Black Hills Annual Report 2022

Plain-text annual report

2022 BLACK HILLS CORPORATION 2022 Annual Report | Proxy Statement | Form 10-K B K H BLACK HILLS CORPORATION We are a customer focused, growth- oriented utility company with a tradition of exemplary service and a vision to be the energy partner of choice. Based in Rapid City, South Dakota, the company serves over 1.3 million electric and natural gas utility customers in 824 communities in Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. Employees partner to produce results that Improve Life with Energy. Arkansas 183,300 utility customers Kansas 118,600 utility customers 100 communities served 67 communities served Colorado 308,600 utility customers 119 communities served 617 megawatts of owned power generation capacity Iowa 162,800 utility customers 133 communities served 87 megawatts of owned power generation capacity Montana 44 utility customers 2 communities served Nebraska 298,800 utility customers 319 communities served South Dakota 72,500 utility customers 29 communities served 150 megawatts of owned power generation capacity Wyoming 180,700 utility customers 56 communities served 174 million tons of coal reserves 627 megawatts of owned power generation capacity Electric Utilities Natural Gas Utilities Power Generation Wind Generation Electric and Natural Gas Utilities Company Headquarters Mine Renewable natural gas interconnection sites Use bounding box to hide marks and text once placed.Above marks denote minumum height of graphic.Use bounding box to hide marks and text once placed.Above marks denote minumum height of graphic.Use bounding box to hide marks and text once placed.Above marks denote minumum height of graphic.Use bounding box to hide marks and text once placed.Above marks denote minumum height of graphic. Align mark to the right with right edge of document. Use bounding box to hide marks and text once placed. Dear fellow shareholders, At Black Hills Corporation, we continue to deliver on our mission of improving life with energy for our 1.3 million electric and natural gas customers across eight states. Since our founding in 1883 in Deadwood, South Dakota, our trusted presence has empowered the success of our customers and communities. We’ve enabled dreams, cultivated opportunities and provided stability to overcome uncertainty. With a storied history of weathering unique challenges together, we recognize the tenacity of the people we live and work with across our service territories. We take great pride in being their valued energy partner and solid foundation for powering a better future. The resiliency of our team, infrastructure and customer-focused strategy was proven once again in 2022. It’s during these times of testing that we learn and grow, with results shining light on strengths and highlighting opportunities. Our success in strategic execution was spotlighted by our industry-leading reliability while serving growing customer demand. Together, we successfully managed our business and navigated supply chain, macroeconomic and industry challenges to deliver solid earnings growth in 2022. These results highlighted our team’s pursuit of customer solutions, profitable growth, and execution on fair and timely regulatory recovery of our investments and costs to serve customers. Social, economic and energy industry trends highlight the essential need for resilient infrastructure and a robust financial position. We made strong progress advancing our plans to maintain reliable, safe, cost-effective and clean energy infrastructure. In addition, we took disciplined measures toward strengthening our balance sheet, which remains a key focus of ours in the coming year. Resilient foundation The reliability and safety of electric and natural gas service is more critical than ever with growing demand, the ongoing clean energy transition and more interconnected global economy and energy systems. Our dependable energy infrastructure is especially vital to the territories we serve where reliability goes hand-in-hand with safety and encourages thriving, growing communities. We proudly delivered another year of industry-leading electric reliability, with all three of our electric utilities recognized in the top quartile of industry reliability performance. Our high level of service is especially noteworthy in light of ongoing customer growth. This growth was reflected in 11 new summer and winter electric peak loads in 2022, including a remarkable ninth consecutive year of new peaks at Wyoming Electric, a 53% increase since 2013. Natural gas demand was also www.blackhillscorp.com strong at the gas utilities, where we continued to deploy capital with a focus on safety and system integrity to maintain resiliency through extreme weather events, such as Winter Storms Uri in 2021 and Elliot in December 2022. Success in serving the growing needs of our customers requires consistent investment and a forward-thinking operational team. In 2022, we deployed $598 million of capital primarily for safety and resiliency and to meet ongoing customer growth. Maintaining that focus, we are forecasting capital investments of $3.5 billion over the next five years. We are balancing investment needs against strengthening our balance sheet and customer costs, particularly in the current inflationary environment. In striking that balance, we are projecting capital investment of approximately $600 million for 2023, while continuing to focus on financial discipline and placing an intentional emphasis on fostering our continuous improvement culture. Powering a better future Sustainability and the source of our energy matters to our stakeholders and to us. We are responsibly integrating renewable resources and reducing emissions while preserving reliability, resiliency and delivering cost-effective energy to our customers. At our electric utilities, we are targeting a 70% reduction in greenhouse gas emissions intensity by 2040 from a 2005 base. During 2022, we enhanced our gas utilities emissions target to Net Zero by 2035,* and plan to meet this target through ongoing infrastructure investment, process enhancements, integration of renewable resources and carbon offset credits. During 2022, we moved closer to making our electric utility emissions goals a reality through our electric resource plans. We recently reached a unanimous settlement agreement for our Colorado Clean Energy Plan filed in May 2022 to achieve the state’s emission reduction target of 80% by 2030. The settlement provides incentives for 50% utility ownership of the estimated 400 megawatts of renewable and battery clean energy resources we will need to meet our goals. We also moved forward with our electric resource plan in South Dakota that was filed in 2021, which proposes the addition of 100 megawatts of renewable resources by 2025 and exploration of battery storage. Another significant milestone was receiving regulatory approval for the Ready Wyoming project, our 260-mile transmission expansion initiative in southeastern Wyoming. It will create a robust and more interconnected transmission and distribution system in eastern Wyoming to enhance the resiliency of our overall system, expand access to power markets and renewable energy resources, and create long-term price stability for customers. We are excited about this project and its ability to support vibrant growth and innovation in Wyoming. Construction is planned to commence in 2023 and the project to be fully in service by the end of 2025. Underlying all we do is our culture of safety and our mindset of serving our customers better every day. We are intentional about doing business more effectively and efficiently with our Energy Forward initiative, which is focused on both big picture and day-to-day process enhancements that will move us forward as the utility of the future. * Net Zero goal based on Scope 1 emissions of gas distribution systems, including fugitive emissions from pipeline mains and service lines, meters, transfer stations, system damages and blow downs. www.blackhillscorp.com Growing long-term value We continued to build on our legacy of long-term growth for our stakeholders in 2022. This growth is reflected in our dividend, which we have increased for 52 consecutive years, one of the longest streaks in our industry. Our enduring success begins with executing on our customer-focused capital investment program, where our long-term, risk-prioritized approach directs investments toward core system needs. We delivered full year earnings of $3.97 per share, a 6% increase year-over-year. These results were achieved through consistent execution of our investment and regulatory plans, operational excellence in serving strong weather-driven customer demand and ongoing customer growth. We successfully managed through challenging supply chain and economic environments, including the impacts of historic inflation and rising interest rates in the last half of 2022. Successfully executing our regulatory plan to achieve fair and timely recovery of our investments to serve customers continued to be a core strength and focus in 2022. We filed and settled rate reviews and rider requests for our Arkansas gas utility and Wyoming electric utility and filed a new rate review for our intrastate pipeline in Colorado. We also gained the last approval required to recover the $546 million in incremental fuel costs incurred for customers resulting from Winter Storm Uri, and we have already recovered more than one-third of those costs. We continue to be excited about the future. As we step forward through near-term macroeconomic challenges, our solid financial position prepares us for long-term growth and our dedicated team continues to serve our customers with excellence, while cultivating profitable growth. As we close this letter, we recognize our success would not be possible without you, our shareholders. Thank you for the confidence and trust you have placed in our company. Sincerely, Steve Mills, Chairman, Black Hills Corp. Board of Directors Linn Evans, President and CEO, Black Hills Corp. www.blackhillscorp.com (This page has been left blank intentionally.) PROXYBLACK HILLS CORPORATION Notice of 2023 Annual Meeting of Shareholders and Proxy Statement PROXY(This page has been left blank intentionally.) PROXYBLACK HILLS CORPORATION NOTICE OF ANNUAL MEETING OF SHAREHOLDERS WHEN: Tuesday, April 25, 2023 9:30 a.m., local time WHERE: Horizon Point Company’s Corporate Headquarters 7001 Mount Rushmore Road Rapid City, South Dakota 57702 We are pleased to invite you to attend the annual meeting of shareholders of Black Hills Corporation. In the event it is not possible to attend our annual meeting in person, we encourage you to listen to the meeting by calling in: 605-782-9484, Conference ID: 744 233 731#. The presentation for this meeting can be located at www.blackhillscorp.com by clicking on "Events and Presentations" in the "Investor Relations" section. The presentation will be posted on the website before the call. Please note, if you attend by calling in, you will not be able to vote your shares or submit questions. Accordingly, it is important that you vote your shares as instructed below. Proposals: 1. 2. 3. 4. 5. Election of three directors in Class II: Scott M. Prochazka, Rebecca B. Roberts, and Teresa A. Taylor. Ratification of Deloitte & Touche LLP to serve as our independent registered public accounting firm for 2023. Advisory vote to approve our executive compensation. Advisory vote on the frequency of the advisory vote on our executive compensation. Any other business that properly comes before the annual meeting. Record Date: The Board set March 6, 2023 as the record date for the meeting. This means that our shareholders as of the close of business on that date are entitled to receive this notice of the meeting and vote at the meeting and any adjournments or postponements of the meeting. How to Vote: Your vote is very important. You may vote your shares by telephone, by the Internet or by returning the enclosed proxy. If you own shares of common stock other than the shares shown on the enclosed proxy, you will receive a proxy in a separate envelope for each such holding. Please vote each proxy received. To make sure that your vote is counted if voting by mail, you should allow enough time for the postal service to deliver your proxy before the meeting. Sincerely, /s/ AMY K. KOENIG Amy K. Koenig Vice President - Governance, Corporate Secretary and Deputy General Counsel PROXY1 PROXY SUMMARYBLACK HILLS CORPORATION OVERVIEWWe are a customer-focused energy solution provider that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission – and our primary focus – is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.Items of Business to be Considered at the Annual MeetingProposalBoard RecommendationPage1Election of Directors FOReach Director Nominee62Ratification of Deloitte & Touche LLP to Serve as Independent Registered Public Accounting Firm for 2023 FOR213Advisory Vote to Approve Executive Compensation FOR244Advisory Vote on the Frequency of the Advisory Vote on our Executive Compensation 1 YEAR51BOARD OF DIRECTORSDirector NomineesOur Board of Directors ("Board") is committed to oversight that promotes the long-term interests of our shareholders and other stakeholders. We believe this is best achieved with directors who bring a diverse and relevant set of skills, expertise, experiences and perspectives. Our Board is nominating three individuals for election at this annual meeting. The following table provides summary information about the nominees:NameAgeDirector SinceIndependentCommittee MembershipOther Public BoardsScott M. Prochazka572020XCompensationLi-Cycle Holdings Corp. Peridot Acquisition Corp. IIRebecca B. Roberts702011XCompensation Governance (Chair)AbbVie, Inc.MSA Safety, Inc.Teresa A. Taylor592016XCompensation (Chair)GovernanceT-Mobile USA, Inc.PROXYPROXY| PROXY SUMMARY2 PROXY SUMMARYBLACK HILLS CORPORATION OVERVIEWWe are a customer-focused energy solution provider that invests in our communities’ safety, sustainability and growth with a mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission – and our primary focus – is to provide safe, reliable and cost-effective electric and natural gas service to 1.3 million utility customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming.Items of Business to be Considered at the Annual MeetingProposalBoard RecommendationPage1Election of Directors FOReach Director Nominee62Ratification of Deloitte & Touche LLP to Serve as Independent Registered Public Accounting Firm for 2023 FOR213Advisory Vote to Approve Executive Compensation FOR244Advisory Vote on the Frequency of the Advisory Vote on our Executive Compensation 1 YEAR51BOARD OF DIRECTORSDirector NomineesOur Board of Directors ("Board") is committed to oversight that promotes the long-term interests of our shareholders and other stakeholders. We believe this is best achieved with directors who bring a diverse and relevant set of skills, expertise, experiences and perspectives. Our Board is nominating three individuals for election at this annual meeting. The following table provides summary information about the nominees:NameAgeDirector SinceIndependentCommittee MembershipOther Public BoardsScott M. Prochazka572020XCompensationLi-Cycle Holdings Corp. Peridot Acquisition Corp. IIRebecca B. Roberts702011XCompensation Governance (Chair)AbbVie, Inc.MSA Safety, Inc.Teresa A. Taylor592016XCompensation (Chair)GovernanceT-Mobile USA, Inc.Director Skills and Demographics EvansGrangerJensenMcAllisterMillsOttoProchazkaRobertsSchoberTaylorSkills and ExperienceBusiness OperationsXXXXXXXXCustomer ServiceXXXCybersecurity/TechnologyXXESG/SustainabilityXXXFinancial AcumenXXXXXXXXGovernment/RegulatoryXXXXXXHealth and SafetyXXXXXXXHuman Capital Management/CompensationXXXXLegal/Governance/ComplianceXXXXMergers and AcquisitionsXXXXXXRisk ManagementXXXXXXXXXXStrategic PlanningXXXXXXXXXXUtility IndustryXXXBoard TenureYears423311621176AgeYears Old60636058676357706759GenderFemaleXXXMaleXXXXXXXRace/EthnicityAfrican American/BlackXWhite/CaucasianXXXXXXXXXOUR COMMITMENT TO SUSTAINABILITYOur mission of Improving Life with Energy means we must be ready to make tomorrow even better than today. That is why we are committed to creating a cleaner energy future which builds upon our responsibility to provide the safe, reliable and cost-effective energy that improves our customers’ lives. By investing in the success of our employees, continually innovating, thoughtfully utilizing resources and keeping people at the core of our decision-making, we are dedicated to the sustainability of our Company, communities and planet. Environmental, Social and Governance (ESG) Strategy and OversightWe are excited to announce significant advancements in our decarbonization journey. We are building upon our success of delivering cost-effective energy for customers and strong returns for investors by seeking renewable energy growth opportunities, minimizing risk and responding to stakeholders’ evolving expectations. ESG and sustainability are inherently connected throughout our business and our ESG management is structured accordingly. Our Board oversees ESG, with management leadership from our CEO and executive steering committee, our dedicated department and our cross functional sustainability working group. PROXYPROXYPROXY SUMMARY |Responsibly Reducing Greenhouse Gas Emissions In November 2020, we announced clean energy goals to reduce greenhouse gas (GHG) emissions intensity for our Electric Utilities of 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. In August 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubles the previous target of a 50% reduction by 2035. