# BLACK HILLS CORP /SD/ (BKH) FY 2024 MD&A Verbatim Item 7 Management's Discussion and Analysis from BLACK HILLS CORP /SD/'s 10-K for fiscal year 2024. SEC filing source: https://www.sec.gov/Archives/edgar/data/1130464/000095017025018647/bkh-20241231.htm Accession: 0000950170-25-018647 Filing date: 2025-02-12 Report date: 2024-12-31 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Published MD&A gate trimmed front/tail over-capture. Confidence: high Company profile: /company/BKH/ All MD&A years: /company/BKH/mda/ Previous year: /company/BKH/mda/fy2023/ (FY 2023) Next year: /company/BKH/mda/fy2025/ (FY 2025) ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Executive Summary We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for 1.35 million customers and 800+ communities we serve. 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. 34 Table of Contents • Expanded BCIS Load: We have supported enabling legislation in Wyoming for the growing blockchain businesses while implementing our own BCIS Tariff to serve these customers. 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 $4.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure, supporting customer and community growth needs, and complying with safety requirements. Our actual 2024 and forecasted capital expenditures for the next five years from 2025 through 2029 are as follows: 35 Table of Contents [[GREPCENT_TABLE]] [["","Actual (a)","","Forecasted (b)"],["Capital Expenditures by Segment (minor differences may result due to rounding)","2024","","2025","","2026","","2027","","2028","","2029"],["","(in millions)"],["Electric Utilities","$","382","","$","550","","$","432","","$","383","","$","615","","$","435"],["Gas Utilities","","403","","","431","","","386","","","412","","","447","","","447"],["Corporate and Other","","13","","","21","","","41","","","27","","","27","","","27"],["Total","$","798","","$","1,002","","$","859","","$","822","","$","1,089","","$","909"]] [[/GREPCENT_TABLE]] (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. 36 Table of Contents 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. 37 Table of Contents 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. 38 Table of Contents 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 [[GREPCENT_TABLE]] [["","For the Years Ended December 31,"],["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions, except per share amounts)"],["Operating income (loss):"],["Electric Utilities","$","233.0","","$","248.8","","$","(15.8",")","$","214.3","","$","34.5"],["Gas Utilities","","271.3","","","228.8","","","42.5","","","244.2","","","(15.4",")"],["Corporate and Other (a)","","(1.2",")","","(4.9",")","","3.7","","","(3.3",")","","(1.6",")"],["Operating Income","","503.1","","","472.7","","","30.4","","","455.2","","","17.5"],["Interest expense, net","","(181.7",")","","(167.9",")","","(13.8",")","","(161.0",")","","(6.9",")"],["Other income (expense), net","","(1.4",")","","(3.2",")","","1.8","","","1.8","","","(5.0",")"],["Income tax (expense)","","(36.3",")","","(25.6",")","","(10.7",")","","(25.2",")","","(0.4",")"],["Net income","","283.7","","","276.0","","","7.7","","","270.8","","","5.2"],["Net income attributable to non-controlling interest","","(10.6",")","","(13.8",")","","3.2","","","(12.4",")","","(1.4",")"],["Net income available for common stock","$","273.1","","$","262.2","","$","10.9","","$","258.4","","$","3.8"],["Weighted average common shares outstanding, Diluted","","69.9","","","67.1","","","2.8","","","65.0","","","2.1"],["Total earnings per share of common stock, Diluted","$","3.91","","$","3.91","","$","\u2014","","$","3.97","","$","(0.06",")"]] [[/GREPCENT_TABLE]] (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 $3.2 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages. 39 Table of Contents Segment Operating Results Non-GAAP Financial Measure The following discussion includes financial information prepared in accordance with GAAP and a “non-GAAP financial measure", Electric and Gas Utility margin. