC equity driven by higher construction work-in-progress balances;
• Income tax (expense) increased $10.7 million driven by higher pre-tax income and a higher effective tax rate primarily due to an $8.2 million tax benefit in 2023 from a Nebraska income tax rate decrease; and
• Net income attributable to non-controlling interest decreased $3.2 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages.

Segment Operating Results

Non-GAAP Financial Measure

The following discussion includes financial information prepared in accordance with GAAP and a “non-GAAP financial measure", Electric and Gas Utility margin. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. 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. 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. 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. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.

Electric Utilities

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

(in millions)

2024 Compared to 2023

Electric Utility margin increased as a result of:

(in millions)

(a) In 2021, Wygen I experienced an unplanned outage which resulted in lost revenue. A claim for these losses was submitted under our business interruption insurance policy. In 2023, we recovered $5.0 million from our business interruption insurance which was recognized as Revenue.

Operations and maintenance expense increased primarily due to $5.1 million of costs related to unplanned generation outages and $4.6 million of higher insurance expense partially offset by $3.5 million of lower employee-related expenses driven by lower headcount. In 2023, Electric Utilities benefited from one-time gains of $7.7 million on the sale of Northern Iowa Windpower assets and $3.9 million on sale of land.

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

Taxes other than income taxes were comparable.

Operating Statistics

(in millions)

(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.

(b) Includes company uses and line losses.

(in millions)

(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. See Key Elements of our Business Strategy section above for additional information.

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

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

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

Gas Utilities

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

(in millions)

2024 Compared to 2023

Gas Utility margin increased as a result of:

(in millions)

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.

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

Taxes other than income taxes were comparable.

Operating Statistics

(in millions

(Dth in millions)

(a) Includes Black Hills Energy Services revenue under the Choice Gas Program.

(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.

(c) Includes inter-segment rent and non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe.

(in millions)

(Dth in millions)

(a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins.

(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.

Corporate and Other

Corporate and Other operating results, including inter-segment eliminations, for the years ended December 31 were as follows:

(in millions)

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.

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

(in millions)

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.

Other (expense), net decreased primarily due to higher AFUDC equity driven by higher construction work-in-progress balances.

Income tax (expense) increased due to higher pre-tax income and a higher effective tax rate. The effective tax rate was 11.3% for 2024 and 8.5% for 2023. 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. Our primary sources of cash are generated from our operating activities, Revolving Credit Facility, CP Program, ATM, and ability to access the public and private capital markets through debt and equity securities offerings when necessary. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate.

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

We believe that our cash on hand, operating cash flows, existing borrowing capacity, and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.

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

(dollars in millions)

(a) Available capacity under Revolving Credit Facility and CP Program represents $750 million of total borrowing capacity less outstanding borrowings and letters of credit. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information.

Future Financing Plans

We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, and the issuance of common stock under our ATM program or in an opportunistic block trade. In 2025, we plan to renew our Equity Distribution Sales Agreement and assess the renewal of our shelf registration statement. Our Equity Distribution Sales Agreement allows us to sell shares of common stock, from time to time, through our ATM program utilizing our shelf registration statement. We also plan to re-finance our $300 million, 3.95%, senior unsecured notes due January 2026, at or before maturity date.

CASH FLOW ACTIVITIES

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

Operating Activities:

(in millions)

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:
• 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;
• 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
• 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.

Investing Activities:

(in millions)

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.
• 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.

Financing Activities:

(in millions)

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:
• Net cash inflows increased $669.4 million as a result of net borrowing activity under our Revolving Credit Facility and CP Program; and
• 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
• 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.

CAPITAL RESOURCES

Shelf Registration Statement

We maintain an effective shelf registration statement with the SEC under which we may issue, from time to time, an unspecified amount of senior debt securities, subordinate debt securities, common stock, preferred stock, warrants, and other securities.

Short-term Debt

We have a $750 million Revolving Credit Facility that matures on May 31, 2029, with two one-year extension options (subject to consent from lenders). This facility is similar to the former revolving credit facility, which includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents, and each bank increasing or providing a new commitment. We also have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million.

The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures or restrictions.

The Revolving Credit Facility contains cross-default provisions that could result in a default under such agreements if BHC or its material subsidiaries failed to 1) make timely payments of debt obligations; or 2) triggered other default provisions under any debt agreement totaling, in the aggregate principal amount of $50 million or more that permit the acceleration of debt maturities or mandatory debt prepayment.

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

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. 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.

CREDIT RATINGS

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

The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2024:

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

(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. Following the affirmation, the parties jointly withdrew the rating.

The following table represents the credit ratings of South Dakota Electric at December 31, 2024:

(a) On May 9, 2024, S&P reported A rating.

(b) On January 17, 2025, Fitch affirmed its A rating for South Dakota Electric. Following the affirmation, the parties jointly withdrew the rating.

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

CAPITAL REQUIREMENTS

Capital Expenditures

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. 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.

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

Repayments of Indebtedness

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

Unconditional Purchase Obligations

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

Defined Benefit Pension Plan

We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The unfunded status of the Pension Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the Pension Plan is $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.

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

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

(Dividends Paid in millions)

Our three-year compound annualized dividend growth rate was 4.3%.

Collateral Requirements

Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions, and the amounts owed by or to the counterparty. At December 31, 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.

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

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

Regulation

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

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

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

As of December 31, 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. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

Goodwill

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

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

Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our operating segments, or components of an operating segment, that constitute a business for which discrete financial information is available. We estimate the fair value of our reporting units using a combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach, which estimates fair value based on market comparables within the utility and energy industry. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions for comparable assets within the utility and energy industry. Varying by reporting unit, weighted average cost of capital in the range of 6.3% 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. 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. These multiples are applied to operating data for each reporting unit to arrive at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market participants.

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

For the years ended December 31, 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.

Income Taxes

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

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

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

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

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

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

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

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

To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. The Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments, prohibited activities, and employee conduct. We report significant issues or concerns pertaining to the Risk Policies and Procedures to the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at least quarterly and as necessary, to review our business and credit activities and to ensure that these activities are conducted within the authorized policies.

Commodity Price Risk

Electric and Gas Utilities

Our Utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis to reflect billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota, and Wyoming, we have ECA or PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming, we have GCA provisions that adjust natural gas rates when our natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic prudence reviews by the state regulatory commissions. If state regulatory commissions decide to discontinue these tariff-based adjustment mechanisms, or there are delays in the timing of recovery under these mechanisms, we may be more exposed to commodity price risk.

The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state regulatory commissions, we have entered into commission-approved hedging programs utilizing natural gas futures, options, over-the-counter swaps, and basis swaps to reduce our customers’ underlying exposure to these fluctuations.

For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state utility commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income. See additional information in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Wholesale Power

There is a potential risk that our wholesale power sales could exceed our current generating capacity, which may arise from unplanned plant outages or from unanticipated load demands. 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.

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. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with fixed price forward contracts to supply gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings.

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.

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. 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. A 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.

We are subject to interest rate risk associated with our pension and post-retirement benefit obligations. Changes in interest rates impact the liabilities associated with these benefit plans as well as the amount of income or expense recognized for these plans. Declines in the value of the plan assets could diminish the funded status of the pension plans and potentially increase the requirements to make cash contributions to these plans. See additional information in Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Credit Risk

We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls and limits to manage and mitigate credit risk within risk tolerances established by the Board of Directors. We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements.

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

See more information in Notes 1 and 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act)) as of December 31, 2024. Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.

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

Changes in Internal Control over Financial Reporting

During the quarter ended December 31, 2024, there were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control over Financial Reporting is presented on Page 54 of this Annual Report on Form 10-K.