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-party damage reduction, expanding the use of renewable natural gas (RNG) and hydrogen, and utilizing carbon credit offsets. Electric Utilities Goals(1)(2)  40% by 2030  70% by 2040 Natural Gas Utilities Goals(1)(3)  Net Zero by 2035 (1) (2) (3) Our goals are compared to a 2005 baseline. Electric Utilities goals include Scope 1 emissions from electric utility generating units and Scope 3 emissions from purchased power for sales. Natural Gas Utilities goals include all Scope 1 sources of methane emissions on our distribution system, including fugitive emissions from pipeline mains and service lines, meters, transfer stations, system damages and system blow downs. We are proud of our sustainability efforts and continue to pursue initiatives to enable the transition to a cleaner energy future, including: Since 2005, we have reduced GHG emissions intensity from our natural gas distribution system mains and services by more than 33% and achieved a 33% reduction in electric utility emissions (a nearly 10% reduction since announcing our goal in 2020 for our electric utilities). We have advanced our role in RNG. In 2021, we developed a voluntary RNG and carbon offset program to help our residential and small business natural gas customers offset up to 100% or more of the emissions associated with their own natural gas usage. We've filed for approval to launch these programs in three of our states, have received approval in two states, and plan to seek approval to offer to all customers in 2023. As we look to the future, our more than 520 MW of planned battery storage, renewable generation and additions, and investments in innovation, such as our hydrogen pilot study, position us to achieve deeper carbon reductions that also deliver reliable and cost-effective energy to our customers. We will continue executing our strategy of investing in cost-effective renewables and new technologies to further reduce our environmental impact across all states in which we operate, while continuing to deliver safe, reliable and cost effective energy to customers. For additional information on our commitment to sustainability, you can review the following 2021 ESG reports on our website at www.blackhillsenergy.com/our-company/commitment-sustainability/sustainability-and-esg-reports: 2021 Corporate Sustainability Report 2021 Edison Electric Institute ESG Disclosure 2021 American Gas Association ESG Disclosure 2021 Natural Gas Sustainability Initiative Disclosure 2021 Sustainability Accounting Standards Board Disclosure 2021 Task Force on Climate Related Financial Disclosure Index 3 PROXYPROXY| PROXY SUMMARYEXECUTIVE COMPENSATION We have an Executive Compensation Philosophy that establishes the framework our Compensation Committee applies in structuring compensation for our executive officers ("Named Executive Officers" or "NEOs"). The components of our executive pay program consist of a base salary, a short-term incentive plan, and long-term incentives. Our executive pay program aligns the interest of our Named Executive Officers with our stakeholders by tying incentive pay to achievement of performance metrics. Variable Linked to Share Value 78% 57% Variable Linked to Share Value 63% 40% *Percentages may differ from above due to rounding. The performance measures for our incentive compensation plans are discussed in greater detail on page 28 of the Proxy Statement. We also require our executive officers to hold a significant amount of our common stock (between 3 and 6 times the base salary) to further align their performance with the interest of our stakeholders. Our compensation practices and policies demonstrate the alignment between executive compensation and the interests of our stakeholders. Our shareholders share our confidence in our compensation philosophy as reflected by the support of shareholders owning 95 percent of the shares who voted to approve our 2021 executive compensation at last year's annual meeting. The following table summarizes our 2022 performance metrics and results for incentive plans that ended in 2022. Pay Element Performance Measure 2022 Results 70 Percent 7.5 Percent 7.5 Percent 7.5 Percent 7.5 Percent Short-term Incentive: Payout of 71.48% of Target EPS from ongoing operations, as adjusted, target set at $4.05; threshold set at $3.77 System Average Interruption Duration Index (SAIDI), target set at 65.80; threshold set at 74.40 Hits Per Thousand (HPT), target set at 2.05; threshold set at 2.16 Total Case Incident Rate (TCIR), target set at 1.00; threshold set at 1.25 Diversity Training $3.97 per share for incentive plan purposes SAIDI:70.14 HPT: 2.26 TCIR: 1.39 Diversity Training: 100% of Target Long-term Incentive (2020-2022 Plan): Payout of 26.98% of Target Performance Share Award Total Shareholder Return (TSR) relative to our Performance Peer Group measured over a three-year period TSR: 0.14% 26th Percentile Ranking in Performance Peer Group 4 PROXYPROXYPROXY SUMMARY |2022 ACCOMPLISHMENTS AND PERFORMANCE Black Hills Corporation reported excellent operational performance in 2022. Earnings per share for the year increased 6% compared to 2021. Consistent execution of our strategy focusing on our customer's needs, cultivating growth, and achieving fair and timely regulatory recovery successfully offset the impact of higher interest rates and inflation in 2022. Significant accomplishments for the year included:  Provided the safe and reliable service our communities and customers depend on and achieved several notable operations performance metrics: * * * * Achieved top-quartile reliability metrics by our three electric utilities Achieved a safety performance total case incident rate of 1.39 compared to a 2020 American Gas Association second quartile reported average of 1.52 Achieved a safety performance preventable motor vehicle incident rate of 1.33 compared to a 2020 American Gas Association reported top quartile average of 1.56 Served ongoing demand growth through 11 new summer or winter electric demand peaks * Wyodak received its CORESafety Certification through the National Mining Association * Energy Star Partner of the Year for sustained excellence in Arkansas Completed financing activity to accomplish our long-term objective of investing to meet the needs of our customers, including: * Issued 1.3 million shares of new common stock for net proceeds of $90 million under our at-the-market equity offering program * * * Grew our dividend for the 52nd consecutive year with a 5.2 percent increase in calendar year 2022 over 2021 Invested in our utility infrastructure and systems: Deployed $598 million in capital projects Secured adequate liquidity to serve customers through compounding impacts of Winter Storm Uri in 2021, Storm Elliot and high natural gas prices in 2022 Executed a number of regulatory accomplishments: * Successfully completed rate review requests for Arkansas Gas and Wyoming Electric All Winter Storm Uri regulatory recovery plans approved; more than 33% of $546 million of fuel costs recovered to date Reached a constructive settlement for Colorado Electric's Clean Energy Plan which, if approved, will result in nearly 70% of the electricity to meet customers' needs being generated by carbon-free sources by 2030 Received a Certificate of Public Convenience and Necessity for the Ready Wyoming 260-mile multi-phase transmission expansion project * * * Continued our focus on sustainability, including: * Announced a new commitment to achieve Net Zero emission by 2035 for our natural gas distribution system * * Issued an updated sustainability report and EEI, AGA, SASB, and NGSI disclosures, and provided new TCFD disclosures Our electric utilities surpassed the one-third reduction of GHG emission mark and achieved a nearly 10% reduction in emissions intensity since announcing our goals     5 PROXYPROXY| PROXY SUMMARYBLACK HILLS CORPORATION 7001 Mount Rushmore Road Rapid City, South Dakota 57702 PROXY STATEMENT  A proxy in the accompanying form is solicited by the Board of Black Hills Corporation, a South Dakota corporation, to be voted at the annual meeting of our shareholders to be held Tuesday, April 25, 2023, and at any adjournment of the annual meeting.  The enclosed form of proxy, when executed and returned, will be voted as set forth in the proxy. Any shareholder signing a proxy has the power to revoke the proxy in writing, addressed to our secretary, or in person at the meeting at any time before the proxy is exercised.  This proxy statement and the accompanying form of proxy are to be first mailed on or about March 15, 2023. Our 2022 annual report to shareholders is being mailed to shareholders with this proxy statement. VOTING RIGHTS AND PRINCIPAL HOLDERS   Only our shareholders of record at the close of business on March 6, 2023 are entitled to vote at the meeting. Our outstanding voting stock as of the record date consisted of 66,277,565 shares of our common stock. Each outstanding share of our common stock is entitled to one vote. Cumulative voting is permitted in the election of directors in the same class. 1 PROXYPROXY STATEMENT |TABLE OF CONTENTS Commonly Asked Questions and Answers About the Annual Meeting Process Proposal 1 - Election of Directors Corporate Governance Meetings and Committees of the Board Director Compensation Security Ownership of Management and Principal Shareholders Proposal 2 - Ratification of Appointment of Independent Registered Public Accounting Firm Fees Paid to the Independent Registered Public Accounting Firm Audit Committee Report Proposal 3 - Advisory Vote on Our Executive Compensation Executive Compensation Compensation Discussion and Analysis Report of the Compensation Committee Summary Compensation Table Grants of Plan Based Awards in 2022 Outstanding Equity Awards at Fiscal Year-End 2022 Option Exercises and Stock Vested During 2022 Pension Benefits for 2022 Nonqualified Deferred Compensation for 2022 Potential Payments Upon Termination or Change in Control Pay Ratio for 2022 Pay versus Performance Proposal 4 - Advisory Vote on the Frequency of the Advisory Vote on our Executive Compensation Transaction of Other Business Shareholder Proposals for 2024 Annual Meeting Shared Address Shareholders Annual Report on Form 10-K Notice Regarding Availability of Proxy Materials 2 Page 3 6 12 15 17 19 21 22 23 24 25 25 36 37 38 39 40 40 42 43 47 47 51 52 52 53 53 53 PROXY| PROXY STATEMENTCOMMONLY ASKED QUESTIONS AND ANSWERS ABOUT THE ANNUAL MEETING PROCESS Who is soliciting my proxy? The Board of Directors of Black Hills Corporation is soliciting your proxy. Where and when is the annual meeting? The annual meeting is at 9:30 a.m., local time, April 25, 2023 at Horizon Point, the Company’s corporate headquarters, 7001 Mount Rushmore Road, Rapid City, South Dakota. Who can vote? Holders of our common stock as of the close of business on the record date, March 6, 2023, can vote at our annual meeting. Each share of our common stock has one vote for Proposals 2, 3, and 4. Related to Proposal 1, Election of Directors, cumulative voting is permitted in the election of directors in the same class. How do I vote? There are three ways to vote by proxy: by calling the toll free telephone number on the enclosed proxy; by going to the website identified on the enclosed proxy; or by returning the enclosed proxy in the envelope provided. You may be able to vote by telephone or over the Internet if your shares are held in the name of a bank or broker. If this is the case, you will need to follow their instructions. What constitutes a quorum? Shareholders representing at least 50 percent of our common stock issued and outstanding as of the record date must be present at the annual meeting, either in person or by proxy, for there to be a quorum. Abstentions and broker non-votes are counted as present for establishing a quorum. A broker non-vote occurs when a broker or other nominee holding shares for a beneficial owner does not vote on a particular proposal because the broker or nominee does not have discretionary voting power and has not received instructions from the beneficial owner. 3 PROXYPROXY STATEMENT |What am I voting on and what is the required vote for the proposals to be adopted? The required vote and method of counting votes for the various business matters to be considered at the annual meeting are described in the table below. If you sign and return your proxy card without indicating your vote, your shares will be voted in accordance with the Board recommendations as set forth below. Item of Business Proposal 1: Election of Directors Board Recommendation FOR election of each director nominee Voting Approval Standard The three nominees with the most "FOR" votes are elected to their respective classes. If a nominee receives more "WITHHOLD AUTHORITY" votes than "FOR" votes, the nominee must submit a resignation for consideration by the Governance Committee and final Board decision. Effect of Abstention Effect of Broker Non-Vote No effect No effect Proposal 2: Ratification of Appointment of Independent Registered Public Accounting Firm Proposal 3: Advisory Vote to Approve Executive Compensation Proposal 4: Advisory Vote on the Frequency of the Advisory Vote to Approve Executive Compensation FOR The votes cast "FOR" must exceed the votes cast "AGAINST". No effect Not applicable; broker may vote shares without instruction FOR 1 YEAR The votes cast "FOR" must exceed the votes cast "AGAINST". This advisory vote is not binding on the Board, but the Board will consider the vote results when making future executive compensation decisions. The frequency receiving the greatest number of votes will be considered by the advisory vote of the shareholders. This advisory vote is not binding on the Board, but the Board will consider the vote result when determining the frequency of the say on pay vote. No effect No effect No effect No effect Is cumulative voting permitted for the election of directors? In the election of directors, you may cumulate your vote. Cumulative voting allows you to allocate among the director nominees in the same class, as you see fit, the total number of votes equal to the number of director positions to be filled multiplied by the number of shares you hold. For example, if you own 100 shares of stock, and there are three directors to be elected in a class at the annual meeting, you could allocate 300 “For” votes (three times 100) among as few or as many of the three nominees to be voted on at the annual meeting as you choose. If you choose to cumulate your votes, you will need to submit a proxy card or a ballot and make an explicit statement of your intent to cumulate your votes, either by indicating in writing on the proxy card or by indicating in writing on your ballot when voting at the annual meeting. If you hold shares beneficially in street name and wish to cumulate votes, you should contact your broker, trustee or nominee. 4 PROXY| PROXY STATEMENTHow will my shares be voted if they are held in a broker’s name? If you hold your shares through an account with a bank or broker, the bank or broker may vote your shares on some matters even if you do not provide voting instructions. Brokerage firms have the authority under the New York Stock Exchange ("NYSE") rules to vote shares on certain matters (such as the ratification of auditors) when their customers do not provide voting instructions. However, on most other matters when the brokerage firm has not received voting instructions from its customers, the brokerage firm cannot vote the shares on that matter and a “broker non-vote” occurs. This means that brokers may not vote your shares on the election of directors, the “say on pay” advisory vote and the "say on frequency" advisory vote if you have not given your broker specific instructions as to how to vote. Please be sure to give specific voting instructions to your broker so that your vote can be counted. What should I do now? You should vote your shares by telephone, over the Internet or by returning your signed and dated proxy card in the enclosed envelope as soon as possible so that your shares will be represented at the annual meeting. Who will count the vote? Representatives of our transfer agent, Equiniti Trust Company, will count the votes and serve as judges of the election. Who conducts the proxy solicitation and how much will it cost? We are asking for your proxy for the annual meeting and will pay all the costs of asking for shareholder proxies. We have hired Georgeson LLC to help us send out the proxy materials and ask for proxies. Georgeson LLC’s fee for these services is anticipated to be $12,250 plus out-of-pocket expenses. We can ask for proxies through the mail, by telephone or in person. We can use our directors, officers and employees to ask for proxies. These people do not receive additional compensation for these services. We will reimburse brokers and other custodians, nominees and fiduciaries for their reasonable out-of-pocket expenses for forwarding solicitation material to the beneficial owners of our common stock. Can I revoke my proxy? Yes. You can change your vote in one of four ways at any time before your proxy is used. First, you can enter a new vote by telephone or Internet. Second, you can revoke your proxy by written notice. Third, you can send a later dated proxy changing your vote. Fourth, you can attend the meeting and vote in person. Who should I call with questions? If you have questions about the annual meeting, you should call Amy K. Koenig, Vice President - Governance, Corporate Secretary and Deputy General Counsel, at (605) 721-1700. 5 PROXYPROXY STATEMENT |PROPOSAL 1 ELECTION OF DIRECTORS Our Board is nominating three individuals for election as directors at this annual meeting. All of the nominees are currently serving as our directors. In accordance with our Bylaws and Article VI of our Articles of Incorporation, members of our Board are elected to three classes of staggered terms consisting of three years each, and until their successors are duly elected and qualified. At this annual meeting, three directors will be elected to Class II for a term of three years until our annual meeting in 2026. Nominees for director at the annual meeting are Scott M. Prochazka, Rebecca B. Roberts, and Teresa A. Taylor. Our Bylaws require a minimum of nine directors. Currently, the Board has set the size of the Board at 10 directors. Pursuant to our Bylaws, directors must resign from the Board at the annual meeting after attaining 72 years of age. Accordingly, Ms. Roberts, who will turn 72 prior to our 2025 annual meeting, is required to resign effective at our 2025 annual meeting and therefore will serve only two years of her term. If, at the time of the annual meeting, any nominees are unable to stand for election, the Board may designate a substitute or reduce the number of directors to no less than nine. In that case, shares represented by proxies may be voted for a substitute director nominated by the Board. We do not expect that any nominee will be unavailable or unable to serve. The Board and the Governance Committee believe that the combination of the various qualifications, skills and experiences of the directors contribute to an effective and well-functioning Board, and that, individually and as a whole, the directors possess the necessary qualifications to provide effective oversight of the business and quality advice to the Company’s management. Included in each director’s biography below is an assessment of the specific qualifications, attributes, skills and experience that have led to the conclusion that each individual should serve as a director in light of our current business and structure. The Board recommends a vote FOR the election of the following nominees: Director Nominee Scott M. Prochazka Rebecca B. Roberts Teresa A. Taylor Class Year Term Expiring II II II 2026 2026 2026 6 PROXY| PROXY STATEMENTDIRECTOR SKILLS AND EXPERIENCE Linden R. Evans Outside Directorships: President and Chief Executive Officer of the Company None Director since: 2018 Director Class: III, term expiring in 2024 Age: 60 Summary: Mr. Evans has been President and Chief Executive Officer of the Company since January 1, 2019. He previously served as President and Chief Operating Officer from 2016 to 2018, and President and Chief Operating Officer – Utilities from 2004 to 2015. He began his career with Black Hills Corporation in 2001 as Corporate Counsel. Prior to joining the Company, Mr. Evans was a mining engineer and an attorney specializing in environmental and corporate legal matters. Skills Relevant to BHC: As CEO of Black Hills Corporation, Mr. Evans brings historic institutional knowledge of the Company and its operations that assist the Board in its evaluation of the Company’s financial and operational risks and strategy. Barry M. Granger Standing Board Committees: Managing Partner and Co-Founder of Vonbar Investments LLC Audit Committee Director since: 2020 Director Class: III, term expiring in 2024 Outside Directorships: Age: 63 None Summary: Mr. Granger has over 35 years of experience in the chemical, materials and industrial markets. He is the Managing Partner of Vonbar Investments LLC, a consulting firm he founded in 2018. He held roles as Vice President of Government Marketing and Government Affairs at DuPont from 2010 to 2017 and Vice President and General Manager, Tyvek® from 2007 to 2010. Early in his career, he served as the Executive Assistant to the Chairman and CEO of DuPont. He has held a variety of leadership positions with increasing responsibilities in operations, product management, sales and marketing. Skills Relevant to BHC: Mr. Granger’s leadership roles in the areas of governmental affairs and operations offer the Board insight regarding oversight of operations, regulatory affairs, and safety. 