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Electric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses, depreciation and amortization expenses, and taxes other than income taxes from the measure. Electric Utility margin is calculated as operating revenue less cost of fuel and purchased power. Gas Utility margin is calculated as operating revenue less cost of natural gas sold. Our Electric and Gas Utility margin is impacted by the fluctuations in power and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact Electric and Gas Utility margin as a percentage of revenue, they only impact total Electric and Gas Utility margin if the costs cannot be passed through to our customers. Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance. Electric Utilities Operating results for the years ended December 31 for the Electric Utilities were as follows: [[GREPCENT_TABLE]] [["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions)"],["Total revenue","$","876.1","","$","865.0","","$","11.1","","$","900.2","","$","(35.2",")"],["Fuel and purchased power:","","206.4","","","200.1","","","6.3","","","266.3","","","(66.2",")"],["Electric Utility margin (non-GAAP)","","669.7","","","664.9","","","4.8","","","633.9","","","31.0"],["Operations and maintenance","","252.6","","","236.2","","","16.4","","","244.8","","","(8.6",")"],["Depreciation and amortization","","145.3","","","142.6","","","2.7","","","135.9","","","6.7"],["Taxes other than income taxes","","38.8","","","37.3","","","1.5","","","38.9","","","(1.6",")"],["","","436.7","","","416.1","","","20.6","","","419.6","","","(3.5",")"],["Operating income","$","233.0","","$","248.8","","$","(15.8",")","$","214.3","","$","34.5"]] [[/GREPCENT_TABLE]] 2024 Compared to 2023 Electric Utility margin increased as a result of: [[GREPCENT_TABLE]] [["","(in millions)"],["New rates and rider recovery","$","15.8"],["Retail customer growth and usage","","3.8"],["Weather","","2.7"],["Off-system excess energy sales","","(7.8",")"],["2023 Wygen I revenue recovery under business interruption insurance (a)","","(5.0",")"],["Unplanned generation outages","","(4.0",")"],["Other","","(0.7",")"],["","$","4.8"]] [[/GREPCENT_TABLE]] (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 $3.9 million on sale of land. Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures. Taxes other than income taxes were comparable. 40 Table of Contents Operating Statistics [[GREPCENT_TABLE]] [["","Revenue","","Quantities Sold"],["","For the year ended December 31,","","For the year ended December 31,"],["By Customer Class","2024","","2023","","2022","","2024","","2023","","2022"],["","(in millions)","","(in GWh)"],["Retail Revenue -"],["Residential","$","234.8","","$","224.5","","$","246.2","","","1,471.9","","","1,438.5","","","1,513.1"],["Commercial","","263.6","","","254.5","","","272.4","","","2,091.4","","","2,074.4","","","2,087.8"],["Industrial","","168.9","","","157.3","","","163.9","","","2,169.8","","","2,094.8","","","1,912.5"],["Municipal","","17.0","","","17.5","","","20.5","","","147.1","","","150.9","","","159.3"],["Other Retail","","14.3","","","12.3","","","6.2","","","\u2014","","","\u2014","","","\u2014"],["Subtotal Retail Revenue - Electric","","698.6","","","666.1","","","709.2","","","5,880.2","","","5,758.6","","","5,672.7"],["Wholesale","","26.8","","","34.2","","","44.8","","","589.4","","","699.7","","","947.0"],["Market - off-system sales","","34.8","","","50.9","","","48.6","","","765.6","","","737.9","","","643.2"],["Transmission","","52.2","","","47.1","","","40.5","","","\u2014","","","\u2014","","","\u2014"],["Other (a)","","63.7","","","66.7","","","57.1","","","\u2014","","","\u2014","","","\u2014"],["Total Revenue and Quantities Sold","$","876.1","","$","865.0","","$","900.2","","","7,235.2","","","7,196.2","","","7,262.9"],["Other Uses, Losses or Generation, net (b)","","","","","","","","390.3","","","463.5","","","450.0"],["Total Energy","","","","","","","","7,625.5","","","7,659.7","","","7,712.9"]] [[/GREPCENT_TABLE]] (a) Primarily related to Integrated Generation, inter-segment rent, and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services. (b) Includes company uses and line losses. [[GREPCENT_TABLE]] [["","Revenue","","Quantities Sold"],["","For the year ended December 31,","","For the year ended December 31,"],["By Business Unit","2024","","2023","","2022","","2024","","2023","","2022"],["","(in millions)","","(in GWh)"],["Colorado Electric","$","276.9","","$","285.7","","$","321.1","","","2,392.7","","","2,397.2","","","2,440.0"],["South Dakota Electric","","322.0","","","321.1","","","335.2","","","2,556.5","","","2,554.3","","","2,626.2"],["Wyoming Electric","","234.3","","","212.2","","","197.7","","","2,190.1","","","2,124.1","","","1,903.7"],["Integrated Generation","","42.9","","","46.0","","","46.2","","","95.9","","","120.6","","","293.0"],["Total Revenue and Quantities Sold","$","876.1","","$","865.0","","$","900.2","","","7,235.2","","","7,196.2","","","7,262.9"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","For the year ended December 31,"],["Quantities Generated and Purchased by Fuel Type","2024","","2023","","2022"],["","(in GWh)"],["Generated:"],["Coal","","2,478.3","","","2,683.4","","","2,708.8"],["Natural Gas","","2,239.1","","","2,021.4","","","1,454.2"],["Wind","","660.2","","","678.5","","","875.8"],["Total Generated","","5,377.6","","","5,383.3","","","5,038.8"],["Purchased:"],["Coal, Natural Gas, Diesel Oil and Other Market Purchases (a)","","1,117.8","","","1,842.9","","","2,280.8"],["Wind and Solar (a)","","1,130.1","","","433.5","","","393.3"],["Total Purchased","","2,247.9","","","2,276.4","","","2,674.1"],["Total Generated and Purchased","","7,625.5","","","7,659.7","","","7,712.9"]] [[/GREPCENT_TABLE]] (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. 41 Table of Contents [[GREPCENT_TABLE]] [["","For the year ended December 31,"],["Quantities Generated and Purchased by Business Unit","2024","","2023","","2022"],["","(in GWh)"],["Generated:"],["Colorado Electric","","865.0","","","653.9","","","474.4"],["South Dakota Electric","","2,045.4","","","2,018.5","","","1,890.0"],["Wyoming Electric","","866.5","","","908.3","","","905.8"],["Integrated Generation","","1,600.7","","","1,802.5","","","1,768.6"],["Total Generated","","5,377.6","","","5,383.2","","","5,038.8"],["Purchased:"],["Colorado Electric","","447.4","","","588.2","","","1,005.4"],["South Dakota Electric","","590.7","","","604.6","","","826.4"],["Wyoming Electric","","1,147.7","","","1,028.5","","","757.2"],["Integrated Generation","","62.1","","","55.2","","","85.1"],["Total Purchased","","2,247.9","","","2,276.5","","","2,674.1"],["Total Generated and Purchased","","7,625.5","","","7,659.7","","","7,712.9"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","For the year ended December 31,"],["","2024","2023","2022"],["Degree Days","Actual","Variance from Normal","Actual","Variance from Normal","Actual","Variance from Normal"],["Heating Degree Days:"],["Colorado Electric","4,926","(8)%","5,330","1%","5,551","9%"],["South Dakota Electric","6,311","(13)%","6,969","(4)%","7,495","6%"],["Wyoming Electric","6,272","(10)%","6,783","(1)%","7,051","3%"],["Combined (a)","5,676","(10)%","6,185","(1)%","6,518","6%"],["Cooling Degree Days:"],["Colorado Electric","1,269","11%","1,046","(10)%","1,362","9%"],["South Dakota Electric","913","49%","497","(21)%","814","27%"],["Wyoming Electric","491","7%","329","(30)%","701","47%"],["Combined (a)","989","20%","713","(15)%","1,040","18%"]] [[/GREPCENT_TABLE]] (a) Degree days are calculated based on a weighted average of total customers by state. [[GREPCENT_TABLE]] [["","For the year ended December 31,"],["Contracted generating facilities Availability (a) by fuel type","2024","2023","2022"],["Coal (b)","89.8%","93.7%","91.5%"],["Natural gas and diesel oil (b)","92.9%","92.1%","96.1%"],["Wind","90.6%","92.5%","93.7%"],["Total availability","91.7%","92.6%","94.4%"],["Wind Capacity Factor (a)","36.7%","37.4%","34.7%"]] [[/GREPCENT_TABLE]] (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. 