7 PROXYPROXY STATEMENT |Tony A. Jensen Standing Board Committees: Retired Director, President and Chief Executive Officer of Royal Gold, Inc. Compensation Committee Director since: 2019 Director Class: III, term expiring in 2024 Outside Directorships: Age: 60 None Summary: Mr. Jensen has over 35 years of experience in the international mining and mining finance industries. From 2003 until his retirement in 2019, Mr. Jensen served in several leadership roles at Royal Gold, Inc., a public precious metals company, including Director, President and Chief Executive Officer from 2006 to 2019, and Chief Operating Officer from 2003 to 2006. Prior to 2003, he held progressively more responsible roles in engineering, finance, strategic growth, safety, environmental excellence, and operational efficiency. Skills Relevant to BHC: As a former CEO of a publicly traded precious metals stream and royalty company, Mr. Jensen brings business, leadership, governance, and financial expertise that assists Board in evaluating the Company’s financial risks and strategy and capital deployment. Kathleen S. McAllister Standing Board Committees: Retired Director, President and Chief Executive Officer of Transocean Partners LLC Audit Committee Director since: 2019 Director Class: I, term expiring in 2025 Outside Directorships: Age: 58 Summary: Silverbow Resources, Inc. (since 2023) TMC The Metals Company Inc. (since 2022) Ms. McAllister has over 30 years of experience in diverse leadership roles with global, capital intensive companies in the energy value chain. She served as Director, President and CEO of Transocean Partners LLC, an international provider of offshore contract drilling services from 2014 to 2016, and as CFO in 2016. She held the roles of Vice President and Treasurer of Transocean Ltd. from 2011 to 2014. Prior to 2011, she served in roles with increasing responsibility in finance, information technology, tax and treasury. Ms. McAllister is a National Association of Corporate Directors Board Fellow and a Certified Public Accountant. She previously served on the board of Maersk Drilling from 2019 to 2021, where she chaired the Audit and Risk Committee. She is a Board Member of Silverbow Resources, Inc. and TMC The Metals Company Inc., where she chairs the Audit Committees. Skills Relevant to BHC: As a former CEO, CFO and Treasurer of publicly traded companies, Ms. McAllister's broad business perspective, financial acumen and experience in capital raising and allocation contributes to the Board's oversight of strategy and risk. Her experience serving as a corporate director and audit and risk committee chair on other public company boards provides a valuable perspective on the Board's role in management oversight and corporate governance. 8 PROXY| PROXY STATEMENTSteven R. Mills Standing Board Committees: Chairman of the Board Retired Public Company Financial Executive Governance Committee Director since: 2011 Director Class: III, term expiring in 2024 Outside Directorships: Age: 67 Amyris, Inc. (since 2018) Summary: Mr. Mills has more than 40 years of experience in the fields of accounting, corporate finance, strategic planning, risk management, and mergers and acquisitions. He is a Board Member of Amyris, Inc., a renewable products company, where he serves as Chair of the Audit Committee and as a member of the Leadership, Development, Inclusion and Compensation Committee. Mr. Mills is also a consultant and advisor to Arianna S.A., a European-based specialized investment fund. Previously, Mr. Mills served as Chief Financial Officer of Amyris, Inc. from 2012 to 2013. Prior to joining Amyris, he had a 33-year career at Archer Daniels Midland Company, one of the world’s largest agricultural processors and food ingredient providers, where he held various senior executive roles, including Senior Executive Vice President Performance and Growth, Chief Financial Officer, Controller, and Senior Vice President Strategic Planning. Skills Relevant to BHC: Mr. Mills brings to the Board executive leadership and financial experience as a former CFO of publicly traded companies and strategic planning experience as both a former senior vice president of strategic planning and a senior executive vice president performance and growth for a publicly traded company. These roles also position Mr. Mills to provide the Board perspectives on mergers and acquisitions and capital deployment. Robert P. Otto Standing Board Committees: Owner of Bob Otto Consulting LLC Audit Committee Director since: 2017 Director Class: I, term expiring in 2025 Outside Directorships: Age: 63 None Summary: Since 2017, Mr. Otto has provided strategic planning and advisory services in cybersecurity and intelligence through his company, Bob Otto Consulting LLC. With 34 years of U.S. Air Force service, he served as a general officer from 2008 to 2016, culminating as lieutenant general and the Deputy Chief of Staff for Intelligence, Surveillance and Reconnaissance. He was directly responsible for intelligence policy, planning, implementation, oversight, and leadership of a 27,000-person workforce. Skills Relevant to BHC: Mr. Otto’s experience in cybersecurity and intelligence through his lengthy career with the U.S. Air Force provide the Board information technology and cybersecurity expertise. His leadership and oversight of a large workforce position him to provide the Board insights regarding human capital management. 9 PROXYPROXY STATEMENT |Scott M. Prochazka Standing Board Committees: Former Board Member, President and Chief Executive Officer of CenterPoint Energy Compensation Committee Director since: 2020 Director Nominee Class: II, term expiring in 2026 Age: 57 Outside Directorships: Peridot Acquisition Corp. II (since 2021) Li-Cycle Holdings Corp. (since 2021) Summary: Mr. Prochazka served as Board Member, President and Chief Executive Officer of CenterPoint Energy, a public energy delivery company with electric transmission and distribution, power generation and natural gas distribution operations, from 2014 until his retirement in 2020. Prior to that he was Chief Operating Officer from 2012 to 2013, Senior Vice President of Electric Business from 2011 to 2012, and Vice President of Gas Business Unit from 2009 to 2011. He held other management positions including Vice President Customer Care and Support Services and Vice President Texas Gas Region. Before his time at CenterPoint Energy, Mr. Prochazka held roles of increasing responsibility at Dow Chemical. Mr. Prochazka was a Board Member of Enable Midstream Partners, LP from 2014 to 2020, and Chairman from 2015 to 2017. Mr. Prochazka was previously a Board Member of Peridot Acquisition Corporation, from 2020 to 2021, where he served on the Audit and Compensation Committees. He is a Board Member of Peridot Acquisition Corp. II where he serves on the Audit and Compensation Committees, and Li-Cycle Holdings Corp. (successor to Peridot Acquisition Corp.) where he chairs the Audit Committee and serves on the Nominating/Governance Committee and the Compensation Committee. Skills Relevant to BHC: Mr. Prochazka’s executive experience as a former CEO of a publicly traded electric and gas utility company, with a market cap more than four times that of Black Hills Corporation, and leadership experience as COO of both gas and electric utility divisions, provides a valuable perspective regarding utility business operations, regulatory and governmental affairs, safety, capital deployment and risk management. Rebecca B. Roberts Standing Board Committees: Retired President of Chevron Pipe Line Company Compensation Committee Governance Committee (Chair) Director since: 2011 Director Nominee Class: II, term expiring in 2026 Outside Directorships: Age: 70 AbbVie, Inc. (since 2018) MSA Safety, Inc. (since 2013) Summary: Ms. Roberts has over 35 years of experience in the energy industry, including managing pipelines in North America and global pipeline projects, and managing a portfolio of power plants in the United States, Asia, and the Middle East. From 2006 until her retirement in 2011, Ms. Roberts served as the President of Chevron Pipe Line Company, a pipeline company transporting crude oil, refined petroleum products, liquefied petroleum gas, natural gas, and chemicals within the United States. From 2003 until 2006, she was the President of Chevron Global Power Generation. She was previously a Board Member of Enbridge, Inc., from 2015 to 2018. Ms. Roberts is a Board Member of Abbvie, Inc. and MSA Safety, Inc., where she serves as the Chair of the Compensation Committee. Skills Relevant to BHC: Ms. Robert’s executive experience overseeing natural gas pipelines and power generation facilities positions her to assist the Board as it evaluates the Company’s operational, health and safety risks. Her prior and ongoing experience on other public company boards provides insight as to the Board’s role in oversight of management as well as corporate governance. 10 Mark A. Schober Standing Board Committees: Retired Senior Vice President and Chief Financial Officer of ALLETE, Inc. Audit Committee (Chair) Governance Committee Director since: 2015 Director Class: I, term expiring in 2025 Outside Directorships: Age: 67 None Mr. Schober has more than 35 years of experience in the utility and energy industry. From 2006 until his retirement in 2014, Mr. Schober served as the Senior Vice President and Chief Financial Officer of ALLETE, Inc., a public energy company. His extensive industry experience in the upper Midwest provides expertise in the regulated business model and the unique challenges of the geographic and regulatory environment in which we operate. Summary: Skills Relevant to BHC: Mr. Schober brings to the Board business and leadership experience as a former executive of a public company, regulated utility experience as a former executive of a publicly traded Midwest based energy company, and financial expertise having served as a CFO. He also provides insight to the Company regarding potential exposures and risks in these areas. Teresa A. Taylor Standing Board Committees: Chief Executive Officer of Blue Valley Advisors, LLC Compensation Committee (Chair) Governance Committee Director since: 2016 2026 Age: 59 Director Nominee Class: II, term expiring in Outside Directorships: T-Mobile USA, Inc. (since 2013) Ms. Taylor has over 30 years of experience in the technology, media, and telecom sectors. She has been the Chief Executive Officer of Blue Valley Advisors, LLC, a consulting firm that she founded, since 2011. She was the Chief Operating Officer of Qwest Communications, Inc., a telecommunications carrier, from 2009 to 2011, where she led the daily operations and a senior management team responsible for 30,000 employees in field support, technical development, sales, marketing, customer support and information technology systems. She is a Board Member of T-Mobile USA, Inc. She was previously a Board Member of First Interstate BancSystem, Inc. from 2012 to 2020, Columbia Pipeline Group Inc. from 2015 to 2016, and NiSource, a public utility Summary: company from 2012 to 2015. Skills Relevant to BHC: Ms. Taylor’s broad range of experience over her three decades-long career, including in the fields of human resources, customer support, information technology systems, and business operations, add breadth and depth to the board. Her experience leading large employee teams lends toward engagement with the Board in the areas of compensation practices and human capital management. Ms. Taylor’s experience as a lead independent director of a publicly traded company provides further insight into Board governance and oversight of management. PROXY| PROXY STATEMENTMark A. Schober Standing Board Committees: Retired Senior Vice President and Chief Financial Officer of ALLETE, Inc. Audit Committee (Chair) Governance Committee Director since: 2015 Director Class: I, term expiring in 2025 Outside Directorships: Age: 67 None Summary: Mr. Schober has more than 35 years of experience in the utility and energy industry. From 2006 until his retirement in 2014, Mr. Schober served as the Senior Vice President and Chief Financial Officer of ALLETE, Inc., a public energy company. His extensive industry experience in the upper Midwest provides expertise in the regulated business model and the unique challenges of the geographic and regulatory environment in which we operate. Skills Relevant to BHC: Mr. Schober brings to the Board business and leadership experience as a former executive of a public company, regulated utility experience as a former executive of a publicly traded Midwest based energy company, and financial expertise having served as a CFO. He also provides insight to the Company regarding potential exposures and risks in these areas. Teresa A. Taylor Standing Board Committees: Chief Executive Officer of Blue Valley Advisors, LLC Compensation Committee (Chair) Governance Committee Director since: 2016 Director Nominee Class: II, term expiring in 2026 Outside Directorships: Age: 59 T-Mobile USA, Inc. (since 2013) Summary: Ms. Taylor has over 30 years of experience in the technology, media, and telecom sectors. She has been the Chief Executive Officer of Blue Valley Advisors, LLC, a consulting firm that she founded, since 2011. She was the Chief Operating Officer of Qwest Communications, Inc., a telecommunications carrier, from 2009 to 2011, where she led the daily operations and a senior management team responsible for 30,000 employees in field support, technical development, sales, marketing, customer support and information technology systems. She is a Board Member of T-Mobile USA, Inc. She was previously a Board Member of First Interstate BancSystem, Inc. from 2012 to 2020, Columbia Pipeline Group Inc. from 2015 to 2016, and NiSource, a public utility company from 2012 to 2015. Skills Relevant to BHC: Ms. Taylor’s broad range of experience over her three decades-long career, including in the fields of human resources, customer support, information technology systems, and business operations, add breadth and depth to the board. Her experience leading large employee teams lends toward engagement with the Board in the areas of compensation practices and human capital management. Ms. Taylor’s experience as a lead independent director of a publicly traded company provides further insight into Board governance and oversight of management. 11 PROXYPROXY STATEMENT |CORPORATE GOVERNANCE Corporate Governance Guidelines Our Board has adopted “Corporate Governance Guidelines of the Board,” which guide the operation of our Board and assist the Board in fulfilling its obligations to shareholders and other constituencies. The guidelines lay the foundation for the Board’s responsibilities, operations, leadership, organization and committee matters. The Governance Committee reviews the guidelines annually, and the guidelines may be amended at any time, upon recommendation by the Governance Committee and approval of the Board. These guidelines can be found in the “Governance” section of our website (www.blackhillscorp.com/investor-relations/corporate-governance). Board Leadership Structure On May 1, 2020, Steven R. Mills, an independent director, was appointed Chairman of the Board. As Chairman, Mr. Mills leads our Board in the performance of its duties by working with the CEO to establish meeting agendas, facilitating board meetings and executive sessions, and collaborating with the Board to annually evaluate the performance of the CEO. As provided in our Corporate Governance Guidelines, the Board does not have a policy on whether or not the roles of Chairman and CEO should be separate or combined. The Governance Committee annually reviews the appropriate leadership structure for the Company and recommends a Chairman for Board approval. While our Bylaws and Corporate Governance Guidelines do not require that our Chairman and CEO positions be held by separate individuals, the Board believes that having separate positions and having an independent director serve as Chairman is the appropriate leadership structure for the Company at this time because it allows our CEO to focus on business operations and our Chairman to focus on Board governance. Risk Oversight Our Board oversees an enterprise risk management ("ERM") approach to risk management that supports our operational and strategic objectives. It fulfills its oversight responsibilities through receipt of quarterly reports from management regarding material risks involving strategic planning and execution, operations, physical and cybersecurity, environmental, social and governance ("ESG"), financial, legal, safety, regulatory, and human resources risks. While our full Board retains responsibility for risk oversight, it delegates oversight of certain risk considerations to its committees within each of their respective areas of responsibility as defined in the charter for each committee. Our management is responsible for day-to-day risk management and operates under our ERM program that addresses enterprise risks. The ERM program includes practices to identify risks, assess the impact and likelihood of occurrence, and develop action plans to prevent the occurrence or mitigate the impact of the risk. The ERM program includes regular reporting to our senior management team, quarterly reporting to our Board, and monitoring and testing by the Risk Management, Compliance and Internal Audit groups. Sustainability Oversight We are committed to creating a cleaner energy future that builds upon our responsibility to provide the safe, reliable and economic energy that improves our customers' lives. The Board oversees management's execution of our sustainability objectives and receives quarterly updates from management regarding sustainability matters. Under the oversight of the Board, we published our 2021 Corporate Sustainability Report in the third quarter of 2022. In addition to announcing significant advancements in our decarbonization journey, the Report announced a goal for our natural gas distribution system to achieve net zero emissions by 2035 and shared our progress towards our goal to reduce electric utility emission intensity 40 percent by 2030 and 70 percent by 2040. Also in the third quarter of 2022, we issued updated Edison Electric Institute and American Gas Association ESG disclosures, Natural Gas Sustainability Initiative (NGSI) disclosures, Sustainability Accounting Standards Board (SASB) disclosures, and new disclosures under the Task Force on Climate Related Financial Disclosure Index. Cyber and Physical Security Oversight Our Board retains oversight of cyber and physical security. Our Chief Information Officer provides the Board quarterly reports that summarize material security risks and the measures that have been put in place to mitigate the associated risks. These reports address a variety of topics including updates on strategic initiatives, industry trends, threat vulnerability assessments, and efforts to prevent, detect and respond to internal and external critical threats. 12 PROXY| PROXY STATEMENTHuman Capital Management Oversight Primary responsibility for oversight of human capital management rests with our Compensation Committee. As part of its oversight, the Committee reviews regular reports from management regarding diversity and inclusion, pay equity, strategic workforce planning, talent retention, employee benefits programs, employee engagement, human rights, and company culture. Succession Planning Oversight Our Board is actively engaged in succession planning for our key executive positions to ensure a strong bench of future leaders. To assist the Board, our CEO and our Senior Vice President - Chief Human Resources Officer perform talent reviews and discuss succession planning and leadership development. Semi-annually, their assessment of senior executive talent, including potential of such talent to succeed our CEO or other executive officers, readiness for succession and development opportunities are presented to our Board. Director Nominees The Governance Committee uses a variety of methods for identifying and evaluating nominees for director. The Governance Committee regularly assesses the appropriate size of the Board and whether any vacancies on the Board are expected due to retirement or otherwise. In the event vacancies are anticipated, or otherwise arise, the Governance Committee considers various potential candidates for director. Board candidates are considered based upon various criteria, including diversity of gender, race and ethnicity; business, administrative and professional skills or experiences; an understanding of relevant industries, technologies and markets; financial literacy; independence status; the ability and willingness to contribute time and special competence to Board activities; personal integrity and independent judgment; and a commitment to enhancing shareholder value. The Governance Committee considers these and other factors as it deems appropriate, given the needs of the Board. Our goal is a diverse, talented, and highly engaged Board, with members whose skills, background and experience are complementary and, together, cover the spectrum of areas that impact our business currently and in the future. The Governance Committee considers candidates for Board membership suggested by a variety of sources, including current or past Board members, the use of third-party executive search firms, members of management, and shareholders. Any shareholder may make recommendations for consideration by the Governance Committee for membership on the Board by sending a written statement of the qualifications of the recommended individual to the Corporate Secretary. The Committee evaluates all director candidates in the same manner using the same criteria regardless of who recommends them. Shareholders who intend to nominate persons for election to the Board must provide timely written notice of the nomination in accordance with Article I, Section 9 of our Bylaws. Generally, our Corporate Secretary must receive the written notice at our executive offices at 7001 Mount Rushmore Road, P.O. Box 1400, Rapid City, South Dakota 57709, not less than 90 days nor more than 120 days prior to the anniversary date of the immediately preceding annual meeting of shareholders. For the 2024 shareholder meeting, those dates are January 26, 2024 and December 27, 2023. The notice must include at a minimum the information set forth in Article I, Section 9 of our Bylaws, including the shareholder’s identity, contingent ownership interests, description of any agreement made with others acting in concert with respect to the nomination, specific information about the nominee and certain representations by the nominee to us. Board Independence In accordance with NYSE rules, the Board through its Governance Committee, affirmatively determines the independence of each director and director nominee in accordance with guidelines it has adopted, which include all elements of independence set forth in the NYSE listing standards. These guidelines are contained in our Policy for Director Independence, which can be found in the "Governance" section of our website (www.blackhillscorp.com/investor-relations/corporate-governance). Based on these standards, the Governance Committee determined that each of the following non-employee directors is independent and has no relationship with us, except as a director and shareholder: Barry M. Granger, Tony A. Jensen, Kathleen S. McAllister, Steven R. Mills, Robert P. Otto, Scott M. Prochazka, Rebecca B. Roberts, Mark A. Schober, and Teresa A. Taylor. In addition, based upon these standards, the Governance Committee determined that Mr. Evans is not independent because he is an officer of the Company. Director Resignation Policies The Corporate Governance Guidelines require members of the Board to submit a letter of resignation for consideration by the Board in certain circumstances. The Corporate Governance Guidelines include a plurality plus voting policy. Pursuant to the policy, any nominee for election as a director in an uncontested election who receives a greater number of votes “Withheld” from his or her election than votes “For” his or her election will promptly tender his or her resignation as a director to the Chairman of the Board following certification of the election results. Broker non-votes will not be deemed to be votes “For” or “Withheld” from a director’s election for purposes of the policy. The Governance Committee (without the participation of the affected director) will consider each resignation tendered under the policy and recommend to the Board whether to accept or reject it. The Board will then take the appropriate action on each tendered resignation, taking into account the Governance Committee’s recommendation. The Governance Committee in making its recommendation, and the Board in making its decision, may consider any factors or other information that it considers appropriate, including the reasons why the 13 PROXYPROXY STATEMENT |Governance Committee believes shareholders “Withheld” votes for election from such director and any other circumstances surrounding the “Withheld” votes, any alternatives for curing the underlying cause of the “Withheld” votes, the qualifications of the tendering director, his or her past and expected future contributions to us and the Board, and the overall composition of the Board, including whether accepting the resignation would cause us to fail to meet any applicable SEC or NYSE requirements. The Board will publicly disclose its decision and rationale by filing a Form 8-K with the SEC within 90 days after receipt of the tendered resignation. The Corporate Governance Guidelines also require members of the Board to tender a letter of resignation in the event of a change in professional responsibilities that may directly or indirectly impact that Board member’s ability to fulfill directorship obligations. The Board is not obligated to accept that resignation. The Governance Committee will review the affected member’s service and qualifications and recommend to the Board the continued appropriateness of Board membership under the circumstances. Codes of Business Conduct and Ethics The Code of Business Conduct and the Code of Ethics that apply to our Chief Executive Officer and Senior Financial Officers can be found in the “Corporate Governance” section of our website (www.blackhillscorp.com/investor-relations/corporate- governance). We intend to disclose any amendments to, or waivers of, the Code of Ethics on our website. Please note that none of the information contained on our website is incorporated by reference in this proxy statement. Certain Relationships and Related Party Transactions We recognize related party transactions can present potential or actual conflicts of interest and create the appearance that decisions are based on considerations other than the best interests of us and our shareholders. Accordingly, as a general matter, it is our preference to avoid related party transactions. Nevertheless, we recognize that there are situations where related party transactions may be in, or may not be inconsistent with, the best interests of us and our shareholders, including but not limited to situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that are not readily available from alternative sources or when we provide products or services to related parties on an arm’s length basis on terms comparable to those provided to unrelated third parties or on terms comparable to those provided to employees generally. Therefore, our Board has adopted a policy for the review of related party transactions. This policy requires directors and officers to promptly report to our Vice President - Governance all proposed or existing transactions in which the Company and they, or persons related to them, are parties or participants. Our Vice President - Governance presents those transactions to our Governance Committee. Our Governance Committee reviews the material facts presented and either approves or disapproves entry into the transaction. In reviewing the transaction, the Governance Committee considers the following factors, among other factors it deems appropriate: (i) whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances; (ii) the extent of the related party’s interest in the transaction; and (iii) the impact on a director’s independence in the event the related party is a director, an immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer. There were no reportable related party transactions in 2022. Communications with the Board We value the views and input of our shareholders and believe that fostering productive dialogue with our shareholders contributes to our long-term success. Shareholders and others interested in communicating directly with the Chairman, with the independent directors as a group, or the Board may do so in writing to the Chairman, Black Hills Corporation, 7001 Mount Rushmore Road, P.O. Box 1400, Rapid City, South Dakota 57709. 14 PROXY| PROXY STATEMENTMEETINGS AND COMMITTEES OF THE BOARD THE BOARD Our Board held nine meetings during 2022. Each regularly scheduled meeting of the Board includes an executive session of only independent directors. We encourage our directors to attend the annual shareholders’ meeting. During 2022, each current director attended at least 75 percent of the combined total of Board meetings and Committee meetings on which the director served. In addition, all directors attended the 2022 annual meeting of shareholders either in person or virtually. COMMITTEES OF THE BOARD Our Board has three standing committees to facilitate and assist the Board in the execution of its responsibilities. Those standing committees are the Audit Committee, the Compensation Committee and the Governance Committee. Each committee operates under a charter, which is available on our website at www.blackhillscorp.com/investor-relations/corporate- governance and is also available in print to any shareholder who requests it. In addition, our Board creates special committees from time to time for specific purposes. Members of the committees are designated by our Board upon recommendation of the Governance Committee. Audit Committee 9 Meetings in 2022 Members: Mark A. Schober (Chair) Barry M. Granger Kathleen S. McAllister Robert P. Otto Independence: 100% Primary Responsibilities  Assist the Board in fulfilling its oversight responsibility to our shareholders relating to the quality and integrity of our accounting, auditing and financial reporting processes;  Oversee the integrity of our financial statements, financial reporting systems of internal controls and disclosure controls regarding finance, accounting and legal compliance;  Review areas of potential significant financial risk to us;  Review consolidated financial statements and disclosures;  Appoint an independent registered public accounting firm for ratification by our shareholders;  Monitor the independence and performance of our independent registered public accountants and internal auditing department;  Pre-approve all audit and non-audit services provided by our independent registered public accountants;  Review the scope and results of the annual audit, including reports and recommendations of our independent registered public accountants;  Review the internal audit plan results of internal audit work and our process for monitoring compliance with our Code of Business Conduct and other policies and practices established to ensure compliance with legal and regulatory requirements; and  Periodically meet, in private sessions, with our VP - Internal Audit, Chief Financial Officer, Chief Compliance Officer, other management, and our independent registered public accounting firm. Committee Report: Page 23 of this Proxy Statement In accordance with the rules of the NYSE, all of the members of the Audit Committee are financially literate. In addition, the Board determined that Ms. McAllister and Mr. Schober have the requisite attributes of an “audit committee financial expert” as provided in regulations promulgated by the SEC, and that such attributes were acquired through relevant education and/or experience. 15 PROXYPROXY STATEMENT |Compensation Committee 5 Meetings in 2022 Members: Teresa A. Taylor (Chair) Tony A. Jensen Scott M. Prochazka Rebecca B. Roberts Independence: 100% Committee Report: Page 36 of this Proxy Statement Primary Responsibilities  Discharge the Board's responsibilities related to executive and director compensation philosophy, policies and programs;  Perform functions required of directors in the administration of all federal and state laws and regulations pertaining to executive employment and compensation;  Consider and recommend for approval by the Board all executive compensation programs including executive benefit programs and stock ownership plans;  Promote an executive compensation program that supports the overall objective of enhancing shareholder value; and  Provide oversight of Company culture, diversity and inclusion, human rights, pay equity, and employee engagement. The Compensation Committee has authority under its charter to retain compensation consultants and other advisors as the Committee may deem appropriate in its sole discretion. The Committee engaged Meridian Compensation Partners, LLC (Meridian), an independent consulting firm, to conduct an annual review of our 2022 total compensation program for executive officers. The Committee reviewed the independence of Meridian and the individual representatives of Meridian who served as consultants to the Committee, in accordance with the SEC and NYSE requirements. The Compensation Committee concluded that Meridian was independent and Meridian’s performance of services raised no conflict of interest. The Committee’s conclusions were based in part on a report that Meridian provided to the Committee intended to reveal any potential conflicts of interest and a schedule of the type and amount of non-executive compensation services provided by Meridian to the Company. During 2022, the cost of these non-executive compensation services was less than $25,000. Compensation Committee Interlocks. None of our executive officers serve as a member of a board of directors or compensation committee of any entity that has one or more executive officers who serve on our Board or on our Compensation Committee. Governance Committee 3 Meetings in 2022  Assess the size of the Board and qualifications for Board membership;  Identify and recommend prospective directors to the Board to fill vacancies; Primary Responsibilities Members: Rebecca B. Roberts (Chair) Steven R. Mills Teresa A. Taylor Mark A. Schober  Review and evaluate director nominations submitted by shareholders, including reviewing the qualifications and independence of shareholder nominees;  Consider and recommend existing Board members to be renominated at our annual meeting of shareholders;  Consider the resignation of an incumbent director who makes a principal occupation change (including retirement) or who receives a greater number of votes "Withheld" than votes "For" in an uncontested election of directors and recommend to the Board whether to accept or reject the resignation;  Establish and review guidelines for corporate governance;  Recommend to the Board for approval committee membership and chairs of the committees; Independence: 100%  Recommend to the Board for approval a Chairman or an independent director to serve as a Lead Director;  Review the independence of each director and director nominee;  Administer an annual evaluation of the performance of the Board and each Committee and a biennial evaluation of each individual director;  Ensure that the Board oversees the evaluation and succession planning of management;  Oversee the reporting framework the Company utilizes to track and monitor progress associated with ESG activities; and  Oversee company political engagement. 16 PROXY| PROXY STATEMENTDIRECTOR COMPENSATION DIRECTOR FEES Compensation to our non-employee directors consists of cash retainers for Board members, Committee members, the Board Chairman and Committee Chairs. Prior to January 1, 2022, the Board members received their equity compensation in the form of common stock equivalents that are deferred until after they leave the Board. Effective January 1, 2022, the Board adopted a new Non-Employee Director Equity Compensation Plan that provides equity compensation to our Board members in the form of restricted stock units and changed the date of the annual equity grant to May to better align with the timing of director elections. For the period of January 1, 2022 through April 30, 2022, the Board members received a pro rata amount of equity compensation in the form of restricted stock units. On May 1, 2022, Board members received an annual equity award of restricted stock units that will vest at the 2023 annual meeting. Dividend equivalents accrue on the common stock equivalents and restricted stock units. We do not pay meeting fees. In setting non-employee director compensation, the Compensation Committee recommends the form and amount of compensation to the Board, which makes the final determination. In considering and recommending the compensation of non- employee directors, the Compensation Committee considers such factors as it deems appropriate, including historical compensation information, level of compensation necessary to attract and retain non-employee directors meeting our desired qualifications and market data. In the review of director compensation in 2022, Meridian completed a market compensation review of our peer companies' director fees. Based on this review, the cash retainer and equity pay were increased effective May 1, 2022, to more closely align with the median director compensation for our peer utility companies. The fee structure for director fees in 2022 is as follows: Board Retainer Board Chairman Committee Chair Retainer Audit Committee Compensation Committee Governance Committee Committee Member Retainer Audit Committee Compensation Committee Governance Committee Fees Effective January 1, 2022 Fees Effective May 1, 2022 Restricted Stock Units 120,000 $ Restricted Stock Units 105,000 $ Cash 85,000 100,000 15,000 12,500 10,000 10,000 7,500 7,500 $ $ $ $ $ $ $ $ Cash 95,000 100,000 15,000 12,500 10,000 10,000 7,500 7,500 $ $ $ $ $ $ $ $ The Committee did not recommend a change to director compensation for 2023. 17 PROXYPROXY STATEMENT |DIRECTOR COMPENSATION FOR 2022 AND COMMON STOCK EQUIVALENTS OUTSTANDING AS OF DECEMBER 31, 2022(1) Name(2) Barry M. Granger Tony A. Jensen Kathleen A. McAllister Steven R. Mills Robert P. Otto Scott M. Prochazka Rebecca B. Roberts Mark A. Schober Teresa A. Taylor John B. Vering(5) Fees Earned or Paid in Cash $101,667 $99,167 $101,667 $199,167 $101,667 $99,167 $116,667 $121,667 $119,167 $34,167 Stock Awards(3) $146,250 $146,250 $146,250 $146,250 $146,250 $146,250 $146,250 $146,250 $146,250 $26,250 Total $247,917 $245,417 $247,917 $345,417 $247,917 $245,417 $262,917 $267,917 $265,417 $60,417 Number of Common Stock Equivalents Outstanding at December 31, 2022(4) 4,410 12,392 10,780 39,515 13,710 4,410 26,904 18,375 13,548 — (1) Our directors did not receive any stock option awards, non-equity incentive plan compensation, pension benefits or perquisites in 2022 and did not have any stock options outstanding at December 31, 2022. (2) Mr. Evans, our President and CEO, is not included in this table because he is our employee and thus receives no compensation for his services as director. Mr. Evans’ compensation received as an employee is shown in the Summary Compensation Table for our Named Executive Officers. (3) Each non-employee director received a pro-rata amount of the annual equity compensation at the beginning of 2022 in the form of restricted stock units for the period of January 1, 2022 through April 30, 2022. Effective May 1, 2022, each non-employee director received an annual equity award of restricted stock units equivalent to $120,000 that will vest at our 2023 annual meeting. The grant date fair value of a restricted stock unit is the closing price of a share of our common stock on the grant date. (4) The common stock equivalents are fully vested in that they are not subject to forfeiture; however, the shares are not issued until after the director ends his or her service on the Board. The common stock equivalents are payable in stock or cash or can be deferred further at the election of the director. (5) Mr. Vering's retirement from our Board was effective at our 2022 Annual Meeting. DIRECTOR STOCK OWNERSHIP GUIDELINES Each member of our Board is required to hold shares of common stock, common stock equivalents, or restricted stock units equal to five times the annual cash Board retainer. Currently, all of our directors have met the stock ownership guideline except for Messrs. Granger and Prochazka, who have been on the Board for less than three years. 