42 Table of Contents Gas Utilities Operating results for the years ended December 31 for the Gas Utilities were as follows: [[GREPCENT_TABLE]] [["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions)"],["Total revenue","$","1,269.4","","$","1,484.2","","$","(214.8",")","$","1,669.1","","$","(184.9",")"],["Cost of natural gas sold","","524.3","","","783.2","","","(258.9",")","","965.1","","","(181.9",")"],["Gas Utility margin (non-GAAP)","","745.1","","","701.0","","","44.1","","","704.0","","","(3.0",")"],["Operations and maintenance","","320.7","","","328.7","","","(8.0",")","","317.3","","","11.4"],["Depreciation and amortization","","124.7","","","113.9","","","10.8","","","114.7","","","(0.8",")"],["Taxes other than income taxes","","28.4","","","29.6","","","(1.2",")","","27.8","","","1.8"],["","","473.8","","","472.2","","","1.6","","","459.8","","","12.4"],["Operating income","$","271.3","","$","228.8","","$","42.5","","$","244.2","","$","(15.4",")"]] [[/GREPCENT_TABLE]] 2024 Compared to 2023 Gas Utility margin increased as a result of: [[GREPCENT_TABLE]] [["","(in millions)"],["New rates and rider recovery","$","48.7"],["Mark-to-market on non-utility natural gas commodity contracts","","4.9"],["Retail customer growth and usage","","3.6"],["Weather","","(15.9",")"],["Other","","2.8"],["","$","44.1"]] [[/GREPCENT_TABLE]] 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 $2.8 million of higher IT-related expenses. Depreciation and amortization increased primarily due to a higher asset base driven by capital expenditures. Taxes other than income taxes were comparable. Operating Statistics [[GREPCENT_TABLE]] [["","Revenue","","Quantities Sold and Transported"],["","For the year ended December 31,","","For the year ended December 31,"],["By Customer Class","2024","","2023","","2022","","2024","","2023","","2022"],["","(in millions","","(Dth in millions)"],["Retail Revenue -"],["Residential","$","691.9","","$","830.3","","$","942.3","","","56.7","","","60.1","","","66.9"],["Commercial","","266.3","","","337.3","","","399.2","","","28.4","","","29.4","","","32.4"],["Industrial","","23.7","","","33.1","","","63.0","","","6.0","","","5.7","","","7.7"],["Other Retail (a)","","40.7","","","48.1","","","48.8","","","\u2014","","","\u2014","","","\u2014"],["Subtotal Retail Revenue - Gas (b)","","1,022.6","","","1,248.8","","","1,453.3","","","91.1","","","95.2","","","107.0"],["Transportation","","178.2","","","176.8","","","173.3","","","159.2","","","159.8","","","160.9"],["Other (c)","","68.6","","","58.6","","","42.5","","","\u2014","","","\u2014","","","\u2014"],["Total Revenue and Quantities Sold","$","1,269.4","","$","1,484.2","","$","1,669.1","","","250.3","","","255.0","","","267.9"]] [[/GREPCENT_TABLE]] (a) Includes Black Hills Energy Services revenue under the Choice Gas Program. (b) Retail gas revenues decreased in 2024 compared to 2023 primarily due to lower commodity prices. Our Utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer. Customer billing rates are adjusted periodically to reflect changes in our cost of energy. (c) Includes inter-segment rent and non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe. 43 Table of Contents [[GREPCENT_TABLE]] [["","Revenue","","Quantities Sold and Transported"],["","For the year ended December 31,","","For the year ended December 31,"],["By Business Unit","2024","","2023","","2022","","2024","","2023","","2022"],["","(in millions)","","(Dth in millions)"],["Arkansas Gas","$","248.8","","$","268.9","","$","311.3","","","29.9","","","30.2","","","32.3"],["Colorado Gas","","278.8","","","313.6","","","320.9","","","31.0","","","32.8","","","34.3"],["Iowa Gas","","162.3","","","213.6","","","283.9","","","37.3","","","37.9","","","40.9"],["Kansas