18 PROXY| PROXY STATEMENTSECURITY OWNERSHIP OF MANAGEMENT AND PRINCIPAL SHAREHOLDERS The following table sets forth the beneficial ownership of our common stock as of February 24, 2023 for each director, each executive officer named in the Summary Compensation Table, all of our directors and executive officers as a group and each person known by us to beneficially own more than five percent of our outstanding shares of common stock. Beneficial ownership includes shares a director or executive officer has or shares the power to vote or transfer. There were no stock options outstanding for any of our directors or executive officers as of February 24, 2023. Except as otherwise indicated by footnote below, we believe that each individual named has sole investment and voting power with respect to the shares of common stock indicated as beneficially owned by that individual. Name of Beneficial Owner (1) Outside Directors Barry M. Granger Tony A. Jensen Kathleen S. McAllister Steven R. Mills Robert P. Otto Scott M. Prochazka Rebecca B. Roberts Mark A. Schober Teresa A. Taylor Named Executive Officers Linden R. Evans Brian G. Iverson Erik D. Keller Richard W. Kinzley Jennifer C. Landis All directors and executive officers as a group (14 persons) * Represents less than one percent of the common stock outstanding. Shares of Common Stock Beneficially Owned (2) Directors Common Stock Equivalents (3) Total Percentage 2,382 8,700 7,089 20,318 5,230 2,382 6,546 7,499 4,529 141,373 39,704 8,083 51,828 20,237 325,899 2,028 3,692 3,692 19,197 8,480 2,028 20,358 10,877 9,019 - - - - - 79,371 4,410 12,392 10,781 39,515 13,710 4,410 26,904 18,375 13,548 141,373 39,704 8,083 51,828 20,237 405,270 * * * * * * * * * * * * * * * (1) Beneficial ownership means the sole or shared power to vote, or to direct the voting of, a security or investment power with respect to a (2) security. Includes restricted stock held by the following executive officers for which they have voting power but not investment power: Mr. Evans - 26,546 shares; Mr. Iverson - 6,288 shares; Mr. Keller - 6,688 shares; Mr. Kinzley - 4,230; Ms. Landis - 3,433 shares and all directors and executive officers as a group 62,288 shares. Includes 1,678 restricted stock units held by each director. (3) Represents common stock equivalents allocated to the directors’ accounts prior to January 1, 2022 under our former directors’ stock- based compensation plan, of which there are no voting rights. 19 PROXYPROXY STATEMENT |PRINCIPAL SHAREHOLDERS Set forth in the table below is information about the number of shares held by persons we know to be the beneficial owners of more than 5% of the issued and outstanding Common Stock: Name and Address BlackRock, Inc.(1) 55 East 52nd Street New York, NY 10055 State Street Corporation(2) State Street Financial Center One Lincoln Street Boston, MA 02111 The Vanguard Group Inc.(3) 100 Vanguard Blvd. Malvern, PA 19355 Shares of Common Stock Beneficially Owned Percentage 10,877,391 16.7% 7,517,054 11.6% 6,969,311 10.9% (1) (2) (3) Information is as of December 31, 2022, and is based on a Schedule 13G/A filed on January 26, 2023. BlackRock, Inc. has sole voting power with respect to 10,652,532 shares and sole investment power with respect to 10,877,391 shares. Information is as of December 31, 2022, and is based on a Schedule 13G filed on February 9, 2023. State Street Corporation has shared voting power with respect to 7,172,710 shares and shared investment power with respect to 7,517,054 shares. Information is as of December 31, 2022, and is based on a Schedule 13G/A filed on February 9, 2023. The Vanguard Group Inc. has shared voting power with respect to 76,566 shares and sole investment power with respect to 6,969,311 shares. 20 PROXY| PROXY STATEMENT21 PROPOSAL 2 RATIFICATION OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLICACCOUNTING FIRMThe firm of Deloitte & Touche LLP, independent registered public accountants, conducted the audit of Black Hills Corporation and its subsidiaries for 2022. Representatives of Deloitte & Touche LLP will be present at our annual meeting and will have the opportunity to make a statement, if they desire to do so, and to respond to appropriate questions.Our Audit Committee has appointed Deloitte & Touche LLP to perform an audit of our consolidated financial statements and those of our subsidiaries for 2023 and to render their reports. In determining whether to recommend to the full Board the reappointment of Deloitte & Touche LLP as our independent auditor, the Audit Committee considered the following:•Technical expertise and knowledge of the Company’s business and industry•The quality and candor of communications with the Audit Committee•Deloitte & Touche LLP’s independence•Public Company Accounting Oversight Board inspection reports on the firm•Input from management on Deloitte & Touche LLP’s performance, objectivity and professional judgment•The appropriateness of fees for audit and non-audit servicesThe Board recommends ratification of the Audit Committee’s appointment of Deloitte & Touche LLP. The appointment of Deloitte & Touche LLP as our independent registered public accounting firm for 2023 will be ratified if the votes cast “For” exceed the votes cast “Against.” Abstentions will have no effect on such vote. If shareholder approval for the appointment of Deloitte & Touche LLP is not obtained, the Audit Committee will reconsider the appointment.The Board recommends a vote FOR ratification of the appointment of Deloitte & Touche LLPto serve as our independent registered public accounting firm for 2023.PROXYPROXY STATEMENT |FEES PAID TO THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The following charts set forth the aggregate fees for services provided to us for the years ended December 31, 2022 and 2021 by our independent registered public accounting firm, Deloitte & Touche, the member firms of Deloitte & Touche and their respective affiliates: Audit Fees Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements included in quarterly reports, opinions on the effectiveness of our internal control over financial reporting, and services that generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and assistance with and review of documents filed with the SEC. Audit-Related Fees Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial statements and are not reported under “Audit Fees.” These services include employee benefit plan audits. Tax Compliance Fees Fees for services related to federal and state tax compliance. Tax Planning and Advisory Fees Fees for planning and advisory services. The services performed by D&T were pre-approved in accordance with the Audit Committee’s pre-approval policy whereby the Audit Committee pre-approves all audit and permissible non-audit services provided by the independent registered public accountants. The Audit Committee will generally pre-approve a list of specific services and categories of services, including audit, audit-related, tax and other services, for the upcoming or current year, subject to a specified cost level. Any service that is not included in the approved list of services must be separately pre-approved by the Audit Committee. 22 PROXY| PROXY STATEMENTAUDIT COMMITTEE REPORT The Audit Committee assists the Board in fulfilling its oversight responsibilities to shareholders relating to the integrity of the Company’s financial statements, the Company’s compliance with legal and regulatory requirements regarding financial reporting, the independent auditors’ qualifications and independence, and the performance of the Company’s internal and independent auditors. Management has the primary responsibility for the completeness and accuracy of the Company’s financial statements and disclosures, the financial reporting process, and the effectiveness of the Company’s internal control over financial reporting. Our independent auditors, Deloitte & Touche LLP, are responsible for auditing the Company’s consolidated financial statements and expressing an opinion as to whether they are presented fairly, in all material respects, in conformity with accounting principles generally accepted in the United States. In fulfilling its oversight responsibilities for 2022, the Audit Committee, among other things: • • • • • • • • • • • Reviewed and discussed the audited financial information contained in the Annual Report on Form 10-K with management and our independent auditors prior to public release. Reviewed and discussed with our independent auditors their judgments as to the quality, not just the acceptability, of our critical accounting principles and estimates and all other communications required to be discussed with the Audit Committee under generally accepted auditing standards, including the matters required to be discussed by the applicable requirements of the Public Company Accounting Oversight Board and the SEC. Reviewed and discussed with management, our internal auditors and our independent auditors management’s report on internal control over financial reporting, including the significance and status of control deficiencies identified by management and the results of remediation efforts undertaken, to determine the effectiveness of internal control over financial reporting at December 31, 2022. Reviewed with our independent auditors their report on the Company’s internal control over financial reporting at December 31, 2022, including the basis for their conclusions. Reviewed and pre-approved all audit and non-audit services and fees provided to the Company by our independent auditors and considered whether the provision of such non-audit services by our independent auditors is compatible with maintaining their independence. Discussed with our internal and independent auditors their audit plans, audit scope and identification of audit risks and reviewed the results of internal audit examinations. Reviewed and discussed the interim financial information contained in each quarterly earnings announcement and Quarterly Report on Form 10-Q with management and our independent auditors prior to public release. Received and reviewed periodic corporate compliance and financial risk reports, including credit and hedging activity. Held private sessions with our independent auditors, Vice President - Internal Audit, Chief Financial Officer and Controller, and Chief Compliance Officer. Received the written disclosures and the letter from our independent auditors required by the applicable requirements of the Public Company Accounting Oversight Board regarding the independent auditors’ communications with the Committee concerning independence and discussed the independence of Deloitte & Touche LLP with them. Concluded Deloitte & Touche LLP is independent based upon the above considerations. Based upon the reviews and discussions referred to above, the Audit Committee recommended to the Board that our audited consolidated financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC. The Audit Committee also recommended and the Board reappointed Deloitte & Touche LLP as our independent registered public accounting firm for 2023. Shareholders are being asked to ratify that selection at the 2023 Annual Meeting. THE AUDIT COMMITTEE Mark A. Schober, Chair Barry M. Granger Kathleen S. McAllister Robert P. Otto 23 PROXYPROXY STATEMENT | PROPOSAL 3 ADVISORY VOTE ON OUR EXECUTIVE COMPENSATION We are providing shareholders with an annual advisory, non-binding vote on the executive compensation of our Named Executive Officers (commonly referred to as “say on pay”). Accordingly, shareholders will vote on approval of the following resolution: RESOLVED, that the shareholders approve, on an advisory basis, the compensation of our Named Executive Officers as disclosed in the Compensation Discussion and Analysis section, the accompanying compensation tables and the related narrative disclosure in this proxy statement. This vote is non-binding. The Board and the Compensation Committee expect to consider the outcome of the vote when considering future executive compensation decisions to the extent they can determine the cause or causes of any significant negative voting results. At our 2022 annual meeting, shareholders owning 95 percent of the shares that were voted in this matter approved our executive compensation. As described at length in the Compensation Discussion and Analysis section of this proxy statement, we believe our executive compensation program is reasonable, competitive and strongly focused on pay for performance. The compensation of our Named Executive Officers varies depending upon the achievement of pre-established performance goals, both individual and corporate. Our short-term incentive is tied to earnings per share, safety performance targets, and diversity training participation targets that reward our executives when they deliver targeted results. Our long-term incentive performance shares or units vest based upon the level of achievement of certain pre-established performance goals over a three-year performance period as described in the Compensation Discussion and Analysis. Through stock ownership guidelines, equity incentives and clawback provisions, we align the interests of our executives with those of our shareholders and our long-term interests. Our executive compensation policies have enabled us to attract and retain talented and experienced senior executives who can drive financial and strategic growth objectives that are intended to enhance shareholder value. We believe that the 2022 compensation of our Named Executive Officers was appropriate and aligned with our 2022 results and positions us for long- term growth. Shareholders are encouraged to read the Compensation Discussion and Analysis, the accompanying compensation tables, and the related narrative disclosures to better understand the compensation of our Named Executive Officers. The advisory resolution to approve executive compensation is non-binding. However, our Board will consider shareholders to have approved our executive compensation if the number of votes cast “For” the proposal exceeds the number of votes cast “Against” the proposal. Abstentions and broker non-votes will have no effect on such vote. The Board recommends a vote FOR the advisory vote on executive compensation. 24 PROXY| PROXY STATEMENT25 EXECUTIVE COMPENSATIONCOMPENSATION DISCUSSION AND ANALYSISINTRODUCTIONThis Compensation Discussion and Analysis describes our overall executive compensation policies and practices and specifically explains the compensation-related actions taken with respect to 2022 compensation for our Named Executive Officers included in the Summary Compensation Table. The Compensation Committee of the Board (the "Committee" for purposes of this Compensation Discussion and Analysis), is composed entirely of independent directors and is responsible for approving and overseeing our executive compensation philosophy, policies and programs.Our Named Executive Officers, based on 2022 positions and compensation levels, are:Named Executive OfficersTitleReferenceLinden R. EvansPresident and Chief Executive OfficerEvans, CEORichard W. KinzleySr. Vice President and Chief Financial OfficerKinzley, CFOBrian G. IversonSr. Vice President, General Counsel and Chief Compliance OfficerIverson, GCErik D. KellerSr. Vice President - Chief Information OfficerKeller, CIOJennifer C. LandisSr. Vice President - Chief Human Resources OfficerLandis, CHROKEY EXECUTIVE COMPENSATION OBJECTIVES Overall, our goal is to target total direct compensation (the sum of base salary, short-term incentive at target and long-term incentive at target) to be around the median of the appropriate market. Our executive compensation is designed to maintain an appropriate and competitive balance between fixed and variable compensation components including short-and long-term compensation, and cash and stock-based compensation. We believe that the performance basis for determining compensation should differ by each reward component – base salary, short-term incentive and long-term incentive. Incentive measures (short-term and long-term) should emphasize objective, quantitative operating measures. The performance measures for our incentive compensation plans are discussed below.BEST PRACTICES IN EXECUTIVE COMPENSATIONOur executive compensation program reflects the following best practices, which ensure effective compensation governance and align the interests of our shareholders and executives.What we do:What we do not do:A significant portion of executive pay is at risk by granting incentive awards that are based on continuing annual and long-term metrics tied to performance.XNo employment agreements with executives.Short-Term incentive plan awards are capped at 200% of target number of shares granted.XNo change in control cash severance payments that exceed three times base salary and target bonus.Long-Term incentive plan awards are capped at 200% of target.XNo excise tax gross-ups for executives.Beginning with 2023 grants, non-vested equity awards are not accelerated after a change in control unless the executive is: (1) terminated without cause or good reason; or (2) the award is not assumed or substituted by the successor company XNo hedging or pledging of Company stock.Executives and directors are subject to stock ownership guidelines and retentional requirements.XNo excessive perquisites for executives.PROXYPROXY STATEMENT |26 2022 COMPENSATION PRACTICE CHANGESOur corporate financial, safety and diversity goals are used as measures to determine awards under our variable pay programs. The Compensation Committee engaged Meridian Compensation Partners, LLC (Meridian) to review our executive compensation plans and practices. Based on this review and recommendations from Meridian, the Compensation Committee made the following changes to our executive compensation practices for 2022:Prior Executive Compensation PracticeRevised Executive Compensation PracticeRationale for ChangeShort-Term IncentiveFour performance measures including:70% EPS from ongoing operations, as adjusted10% Total Case Incident Rate (TCIR)10% Preventable Motor Vehicle Incident (PMVI)10% Employee Safety & Wellness EngagementFive performance measures including:70% EPS from ongoing operations, as adjusted7.5% System Average Interruption Duration Index (SAIDI)7.5% Hits Per Thousand (HPT)7.5% Total Case Incident Rate (TCIR)7.5% Diversity TrainingA diversity metric was added to demonstrate our commitment to building a diverse and well-rounded employee team. The addition of the diversity goal resulted in a change to the weight of all non-financial goals.HPT was added to measure our progress in reducing stray emissions and improving pipeline safety through a reduction in the number of gas line hits.SAIDI was added as a measure of the reliability of our electric delivery to customers.Long-Term Incentive50% Performance Share Units and 50% Restricted Stock Awards60% Performance Share Awards and 40% Restricted Stock AwardsA higher performance based percentage of the long-term incentive drives long-term focus/behaviors/actions on the performance measures.*Beginning with our 2021-2023 Performance Share PlanSETTING EXECUTIVE COMPENSATIONBased upon our compensation philosophy, the Committee structures executive compensation to motivate our executives to achieve specified business goals and to reward them for achieving such goals. The key steps the Committee follows in setting executive compensation are to:Analyze executive compensation market data to ensure market competitivenessReview the components of executive compensation, including base salary, short-term incentive, long-term incentive, retirement, and other benefitsReview total compensation and structureReview executive officer performance, responsibilities, experience, and other factors cited above to determine individual compensation levelsPROXY| PROXY STATEMENTEXECUTIVE COMPENSATION PROGRAM DESIGN OBJECTIVES Attract, retain, motivate, and encourage the development of highly qualified executives Provide competitive compensation Promote the relationship between pay and performance Promote corporate performance that is linked to our shareholders’ interests Recognize and reward individual performance Market Compensation Analysis The market for our executive talent is national in scope and is not focused on any one geographic location, area or region of the country. As such, our executive compensation should be competitive with the national market for executives. It should also reflect the executive’s responsibilities and duties and align with the compensation of executives at companies or business units of comparable size and complexity. The Committee gathers market information for our executives from the electric and gas utility industry and general industry. The Committee selects and retains the services of an independent consulting firm to periodically:  Provide information regarding practices and trends in compensation programs  Review and evaluate our compensation program as compared to compensation practices of other companies with similar characteristics, including size, complexity, and type of business  Review and assist with the establishment of a peer group of companies  Provide a compensation analysis of the executive positions The Committee used the services of Meridian to evaluate 2022 compensation. It gathered data from nationally recognized survey providers, as well as specific peer companies through public filings, which included: i. ii. Willis Towers Watson’s Compensation Data Bank (energy services and general industry); and 20 peer companies representing the utility and energy industry. The 20 peer companies ranged in annual revenue size from approximately $567 million to $7.3 billion, with the median at $2.2 billion. The Company’s 2022 revenue was $2.6 billion. The survey data was adjusted for our relative revenue size using regression analysis. Our compensation peer companies included in the analysis for 2022 compensation decisions were: ALLETE Inc. Alliant Energy Corporation Ameren Corporation Atmos Energy Corp. IDACORP Inc. MGE Energy Inc. ONE Gas, Inc. Pinnacle West Capital Corp. New Jersey Resources Corp. PNM Resources, Inc. NiSource, Inc. Portland General Electric Co. Avista Corp. Northwest Natural Holding Co. South Jersey Industries, Inc. CMS Energy Corp. Hawaiian Electric Ind., Inc. NorthWestern Corp. OGE Energy Corp. Spire, Inc. Meridian validated that the above Compensation Peer Group remains credible, includes size-appropriate peers, and reflects the Company's industry, complexity and market for executive talent. The salary surveys are one of several factors the Committee uses in setting appropriate compensation levels. Other factors include Company performance, individual performance and experience, the level and nature of the executive’s responsibilities, internal equity considerations and discussions with the CEO related to the other senior executive officers' performance and contributions. 27 PROXYPROXY STATEMENT |Components of Executive Compensation The primary components of our executive compensation program consist of a base salary, a short-term incentive plan, and long-term incentives. In addition, we provide retirement and other benefits. The Committee reviews all components of each executive officer's compensation, including salary, short-term incentive, equity and other long-term incentive compensation values granted, and the current and potential value of the executive officer's total Black Hills Corporation equity holdings. The majority of the executives’ total compensation is granted as incentive compensation. Incentive compensation is intended to motivate and encourage our executives to drive performance and achieve superior results for our shareholders and align realized pay with stock performance. The Committee periodically reviews information provided by its compensation consultant to inform its determination of the appropriate level and mix of total compensation. The Committee believes that a significant portion of total target compensation should be comprised of variable compensation. In order to reward long-term growth while still encouraging focus on short-term results, the Committee establishes incentive targets that emphasize long-term compensation at a greater level than short-term compensation. Base Salary. Base salaries for all executives are reviewed annually. The base salary of our executives is also adjusted at the time of a promotion or material change in job responsibility, as appropriate. Evaluation of 2022 base salary adjustments occurred in January 2022. The base salary component of each position was compared to the median of the market data provided by the compensation consultant. The actual base salary of each officer was determined by the executive’s performance, the experience level of the officer, the current position in a market-based salary range, and internal pay relationships. Evans, CEO Kinzley, CFO Iverson, GC Keller, CIO Landis, CHRO Base Salary 2021 2022 825,000 $ 454,000 $ 400,000 $ 340,000 $ 316,000 $ 860,000 472,000 416,000 354,000 348,000 $ $ $ $ $ Short-Term Incentive. Our Short-Term Incentive Plan is designed to recognize and reward the contributions of individual executives as well as the contributions that group performance makes to overall corporate success. The 2022 short-term incentive was based on the following metrics: 2022 Short-Term Incentive Metrics Rationale EPS As-adjusted is a prevalent growth metric that aligns with shareholder interests and is well understood by the executive team. TCIR measures occupational health and safety performance over a period of time and reinforces BHC's commitment to sending our workforce home safely every day. SAIDI measures average annual outage time of our electric utility segment and demonstrates our commitment to providing safe, reliable electricity to our customers. HPT provides a customer-focused metric for our gas utilities and is measured by gas line hits per 1,000 line locates performed. HPT is aligned with our system safety efforts and supports our environmental goals and climate strategy of achieving net-zero natural gas emissions by 2035. Diversity training contributes to our culture of inclusion through education, awareness, and fostering meaningful connections. Metric Weighting 70% Definition GAAP earnings per share adjusted for unique one-time non- budgeted events (similar to those items adjusted for when reporting non-GAAP earnings for external purposes), including external acquisition costs, impairments, transaction financing costs, unique tax transactions, and other items the Committee deems not reflective of ongoing operations and the value created for shareholders 7.5% Injuries per 200,000 hours worked 7.5% System average interruption duration index 7.5% Hits per thousand EPS from ongoing operations, as adjusted Total Case Incident Rate (TCIR) Electric Reliability (SAIDI) Gas Distribution Damage Prevention (HPT) Diversity Training Participation 7.5% 95% manager level and above completion of worldview training and 100% senior management team participation in a reverse mentorship program or Employee Resource Group sponsorship 28 EPS from ongoing operations, as adjusted Total Case Incident Rate (TCIR) Electric Reliability (SAIDI) Gas Distribution Damage (HPT) Diversity Training Participation Payout percentage of target for each metric 2022 Short-Term Incentive Goals Incentive Threshold Maximum $3.77 1.25 74.40 2.16 50% Goals Target $4.05 1.00 65.80 2.05 100% $4.33 0.85 54.20 1.94 200% The Committee believes that these performance measures meet the objectives of the plan, including:  Align the interests of the plan participants and the shareholders  Motivate employees to strive to achieve superior operating results  Provide an incentive reflective of core operating performance  Ensure “buy-in” from participants with easily understood metrics  Meet the performance objectives of the plan to achieve over time an average payout equal to market competitive levels The short-term incentive, after applicable tax withholding, is distributed to the officer in the form of cash. Target award levels are established as a percentage of each participant’s base salary. A target award is typically set around the benchmark 50th percentile short-term incentive target award for comparable positions. The actual payout, if any, will vary, based on attainment of pre-established performance goals, between 0 and 200 percent of the individual executive’s short-term incentive target award level. The Committee approves the target level for each officer in January, which applies to performance in the upcoming plan year. Target levels are derived in part from market data provided by the compensation consultant and in part by the Committee’s judgment regarding internal equity, retention and an individual executive’s expected contribution to the achievement of our strategic objectives. The target levels for our Named Executive Officers are shown below: Evans, CEO Kinzley, CFO Iverson, GC Keller, CIO Landis, CHRO Short-Term Incentive Target 2021 % of Base Salary $ Amount 100% $ 70% $ 60% $ 50% $ 50% $ 825,000 317,800 240,000 170,000 158,000 2022 % of Base Salary $ Amount 100% $ 70% $ 60% $ 50% $ 60% $ 860,000 330,400 249,600 177,000 208,800 The threshold, target and maximum payout levels for our Named Executive Officers under the 2022 Short-Term Incentive Plan are shown in the Grants of Plan-Based Awards in 2022 table on page 38, under the heading “Estimated Future Payouts Under Non-Equity Incentive Plan Awards.” Early in the first quarter, the Committee evaluates actual performance in relation to the prior year’s targets and approves the actual payment of awards related to the prior plan year. The Committee reserves the discretion to adjust any award, and will review and take into account individual performance, level of contribution, and the accomplishment of specific project goals that were initiated throughout the plan year. The Committee also reserves discretion with respect to any payout related to safety goals if we experience an employee or contractor fatality during the plan period. Discretion was not exercised to adjust awards for 2022. PROXY| PROXY STATEMENTComponents of Executive Compensation The primary components of our executive compensation program consist of a base salary, a short-term incentive plan, and long-term incentives. In addition, we provide retirement and other benefits. The Committee reviews all components of each executive officer's compensation, including salary, short-term incentive, equity and other long-term incentive compensation values granted, and the current and potential value of the executive officer's total Black Hills Corporation equity holdings. The majority of the executives’ total compensation is granted as incentive compensation. Incentive compensation is intended to motivate and encourage our executives to drive performance and achieve superior results for our shareholders and align realized pay with stock performance. The Committee periodically reviews information provided by its compensation consultant to inform its determination of the appropriate level and mix of total compensation. The Committee believes that a significant portion of total target compensation should be comprised of variable compensation. In order to reward long-term growth while still encouraging focus on short-term results, the Committee establishes incentive targets that emphasize long-term compensation at a greater level than short-term compensation. Base Salary. Base salaries for all executives are reviewed annually. The base salary of our executives is also adjusted at the time of a promotion or material change in job responsibility, as appropriate. Evaluation of 2022 base salary adjustments occurred in January 2022. The base salary component of each position was compared to the median of the market data provided by the compensation consultant. The actual base salary of each officer was determined by the executive’s performance, the experience level of the officer, the current position in a market-based salary range, and internal pay relationships. Evans, CEO Kinzley, CFO Iverson, GC Keller, CIO Landis, CHRO Base Salary 2021 2022 825,000 $ 454,000 $ 400,000 $ 340,000 $ 316,000 $ 860,000 472,000 416,000 354,000 348,000 $ $ $ $ $ Short-Term Incentive. Our Short-Term Incentive Plan is designed to recognize and reward the contributions of individual executives as well as the contributions that group performance makes to overall corporate success. The 2022 short-term incentive was based on the following metrics: 2022 Short-Term Incentive Metrics Metric Weighting Definition Rationale GAAP earnings per share adjusted for unique one-time non- budgeted events (similar to those items adjusted for when reporting non-GAAP earnings for external purposes), EPS As-adjusted is a prevalent growth metric that aligns with 70% including external acquisition costs, impairments, transaction shareholder interests and is well understood by the executive financing costs, unique tax transactions, and other items the team. Committee deems not reflective of ongoing operations and the value created for shareholders EPS from ongoing operations, as adjusted Total Case Incident Rate (TCIR) Electric Reliability (SAIDI) Gas Distribution Damage Prevention (HPT) 7.5% Injuries per 200,000 hours worked 7.5% System average interruption duration index 7.5% Hits per thousand TCIR measures occupational health and safety performance over a period of time and reinforces BHC's commitment to sending our workforce home safely every day. SAIDI measures average annual outage time of our electric utility segment and demonstrates our commitment to providing safe, reliable electricity to our customers. HPT provides a customer-focused metric for our gas utilities and is measured by gas line hits per 1,000 line locates performed. HPT is aligned with our system safety efforts and supports our environmental goals and climate strategy of achieving net-zero natural gas emissions by 2035. Diversity training contributes to our culture of inclusion through education, awareness, and fostering meaningful connections. Diversity Training Participation 7.5% 95% manager level and above completion of worldview training and 100% senior management team participation in a reverse mentorship program or Employee Resource Group sponsorship Incentive EPS from ongoing operations, as adjusted Total Case Incident Rate (TCIR) Electric Reliability (SAIDI) Gas Distribution Damage (HPT) Diversity Training Participation Payout percentage of target for each metric 2022 Short-Term Incentive Goals Threshold $3.77 1.25 74.40 2.16 50% Goals Target $4.05 1.00 65.80 2.05 100% Maximum $4.33 0.85 54.20 1.94 200% The Committee believes that these performance measures meet the objectives of the plan, including:  Align the interests of the plan participants and the shareholders  Motivate employees to strive to achieve superior operating results  Provide an incentive reflective of core operating performance  Ensure “buy-in” from participants with easily understood metrics  Meet the performance objectives of the plan to achieve over time an average payout equal to market competitive levels The short-term incentive, after applicable tax withholding, is distributed to the officer in the form of cash. Target award levels are established as a percentage of each participant’s base salary. A target award is typically set around the benchmark 50th percentile short-term incentive target award for comparable positions. The actual payout, if any, will vary, based on attainment of pre-established performance goals, between 0 and 200 percent of the individual executive’s short-term incentive target award level. The Committee approves the target level for each officer in January, which applies to performance in the upcoming plan year. Target levels are derived in part from market data provided by the compensation consultant and in part by the Committee’s judgment regarding internal equity, retention and an individual executive’s expected contribution to the achievement of our strategic objectives. The target levels for our Named Executive Officers are shown below: Evans, CEO Kinzley, CFO Iverson, GC Keller, CIO Landis, CHRO Short-Term Incentive Target 2021 2022 % of Base Salary $ Amount % of Base Salary $ Amount 100% $ 70% $ 60% $ 50% $ 50% $ 825,000 317,800 240,000 170,000 158,000 100% $ 70% $ 60% $ 50% $ 60% $ 860,000 330,400 249,600 177,000 208,800 The threshold, target and maximum payout levels for our Named Executive Officers under the 2022 Short-Term Incentive Plan are shown in the Grants of Plan-Based Awards in 2022 table on page 38, under the heading “Estimated Future Payouts Under Non-Equity Incentive Plan Awards.” Early in the first quarter, the Committee evaluates actual performance in relation to the prior year’s targets and approves the actual payment of awards related to the prior plan year. The Committee reserves the discretion to adjust any award, and will review and take into account individual performance, level of contribution, and the accomplishment of specific project goals that were initiated throughout the plan year. The Committee also reserves discretion with respect to any payout related to safety goals if we experience an employee or contractor fatality during the plan period. Discretion was not exercised to adjust awards for 2022. 29 PROXYPROXY STATEMENT |30 On January 24, 2023, the Committee approved a payout of 71.48% percent of target under the 2022 Short-Term Incentive Plan. The incentive plan payout was based on attainment of the following: Incentive2022 ResultsGoal Payout% of AwardPayoutEPS from ongoing operations, as adjusted$3.9786.44%70%60.51%Total Case Incident Rate (TCIR)1.390%7.5%0.00%Electric Reliability (SAIDI)70.1474.77%7.5%5.61%Gas Distribution Damage (HPT)2.260%7.5%0.00%Diversity Training ParticipationSatisfied71%7.5%5.36%Total Payout100%71.48%Earnings per share from ongoing operations, as adjusted, for incentive plan purposes were the same as earnings per share from continuing operations, as adjusted, reported externally to our investors (and reconciled to GAAP earnings per share in Appendix A). For 2022, no adjustments were made to our earnings per share from ongoing operations.Payouts under the Short-Term Incentive Plan have varied over the last 10 years as shown in the graph below.Actual awards made to each of our Named Executive Officers under the Short-Term Incentive Plan for 2022 are included in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 37.For the 2023 Short-Term Incentive Plan, we are maintaining our commitment to financial performance with EPS As Adjusted, are expanding our safety metric to include a slate of proactive metrics (timeliness of incident reporting and safety event reporting) and outcome-based metrics (TCIR and PMVI), adding a slate of customer experience metrics including customer perception (JD Power for Natural Gas and Electric) and customer interaction (Customer Effort and Net Promoter Score), deepening our commitment to diversity by adding metrics for diverse candidate pools and diverse interview panels, and including system reliability metrics (SAIDI) and safety metrics (Gas Pipeline Hits per Thousand) which support of our natural gas emissions reduction goal of net zero by 2035. The addition and expansion of our metrics for customer experience, diversity, and system safety and reliability to our 2023 Short-Term Incentive goals demonstrate our ongoing focus to improve our social and environmental ESG performance.Long-Term Incentive. Our Long-Term Incentive Plan is designed to focus executive performance on sustained long-term results that drive or are based on shareholder value creation. Long-term incentive compensation is intended to:Promote achievement of corporate goals by linking the interests of participants to those of our shareholdersProvide participants with an incentive for excellence in individual performancePromote teamwork among participantsMotivate, retain, and attract the services of participants who make significant contributions to our success by allowing participants to share in such successMeet the performance objectives of the plan to achieve an average payout equal to market competitive levels over timePROXY| PROXY STATEMENTThe Committee approved the metrics for our Long-term incentive plans as follows: Long-Term Incentive Plan Metrics Plan Metrics Definition 2020-2022 Plan TSR Total shareholder return 60% TSR Total shareholder return 2021-2023 Plan and 2022- 2024 Plan 20% EPS 20% Average Cost to Serve Diluted earnings per share calculated in accordance with GAAP, adjusted for material, non-recurring events that are approved by the Company's Audit Committee (such as impairment charges, one-time tax events, changes to accounting rules, etc.) Non-fuel operations and maintenance (O&M) expense divided by gross margin calculated in accordance with GAAP, adjusted for material, non-recurring events that are