Gas","","130.4","","","155.6","","","191.4","","","34.8","","","35.5","","","38.6"],["Nebraska Gas","","304.5","","","366.1","","","384.8","","","80.3","","","82.2","","","85.1"],["Wyoming Gas","","144.6","","","166.4","","","176.8","","","37.0","","","36.4","","","36.7"],["Total Revenue and Quantities Sold","$","1,269.4","","$","1,484.2","","$","1,669.1","","","250.3","","","255.0","","","267.9"]] [[/GREPCENT_TABLE]] [[GREPCENT_TABLE]] [["","For the year ended December 31,"],["","2024","2023","2022"],["Heating Degree Days","Actual","","Variance From Normal","Actual","Variance From Normal","Actual","Variance From Normal"],["Arkansas Gas (a)","","2,998","","(20)%","3,197","(17)%","3,844","2%"],["Colorado Gas","","5,662","","(7)%","5,916","(4)%","6,325","4%"],["Iowa Gas","","5,543","","(16)%","5,921","(12)%","7,037","7%"],["Kansas Gas (a)","","4,092","","(12)%","4,387","(8)%","4,968","7%"],["Nebraska Gas","","5,172","","(13)%","5,579","(8)%","6,220","4%"],["Wyoming Gas","","6,641","","(10)%","7,385","8%","7,644","12%"],["Combined (b)","","5,517","","(11)%","6,006","(4)%","6,536","5%"]] [[/GREPCENT_TABLE]] (a) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins. (b) Heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April. Corporate and Other Corporate and Other operating results, including inter-segment eliminations, for the years ended December 31 were as follows: [[GREPCENT_TABLE]] [["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions)"],["Operating (loss)","$","(1.2",")","$","(4.9",")","$","3.7","","$","(3.3",")","$","(1.6",")"]] [[/GREPCENT_TABLE]] 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) [[GREPCENT_TABLE]] [["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions)"],["Interest expense, net","$","(181.7",")","$","(167.9",")","$","(13.8",")","$","(161.0",")","$","(6.9",")"],["Other income (expense), net","","(1.4",")","","(3.2",")","","1.8","","","1.8","","","(5.0",")"],["Income tax (expense)","","(36.3",")","","(25.6",")","","(10.7",")","","(25.2",")","","(0.4",")"]] [[/GREPCENT_TABLE]] 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. 44 Table of Contents 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 $8.2 million tax benefit in 2023 from a Nebraska income tax rate decrease. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details. Liquidity and Capital Resources OVERVIEW Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our operating activities, Revolving Credit Facility, CP Program, ATM, and ability to access the public and private capital markets through debt and equity securities offerings when necessary. This cash is used for, among other things, working capital, capital expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations, and redemption of outstanding debt and equity securities when required or financially appropriate. We experience significant cash requirements during peak months of the winter heating season due to higher natural gas consumption, during periods of high natural gas prices, and during the construction season, which typically peaks in spring and summer. We believe that our cash on hand, operating cash flows, existing borrowing capacity, and ability to complete new debt and equity financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section. The following table provides an informational summary of our liquidity and capital structure as of December 31: [[GREPCENT_TABLE]] [["","2024","","2023"],["","(dollars in millions)"],["Cash and cash equivalents","$","16.1","","$","86.6"],["Available capacity under Revolving Credit Facility and CP Program (a)","","612.7","","","746.3"],["Available liquidity","$","628.8","","$","832.9"],["Capital structure"],["Short-term debt","$","133.8","","$","600.0"],["Long-term debt","","4,250.2","","","3,801.2"],["Total debt","","4,384.0","","","4,401.2"],["Total stockholders' equity (excludes non-controlling interest)","","3,501.5","","","3,215.3"],["Total capitalization","$","7,885.5","","$","7,616.5"],["Debt to capitalization","","55.6","%","","57.8","%"],["Long-term debt to total debt","","96.9","%","","86.4","%"]] [[/GREPCENT_TABLE]] (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 $300 million, 3.95%, senior unsecured notes due January 2026, at or before maturity date. 45 Table of Contents CASH FLOW ACTIVITIES The following tables summarize our cash flows for the years ended December 31: Operating Activities: [[GREPCENT_TABLE]] [["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions)"],["Net income","$","283.7","","$","276.0","","$","7.7","","$","270.8","","$","5.2"],["Non-cash adjustments to Net income","","350.5","","","313.5","","","37.0","","","295.7","","","17.8"],["Total earnings","","634.2","","","589.5","","","44.7","","","566.5","","","23.0"],["Changes in certain operating assets and liabilities:"],["Materials, supplies and fuel, Accounts receivable and other current assets","","(12.5",")","","255.9","","","(268.4",")","","(259.9",")","","515.8"],["Accounts payable and accrued liabilities","","28.8","","","(109.9",")","","138.7","","","89.4","","","(199.3",")"],["Regulatory assets","","90.0","","","236.8","","","(146.8",")","","203.9","","","32.9"],["Net inflow from changes in certain operating assets and liabilities","","106.3","","","382.8","","","(276.5",")","","33.4","","","349.4"],["Other operating activities","","(21.2",")","","(27.9",")","","6.7","","","(15.1",")","","(12.8",")"],["Net cash provided by operating activities","$","719.3","","$","944.4","","$","(225.1",")","$","584.8","","$","359.6"]] [[/GREPCENT_TABLE]] 2024 Compared to 2023 Net cash provided by operating activities was $225.1 million lower which was attributable to: • Total earnings (net income plus non-cash adjustments) were $44.7 million higher primarily as a result of increased Electric and Gas Utility margins due to new rates, rider recovery and customer growth, partially offset by unfavorable weather, higher operating expenses and higher financing costs. • Net inflows from changes in certain operating assets and liabilities were $276.5 million lower, primarily attributable to: o Cash inflows decreased by approximately $268.4 million as a result of changes in accounts receivable and other current assets primarily due to lower collections on pass-through revenues and lower natural gas in storage inventories driven by fluctuations in commodity prices and timing of injections and withdrawals; o Cash outflows decreased by approximately $138.7 million as a result of increases in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, payment timing of natural gas and power purchases, and changes in other working capital requirements; and o Cash inflows decreased by approximately $146.8 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of deferred gas and fuel cost adjustments driven by fluctuations in commodity prices. • Cash outflows decreased $6.7 million from other operating activities primarily due to lower costs from cloud computing arrangements. Investing Activities: [[GREPCENT_TABLE]] [["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions)"],["Capital expenditures","$","(744.2",")","$","(555.6",")","$","(188.6",")","$","(604.4",")","$","48.8"],["Other investing activities","","(1.8",")","","18.9","","","(20.7",")","","0.5","","","18.4"],["Net cash (used in) investing activities","$","(746.0",")","$","(536.7",")","$","(209.3",")","$","(603.9",")","$","67.2"]] [[/GREPCENT_TABLE]] 2024 Compared to 2023 Net cash used in investing activities was $209.3 million higher which was attributable to: • Cash outflows from capital expenditures (which are net of contributions in aid of construction) increased $188.6 million primarily as a result of Wyoming Electric's Ready Wyoming electric transmission expansion project and Black Hills Energy Renewable Resources' acquisition of a RNG production facility at a landfill in Dubuque, Iowa. 46 Table of Contents • Cash outflows increased $20.7 million for other investing activities primarily due to 2023 proceeds from the sale of Northern Iowa Windpower assets and a sale of land to support data center growth. Financing Activities: [[GREPCENT_TABLE]] [["","2024","","2023","","2024 vs 2023 Variance","","2022","","2023 vs 2022 Variance"],["","(in millions)"],["Dividends paid on common stock","$","(182.3",")","$","(168.1",")","$","(14.2",")","$","(156.7",")","$","(11.4",")"],["Common stock issued","","181.4","","","118.3","","","63.1","","","90.1","","","28.2"],["Short-term and long-term debt borrowings (repayments), net","","(16.2",")","","(260.6",")","","244.4","","","115.4","","","(376.0",")"],["Distributions to non-controlling interests","","(17.4",")","","(18.3",")","","0.9","","","(17.4",")","","(0.9",")"],["Other financing activities","","(8.4",")","","(13.0",")","","4.6","","","0.9","","","(13.9",")"],["Net cash provided by (used in) financing activities","$","(42.9",")","$","(341.7",")","$","298.8","","$","32.3","","$","(374.0",")"]] [[/GREPCENT_TABLE]] 2024 Compared to 2023 Net cash used in financing activities was $298.8 million lower which was primarily attributable to: • Cash outflows increased $14.2 million due to increased dividends paid on increased shares of common stock outstanding; • Cash inflows increased $63.1 million due to higher issuances of common stock; • Net outflows from changes in short-term and long-term debt (repayments) borrowings decreased $244.4 million due to: o Net cash inflows increased $669.4 million as a result of net borrowing activity under our Revolving Credit Facility and CP Program; and o Cash inflows decreased $350 million due to issuances of $450 million of senior unsecured notes in May 2024 compared to issuances of $350 million of senior unsecured notes in March 2023 and $450 million of senior unsecured notes in September 2023; and o Cash outflows increased $75 million due to repayment of our $600 million senior unsecured notes in August 2024 compared to repayment of our $525 million senior unsecured notes in November 2023. • Cash outflows decreased by $4.6 million for other financing activities primarily due to lower financing costs from the May 2024 debt offering compared to the March 2023 and September 2023 debt offerings. 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. 47 Table of Contents 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: [[GREPCENT_TABLE]] [["Rating Agency","Senior Unsecured Rating","Outlook"],["S&P (a)","BBB+","Stable"],["Moody\u2019s (b)","Baa2","Stable"],["Fitch (c)","BBB+","Negative"]] [[/GREPCENT_TABLE]] (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. 48 Table of Contents The following table represents the credit ratings of South Dakota Electric at December 31, 2024: [[GREPCENT_TABLE]] [["Rating Agency","Senior Secured Rating"],["S&P (a)","A"],["Fitch (b)","A"]] [[/GREPCENT_TABLE]] (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. 49 Table of Contents On January 24, 2025, our Board of Directors declared a quarterly dividend of $0.676 per share, equivalent to an annual dividend rate of $2.704 per share. The table below provides our dividends paid, dividend payout ratio, and dividends paid per share for the three years ended December 31: [[GREPCENT_TABLE]] [["","2024","","2023","","2022"],["","(Dividends Paid in millions)"],["Common Stock Dividends Paid","$","182.3","","$","168.1","","$","156.7"],["Dividend Payout Ratio","","66","%","","64","%","","61","%"],["Dividends Per Share","$","2.60","","$","2.50","","$","2.41"]] [[/GREPCENT_TABLE]] 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. 50 Table of Contents As of December 31, 2024, and 2023, we had total regulatory assets of $427.7 million and $480.1 million, respectively, and total regulatory liabilities of $568.7 million and $566.6 million, respectively. 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. 51 Table of Contents See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.