approved by the Company's Audit Committee (such as impairment charges, one-time tax events, changes to accounting rules, etc.) Rationale Executive pay under a long-term, capital accumulation program should mirror performance in shareholder return Executive pay under a long-term, capital accumulation program should mirror performance in shareholder return Aligns with long-term performance growth Drives growth goals while balancing capital deployment with increasing customer rates The long-term incentive compensation component is composed of performance share units and restricted stock that vests ratably over three years. The Committee chose these components because linking executive compensation to stock price appreciation and total shareholder return is an effective way to align the interests of management with those of our shareholders. The split between performance shares and restricted stock for each plan period is illustrated below: The value of long-term incentives awarded is based primarily on competitive market-based data presented by the compensation consultant to the Committee, the impact each position has on our shareholder return, executive performance, and internal pay relationships. The actual amount realized will vary from the target award amounts. The Committee approved the target long-term incentive compensation level for each officer in January 2022. The 2022 long-term incentive was adjusted from 2021 levels for some of the Named Executive Officers to align more closely with market medians. NEO Long-Term Incentive Target Compensation Evans, CEO Kinzley, CFO Iverson, GC Keller, CIO Landis, CHRO 2021 2022 $ $ $ $ $ 2,150,000 $ 625,000 $ 490,000 $ 250,000 $ 275,000 $ 2,300,000 625,000 600,000 300,000 325,000 31 PROXYPROXY STATEMENT | 32 Performance Share Units. Participants are awarded a target number of performance shares units. The target number of performance share units is determined by dividing the Committee approved target performance value for the participant by the average closing price for the established number of trading days at the beginning of the performance period. Vesting of performance share units associated with TSR is based on our total shareholder return over designated performance periods as measured against our Performance Peer Group. The Committee, with the guidance of its independent compensation consultant, periodically conducts a review of our Performance Peer Group to which our performance should be compared. Due to the extensive merger and acquisition activity in the industry and its contribution to relative performance volatility, the Committee chose to use the companies in the EEI Index as the Performance Peer Group. A summary of the TSR performance criteria for each three-year plan period is summarized in the table below:Performance Share PlansPercentile Ranking for Threshold Payout of 25% of Target SharesPercentile Ranking for Target Payout of 100% of Target SharesPercentile Ranking for Maximum Payout LevelPossible Payout Range of Target25th percentile50th percentile90th percentile0-200%Our plans provide: (i) a threshold payout if relative TSR performance is below threshold but our TSR is at least 35 percent for the performance period; and (ii) the performance share plan payout is capped at 100 percent of target if TSR is negative. The additional provisions are intended to reduce the impact of one peer company’s performance on the relative TSR, and also increase accountability and expectations related to the Company’s performance. Vesting of shares associated with Earnings Per Share and Average Cost to Serve performance is determined based upon the Company's performance against established performance goals. The final value of the performance shares is based upon the number of shares of common stock that are ultimately earned, based upon our performance in relation to the performance criteria.Threshold performance under the plan results in a payout of 25 percent of the target share award. Target performance results in a payout of the target share award. Maximum performance results in a payout of 200 percent of the target share award.The performance awards and dividend equivalents, if earned, are paid 50 percent in cash and 50 percent in common stock. All payroll deductions and applicable tax withholding related to the award are withheld from the cash portion. Performance awards are pro-rated for the period of service in the events of retirement, death or disability. Performance awards vest in full under certain circumstances following a change in control. Performance awards are forfeited if an officer's employment is terminated for any reason other than those previously stated.Restricted Stock. Restricted stock awarded as long-term incentives vests one-third each year over a three-year period, and automatically vests in its entirety upon death, disability or under certain termination circumstances following a change in control. Dividends are paid on the restricted stock. Unvested restricted stock is forfeited if an officer’s employment is terminated for any reason other than those previously stated.Payouts under the Performance Share Plan have varied significantly over the last 10 years, as shown in the graph below. Each performance period extends for three years. For the recently completed performance period, January 1, 2020 to December 31, 2022, our total shareholder return was 0.14 percent, which ranked at the 26th percentile of our Performance Peer Group, resulting in a payout at 26.98 percent of target. PROXY| PROXY STATEMENT33 The performance share units and restricted stock granted in 2022 are reflected in the tables in the Performance Share Units and Restricted Stock sections that follow.The 2023 Long-Term Incentive plan retains our current three metrics and adds a new environmental metric measuring our progress in replacing high emitting pipeline to reduce fugitive emissions in support of our 2035 net zero natural gas emissions goal.Board and Management Roles in Compensation DecisionsRole of Executive Officers in Compensation Decisions. In 2022, the Senior Vice President - Chief Human Resources Officer, with the support of an external compensation consultant, reviewed all compensation programs to ensure that the programs do not encourage unnecessary risk-taking and instead encourage behaviors that support the values and operations of the Company. This review determined that the compensation programs of the Company do not encourage excessive risk-taking or have an adverse effect on the Company. The CEO annually reviews the performance of each of our senior executive officers. Based upon these performance reviews, market analysis conducted by compensation consultants and discussions with our Senior Vice President - Chief Human Resources Officer, the CEO recommends the compensation for this group of officers to the Committee.Role of the Committee and Board in Setting Executive Compensation. The Committee reviews and establishes the Company’s financial targets and the CEO’s goals and objectives for the year. After the end of each year, the Committee evaluates the CEO’s performance in light of established goals and objectives, with input from the other independent directors. Based upon the Committee’s evaluation and recommendation, the independent directors of the Board set the CEO’s annual compensation, including salary, short-term incentive, and long-term incentive compensation.The Committee reviews the CEO’s recommended compensation for our senior executive officers. The Committee may approve the CEO’s compensation recommendations for this group of officers or exercise its discretion by modifying any of the recommended compensation and award levels in its review and approval process. The Committee is required to approve all decisions regarding equity awards to our officers.SummaryIn total, the Committee believes that the 2022 compensation actions, decisions and outcomes strongly reflect and reinforce our compensation philosophy and, in particular, emphasize the alignment between compensation and both performance and shareholder interests. At our 2022 annual meeting, shareholders owning 95 percent of the shares that were voted on this matter approved our executive compensation for 2021, which we consider highly supportive of our current compensation philosophy. In connection with establishing the 2022 executive compensation program, the Board reviewed the results of the say on pay vote, as well as market data and performance indicators.PROXYPROXY STATEMENT |Governance Best Practices We have several governance programs in place to align our executive compensation with shareholder interests and to mitigate risks in our plans. These programs include stock ownership guidelines, clawback provisions in our short-term and long-term incentive award agreements, and the prohibition of hedging or pledging of Company stock. STOCK OWNERSHIP GUIDELINES The Committee has implemented stock ownership guidelines that apply to all officers based upon their level of responsibility. We believe it is important for our officers to hold a significant amount of our common stock to further align their interests with the interests of our shareholders. A “retention ratio” approach to stock ownership is incorporated into the guidelines. Officers are required to retain 100 percent of all shares owned, including shares awarded through our incentive plans (net of share withholding for taxes and, in the case of cashless stock option exercises, net of the exercise price and withholding for taxes) until specific ownership goals are achieved. The guidelines are shown below. Position CEO CFO Other Senior Officers Stock Ownership Value as Multiple of Base Salary 6X 4X 3X At least annually, the Compensation Committee reviews common stock ownership to confirm the officers have met or are progressing toward their stock ownership guidelines. Generally, an officer may not sell common stock unless he or she owns common stock in excess of 110 percent of the applicable stock ownership guideline. With the exception of Mr. Keller, who has been in his role less than three years, all of our Named Executive Officers have exceeded their stock ownership guidelines. CLAWBACK OF EXECUTIVE COMPENSATION Our incentive compensation award agreements for restricted stock and performance shares include clawback provisions whereby the participant may be required to repay all income or gains previously realized in respect of such awards if his or her: (1) employment is terminated for cause; (2) if within one year following termination of employment, the Board determines that the participant engaged in conduct prior to his or her termination that would have constituted the basis for a termination of employment for cause; (3) if the participant makes a public statement that is materially detrimental to the interests or reputation of the Company; (4) if the employee violates in any material respect any policy or any code of ethics; or (5) if the participant engages in any fraudulent, illegal or other misconduct. Additionally, our 2015 Amended and Restated Omnibus Incentive Plan states that clawback of compensation is subject to any policy adopted by the Board, including in response to the requirements of Section 10D of the Exchange Act, the SEC final rules thereunder, or any listing rules. We expect to amend our clawback policy and provisions in 2023 to align with the final rules adopted by the SEC and NYSE. HEDGING POLICY Our directors, executive officers, and employees are prohibited from engaging in hedging transactions involving, and from pledging, Company stock, including holding our stock in a margin account. This prohibition extends to all hedging transactions, including zero cost collars and forward sale contracts. 2022 BENEFITS Retirement Benefits. We maintain a variety of employee benefit plans and programs in which our executive officers may participate. We believe it is important to provide post-employment benefits to our executive officers and the benefits we provide approximate retirement benefits paid by other employers to executives in similar positions. The Committee periodically reviews the benefits provided, with assistance from its compensation consultant, to maintain a market-based benefits package. None of our Named Executive Officers received any pension benefit payments in 2022. Several years ago, we adopted a defined contribution plan design as our primary retirement plan and amended our Defined Benefit Pension Plan (“Pension Plan”) for all eligible employees to incorporate a partial freeze in which the accrual of benefits ceased for certain participants while other participants were allowed an election to continue to accrue benefits. None of our Named Executive Officers met the age and service requirements to allow them to continue to accrue benefits under the Pension Plan. Employees who no longer accrue benefits under the Pension Plan now receive Company Retirement 34 PROXY| PROXY STATEMENTContributions (“Retirement Contributions”) in the Retirement Savings Plan. The Retirement Contributions are an age and service points-based calculation. The 401(k) Retirement Savings Plan is offered to all our eligible employees and we provide matching contributions for certain eligible participants. All of our Named Executive Officers are participants in the 401(k) Retirement Savings Plan and received matching contributions in 2022. The matching contributions and the Retirement Contributions are included as “All Other Compensation” in the Summary Compensation Table on page 37. We also provide nonqualified plans to certain executives as approved by the Compensation Committee. The level of retirement benefits provided by the Pension Plan and Nonqualified Plans for each of our Named Executive Officers is reflected in the Pension Benefits for 2022 table on page 40. Our contributions to the Nonqualified Deferred Compensation Plan are included in the All Other Compensation column of the Summary Compensation Table on page 37 and the aggregate Nonqualified Deferred Compensation balance at December 31, 2022 is reported in the Nonqualified Deferred Compensation for 2022 table on page 42. These retirement benefits are explained in more detail in the accompanying narrative to the tables. Other Personal Benefits. We provide the personal use of a Company vehicle, executive health services, and limited reimbursement of financial planning services as benefits to our executive officers. The specific amount attributable to these benefits in 2022 is disclosed in the Summary Compensation Table on page 37. The Committee periodically reviews the other personal benefits provided to our executive officers and believes the current benefits are reasonable and consistent with our overall compensation program. CHANGE IN CONTROL PAYMENTS Our Named Executive Officers may also receive severance benefits in the event of a change in control. We have no employment agreements with our Named Executive Officers. However, change in control agreements are common among our Compensation Peer Group and the Committee and our Board believes providing these agreements to our corporate and select subsidiary officers protects our shareholder interests in the event of a change in control by helping assure management focus and continuity. In 2022, our Compensation Committee approved revised form of incentive award agreements that require a "double trigger" before accelerated equity compensation will be paid to our Named Executive Officers. The double trigger provides benefits in association with: (1) (2) a change in control, and (i) (ii) a termination of employment other than by death, disability or by us for cause, or a termination by the employee for good reason. Our change in control agreements have expiration dates and our Board conducts a thorough review of the change in control agreements at each renewal period. Our current change in control agreements expire November 15, 2025. In general, our change in control agreements provide a severance payment of up to 2.99 times average compensation for Mr. Evans, and up to two times average compensation for the other Named Executive Officers. The change in control agreements do not provide for excise tax gross-ups. See the Potential Payments upon Termination or Change in Control table on page 43 and the accompanying narrative for more information regarding our change in control agreements and estimated payments associated with a change in control. TAX AND ACCOUNTING IMPLICATIONS Section 162(m) of the U.S. Internal Revenue Code of 1986, as amended, places a limit of $1 million in compensation per year on the amount public companies may deduct with respect to certain executive officers. The Committee continues to believe that shareholder interests are best served if its discretion and flexibility in structuring and awarding compensation is not restricted, even though some past and/or future compensation awards result in non-deductible compensation expenses to the Company. The Committee's ability to continue to provide a competitive compensation package to attract, motivate and retain the Company's most senior executives is considered critical to the Company's success and to advancing the interests of its shareholders. 35 PROXYPROXY STATEMENT |REPORT OF THE COMPENSATION COMMITTEE The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to our Board that the Compensation Discussion and Analysis be included in this proxy statement. THE COMPENSATION COMMITTEE Teresa A. Taylor, Chair Tony A. Jensen Scott M. Prochazka Rebecca B. Roberts 36 PROXY| PROXY STATEMENTSUMMARY COMPENSATION TABLE The following table sets forth the total compensation paid or earned by each of our Named Executive Officers for the years ended December 31, 2022, 2021 and 2020. We have no employment agreements with our Named Executive Officers: Name and Principal Position Linden R. Evans President and Chief Executive Officer Richard W. Kinzley Sr. Vice President and Chief Financial Officer Brian G. Iverson Sr. Vice President, General Counsel and Chief Compliance Officer Erik D. Keller (5) Sr. Vice President - Chief Information Officer Jennifer C. Landis (6) Sr. Vice President - Chief Human Resources Officer Year 2022 2021 2020 2022 2021 2020 2022 2021 2020 2022 2021 2022 Stock Awards(1) $2,394,776 $2,238,529 $1,820,599 $650,723 $650,687 $538,547 $624,682 $510,213 $425,583 $312,337 $260,251 $338,378 Non-Equity Incentive Plan Compensation(2) $610,559 $708,252 $936,632 $234,669 $274,770 $348,447 $177,270 $206,294 $275,609 $125,686 $146,261 $146,963 Salary $854,167 $819,167 $783,333 $469,000 $454,000 $448,333 $413,333 $397,667 $384,167 $351,667 $338,333 $342,667 Changes in Pension Value and Nonqualified Deferred Compensation Earnings (3) $— $— $79,100 $— $— $51,945 $— $— $23,339 $— $— $— All Other Compensation(4) $627,046 $674,960 $601,450 $268,377 $282,323 $263,528 $164,183 $170,934 $157,216 $109,753 $146,667 $104,278 Total $4,486,548 $4,440,908 $4,221,114 $1,622,769 $1,661,780 $1,650,800 $1,379,468 $1,285,108 $1,265,914 $899,443 $891,512 $932,286 (1) (2) (3) Stock Awards represent the grant date fair value related to restricted stock, performance shares and performance share units that have been granted as a component of long-term incentive compensation. The grant date fair value is computed in accordance with the provisions of accounting standards for stock compensation. Assumptions used in the calculation of these amounts are included in Note 14 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2022. The amounts shown for the performance shares and performance share units represent the values that are based on the achievement of 100% of the target performance. Assuming achievement of the maximum 200% of target performance, the value of the performance share units would be: $2,949,601 for Mr. Evans, $801,496 for Mr. Kinzley, $769,413 for Mr. Iverson, $384,699 for Mr. Keller, and $416,782 for Ms. Landis. Non-Equity Incentive Plan Compensation represents amounts earned under the Short-Term Incentive Plan. The Compensation Committee approved the payout of the 2022 awards on January 24, 2023 and the awards were paid on March 3, 2023. Change in Pension Value and Nonqualified Deferred Compensation Earnings represents the net positive increase in actuarial value of the Pension Plan and Pension Restoration Benefit (“PRB”) for the respective years. These benefits have been valued using the assumptions disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2022. Because these assumptions sometimes change between measurement dates, the change in value reflects not only the change in value due to additional benefits earned during the period and the passage of time but also reflects the change in value caused by changes in the underlying actuarial assumptions. This has created significant volatility in the last three years with the change in discount rates used to calculate the present value of these benefits contributing significantly to the decreases in 2021, 2022, and the increase in 2020. The Pension Plan and PRB were frozen effective January 1, 2010 for participants who did not satisfy the age 45 and 10 years of service eligibility. Messrs. Evans, Kinzley and Iverson and Ms. Landis did not meet the eligibility choice criteria and their benefits were frozen. Our Named Executive Officers receive employer contributions into a Nonqualified Deferred Compensation Plan (“NQDC”). The NQDC employer contributions are reported in the All Other Compensation column. No Named Executive Officer received preferential or above- market earnings on nonqualified deferred compensation. The change in value attributed to each Named Executive Officer from each plan is shown in the table below: Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis Year 2022 2021 2020 2022 2021 2020 2022 2021 2020 2022 2021 2022 $ $ $ $ $ $ $ $ $ $ $ $ Defined Benefit Plan PRB (76,130) (7,574) 43,576 (91,619) (11,125) 48,872 (40,857) (4,089) 23,339 - - (22,421) $ $ $ $ $ $ $ $ $ $ $ $ (63,285) (7,745) 35,524 (5,842) (833) 3,073 - - - - - - Total Change in Pension Value $ $ $ $ $ $ $ $ $ $ $ $ (139,415) (15,319) 79,100 (97,461) (11,958) 51,945 (40,857) (4,089) 23,339 - - (22,421) 37 PROXYPROXY STATEMENT |(4) All Other Compensation includes amounts allocated under the 401(k) match, defined contributions, Company contributions to defined benefit and deferred compensation plans, dividends received on restricted stock and unvested restricted stock units and other personal benefits. The Other Personal Benefits column reflects the personal use of a Company vehicle, executive health, and financial planning services for each NEO. Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis Year 2022 2022 2022 2022 2022 401(k) Match 15,894 18,300 16,982 18,300 15,601 $ $ $ $ $ Defined Contributions 24,400 $ 22,200 $ 23,518 $ 12,437 $ 18,300 $ NQDC Contributions 494,238 $ 191,442 $ 93,487 $ 45,176 $ 48,353 $ Dividends on Restricted Stock Other Personal Benefits $ $ $ $ $ 70,379 19,870 17,186 16,181 9,153 $ $ $ $ $ 22,135 16,565 13,010 17,659 12,871 Total Other Compensation 627,046 $ 268,377 $ 164,183 $ 109,753 $ 104,278 $ (5) (6) Mr. Keller became an NEO in 2021. Ms. Landis became an NEO in 2022, and her employment with the Company will terminate on April 1,2023 as described below. GRANTS OF PLAN BASED AWARDS IN 2022(1) Estimated Future Payouts Under Non-Equity Incentive Plan Awards (2) Estimated Future Payouts Under Equity Incentive Plan Awards (3) Name Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis Date of Compensation Committee Action 1/25/22 1/25/22 1/25/22 1/25/22 1/25/22 1/25/22 1/25/22 1/25/22 1/25/22 1/25/22 Grant Date 1/25/22 2/11/22 1/25/22 2/11/22 1/25/22 2/11/22 1/25/22 2/11/22 1/25/22 2/11/22 Threshold ($) $ 430,000 Target ($) $ 860,000 Maximum ($) $ 1,720,000 Threshold (#) Target (#) Maximum (#) 5,057 20,226 40,452 $ 165,200 $ 330,400 $ 660,800 $ 124,800 $ 249,600 $ 499,200 $ 88,500 $ 177,000 $ 354,000 $ 104,400 $ 208,800 $ 417,600 1,374 5,496 10,992 1,319 5,276 10,552 660 715 2,638 5,276 2,858 5,716 Maximum ($) All Other Stock Awards: Number of Shares of Stock or Units(4) (#) Threshold (#) Grant Date Fair Value of Stock Awards(5) ($) 13,801 $ 1,474,801 919,975 $ 3,750 3,600 1,800 1,950 $ $ $ $ $ $ $ $ 400,748 249,975 384,706 239,976 192,349 119,988 208,391 129,987 (1) (2) (3) (4) (5) No stock options were granted to our Named Executive Officers in 2022. The columns under “Estimated Future Payouts Under Non-Equity Incentive Plan Awards” show the range of payouts for 2022 performance under our Short-Term Incentive Plan as described in the Compensation Discussion and Analysis under the section titled “Short-Term Incentive” on page 28. If the performance criteria are met, payouts can range from 50 percent of target at the threshold level to 200 percent of target at the maximum level. The non-equity incentive payment for 2022 performance, paid in 2023, has been made based on achieving the criteria described in the Compensation Discussion and Analysis, at 71.48 percent of target, and is shown in the Summary Compensation Table on page 37 in the column titled “Non-Equity Incentive Plan Compensation.” The columns under “Estimated Future Payouts Under Equity Incentive Plan Awards” show the range of payouts (in shares of stock) for the January 1, 2022 to December 31, 2024 performance period as described in the Compensation Discussion and Analysis under the section titled “Long-Term Incentive” on page 30. If the performance criteria are met, payouts can range from 25 percent of target to 200 percent of target. If a participant retires, suffers a disability or dies during the performance period, the participant or the participant’s estate is entitled to that portion of the number of performance shares as such participant would have been entitled to had he or she remained employed through the end of the performance period, prorated for the number of months served. With the exception of certain terminations following a change in control, performance shares and performance share units are forfeited if employment is terminated for any other reason. During the performance period, dividends and other distributions paid with respect to the shares of common stock accrue for the benefit of the participant and are paid out at the end of the performance period. The column “All Other Stock Awards” reflects the number of shares of restricted stock granted on February 11, 2022 under our Amended and Restated 2015 Omnibus Incentive Plan. The restricted stock vests one-third each year over a three-year period, and automatically vests upon death or disability, with the exception of certain terminations following a change in control. Unvested restricted stock is forfeited if employment is terminated for any other reason. Dividends are paid on the restricted stock and the dividends that were paid in 2022 are included in the column titled “All Other Compensation” in the Summary Compensation Table on page 37. The column “Grant Date Fair Value of Stock Awards” reflects the grant date fair value of each equity award computed in accordance with the provisions of accounting standards for stock compensation. The grant date fair value for the performance share units was $72.92 per share and was calculated on a weighted average basis considering the results of a Monte Carlo simulation model and the market value of our common stock as of the beginning of the performance period. Assumptions used in the calculation are included in Note 14 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2022. The grant date fair value for the restricted stock was $66.66 per share for the February 11, 2022 grant, which was the market value of our common stock on the date of grant as reported on the NYSE. 38 PROXY| PROXY STATEMENT OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END 2022(1) Stock Awards Number of Shares or Units of Stock That Have Not Vested(2) (#) Market Value of Shares or Units of Stock That Have Not Vested ($) 29,203 8,245 7,131 6,714 3,798 2,054,139 579,953 501,595 472,263 267,151 Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested(2) (#) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) 59,318 16,876 14,206 6,788 7,740 4,171,104 1,186,706 998,932 477,468 544,280 Name Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis (1) (2) There were no stock options outstanding at December 31, 2022 for our Named Executive Officers. Vesting dates for restricted stock, performance shares, and performance share units are shown in the table below. The performance shares shown with a vesting date of December 31, 2022, are the actual equivalent shares, including dividend equivalents, earned for the performance period ended December 31, 2022. On January 24, 2023, the Compensation Committee confirmed that the performance criteria were met and there would be a payout of 26.98 percent of target. The performance shares with a vesting date of December 31, 2023 and the performance share units with a vesting date of December 31, 2024 are shown at the threshold and target payout levels, respectively, based upon performance as of December 31, 2022. Name Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis Unvested Restricted Stock # of Shares 3,503 5,949 4,600 5,950 4,600 4,601 1,036 1,729 1,250 1,730 1,250 1,250 819 1,356 1,200 1,356 1,200 1,200 692 600 3,530 692 600 600 326 761 650 761 650 650 Vesting Date 02/10/23 02/11/23 02/11/23 02/11/24 02/11/24 02/11/25 02/10/23 02/11/23 02/11/23 02/11/24 02/11/24 02/11/25 02/10/23 02/11/23 02/11/23 02/11/24 02/11/23 02/11/25 02/11/23 02/11/23 08/05/23 02/11/24 02/11/24 02/11/25 02/10/23 02/11/23 02/11/23 02/11/24 02/11/24 02/11/25 Unvested and Unearned Performance Shares # of Shares 3,396 35,696 20,226 Vesting Date 12/31/22 12/31/23 12/31/24 1,004 10,376 5,496 12/31/22 12/31/23 12/31/24 794 8,136 5,276 12/31/22 12/31/23 12/31/24 4,150 2,638 12/31/23 12/31/24 316 4,566 2,858 12/31/22 12/31/23 12/31/24 39 PROXYPROXY STATEMENT |OPTION EXERCISES AND STOCK VESTED DURING 2022(1) Stock Awards(2) Number of Shares Acquired on Vesting (#) Value Realized on Vesting ($) 18,076 5,697 4,418 691 2,036 $ $ $ $ $ 1,214,575 383,045 296,986 46,062 136,756 There were no stock options exercised during 2022. Reflects restricted stock that vested in 2022 and performance shares earned for the January 1, 2019 to December 31, 2021 performance period. The performance share payout was approved by the Compensation Committee on January 24, 2022 and paid out on February 5, 2022. Name Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis _______________ (1) (2) PENSION BENEFITS FOR 2022 Several years ago, we adopted a defined contribution plan design as our primary retirement plan and amended our Pension Plan and Nonqualified Pension Plans for all eligible employees to incorporate a partial freeze in which the accrual of benefits ceased for certain participants while other participants were allowed an election to continue to accrue benefits. Employees eligible to elect continued participation were those employees who were at least 45 years old and had at least 10 years of eligible service with us as of January 1, 2010. None of our Named Executive Officers met the age and service requirement necessary to continue to accrue benefits under the Pension Plan. Rather, benefits under the Pension Plan were frozen for Messrs. Evans, Kinzley and Iverson and Ms. Landis. Mr. Keller joined the Company after the plans were frozen and therefore does not participate in the plans. None of our Named Executive Officers received any pension benefit payments during the fiscal year ended December 31, 2022. The present value accumulated by each Named Executive Officer from each plan is shown in the table below: Name Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis Plan Name Pension Plan Pension Restoration Benefit Pension Plan Pension Restoration Benefit Pension Plan Pension Restoration Plan Pension Plan Pension Restoration Plan Pension Plan Pension Restoration Plan Number of Years of Credited Service(1) (#) Present Value of Accumulated Benefit(2) ($) 8.58 8.58 10.50 10.50 5.83 N/A N/A N/A 7.00 N/A 275,496 219,813 236,011 14,461 146,630 - - - 33,141 - (1) (2) The number of years of credited service represents the number of years used in determining the benefit for each plan. The present value of accumulated benefits was calculated assuming the participants will work until retirement, benefits commence at age 62 and using the discount rate, mortality rate and assumed payment form assumptions consistent with those disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2022. 40 PROXY| PROXY STATEMENTDEFINED BENEFIT PENSION PLAN Our Pension Plan is a qualified pension plan. As discussed above, several years ago we amended our Pension Plan to incorporate a partial freeze in which the accrual of benefits ceased for certain participants while other participants were allowed an election to continue to accrue benefits. The Pension Plan provides benefits at retirement based on length of employment service and average compensation levels during the highest five consecutive years of the last ten years of service. For purposes of the benefit calculation, earnings include wages and other cash compensation received from us, including any bonus, commission, unused paid time off or incentive compensation. It also includes any elective before-tax contributions made by the employee to a Company-sponsored cafeteria plan or 401(k) plan. However, it does not include any expense reimbursements, taxable fringe benefits, moving expenses or moving/relocation allowances, nonqualified deferred compensation, non-cash incentives, stock options and any payments of long-term incentive compensation such as restricted stock or payments under performance share plans. The Internal Revenue Code places maximum limitations on the amount of compensation that may be recognized when determining benefits of qualified pension plans. In 2022, the maximum amount of compensation that could be recognized when determining compensation was $305,000 (called “covered compensation”). Our employees do not contribute to the plan. The amount of the annual contribution by us to the plan is based on an actuarial determination. The benefit formula for the Named Executive Officers in the plan is the sum of (a) and (b) below: (a) Credited Service after January 31, 2000 0.9% of average earnings (up to covered compensation), multiplied by credited service after January 31, 2000 minus the number of years of credited service before January 31, 2000 Plus 1.3% of average earnings in excess of covered compensation, multiplied by credited service after January 31, 2000 minus the number of years of credited service before January 31, 2000 Plus (b) Credited Service before January 31, 2000 1.2% of average earnings (up to covered compensation), multiplied by credited service before January 31, 2000 Plus 1.6% of average earnings in excess of covered compensation, multiplied by credited service before January 31, 2000 Pension benefits are not reduced for social security benefits. The Internal Revenue Code places maximum limitations on annual benefit amounts that can be paid under qualified pension plans. In 2022, the maximum benefit payable under qualified pension plans was $245,000. Accrued benefits become 100 percent vested after an employee completes five years of service. Normal retirement is defined as age 65 under the plan. However, a participant may retire and begin taking unreduced benefits at age 62 with five years of service. Participants who have completed at least five years of credited service can retire and receive defined benefit pension benefits as early as age 55. However, the retirement benefit will be reduced by five percent for each year of retirement before age 62. All our Named Executive Officers who are eligible for pension benefits, with the exception of Ms. Landis, are currently age 55 or older and are entitled to early retirement benefits under this provision. PENSION RESTORATION BENEFIT We also have a Pension Restoration Benefit. This is a nonqualified supplemental plan, in which benefits are not tax deductible until paid. The plan is designed to provide the higher paid executive employee a retirement benefit which, when added to social security benefits and the pension to be received under the Pension Plan, will approximate retirement benefits being paid by other employers to their employees in similar executive positions. The employee’s pension from the qualified Pension Plan is limited by the Internal Revenue Code. The 2022 pension limit was set at $245,000 annually and the compensation taken into account in determining contributions and benefits could not exceed $305,000 and could not include nonqualified deferred compensation. The amount of deferred compensation paid under nonqualified plans is not subject to these limits. As a result of the change in the Pension Plan discussed above, the benefits for certain officers (including Messrs. Evans and Kinzley) under the Nonqualified Pension Plans were significantly reduced because the nonqualified benefit calculations were linked to the benefits earned in the Pension Plan. The Compensation Committee amended the Nonqualified Deferred Compensation Plan to provide non-elective nonqualified restoration benefits to those affected officers who were not eligible to continue accruing benefits under the Pension Plan and Nonqualified Pension Plans. 41 PROXYPROXY STATEMENT |Pension Restoration Benefit. In the event that at the time of a participant’s retirement, the participant’s salary level exceeds the qualified Pension Plan annual compensation limitation ($305,000 in 2022) or includes nonqualified deferred compensation, then the participant will receive an additional benefit, called a “Pension Restoration Benefit,” which is measured by the difference between (i) the monthly benefit that would have been provided to the participant under the Pension Plan as if there were no annual compensation limitation and no exclusion on nonqualified deferred compensation, and (ii) the monthly benefit to be provided to the participant under the Pension Plan. The Pension Restoration Benefit applies to Messrs. Evans and Kinzley. NONQUALIFIED DEFERRED COMPENSATION FOR 2022 We have a Nonqualified Deferred Compensation Plan for a select group of management or highly compensated employees. Eligibility to participate in the plan is determined by the Compensation Committee and includes our Named Executive Officers. A summary of the activity in the plan and the aggregate balance as of December 31, 2022 for our Named Executive Officers is shown in the following table. Our Named Executive Officers received no withdrawals or distributions from the plan in 2022. Name Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis _______________ (1) Executive Contributions $ $ $ $ $ — $ — $ — $ 88,580 $ 51,277 $ Company Contributions in Last Fiscal Year(1) Aggregate Earnings in Last Fiscal Year(2) (1,066,930) $ (339,072) $ (257,377) $ (18,005) $ (109,501) $ Aggregate Balance at Last Fiscal Year End(3) 5,032,553 2,471,582 990,144 195,762 578,513 494,238 191,442 93,487 45,176 48,353 $ $ $ $ $ Our contributions represent non-elective Supplemental Matching and Retirement Contributions and Supplemental Target Contributions (defined in the paragraph below) and are included in the All Other Compensation column of the Summary Compensation Table. The value attributed from each contribution type to each Named Executive Officer in 2022 is shown in the table below: Name Linden R. Evans Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis Supplemental Matching Contribution Supplemental Retirement Contribution Supplemental Target Contribution Total Company Contributions $ $ $ $ $ 75,345 $ 26,298 $ 18,842 $ 6,233 $ 7,186 $ 106,744 35,065 25,122 6,233 7,186 $ $ $ $ $ 312,149 130,079 49,522 32,710 33,981 $ $ $ $ $ 494,238 191,442 93,487 45,176 48,353 (2) (3) (4) Because amounts included in this column do not include above-market or preferential earnings, none of these amounts are included in the “Change in Pension Value and Nonqualified Deferred Compensation Earnings” column of the Summary Compensation Table. Messrs. Evans’, Kinzley’s, Iverson’s, Keller's and Ms. Landis' aggregate balances at December 31, 2022 include $1,548,082, $596,215, $298,260, $84,603, and $48,353, respectively, which are included in the Summary Compensation Table as 2022, 2021 and 2020 compensation. In April of 2022, the Compensation Committee eliminated the supplemental target contribution for all future participants in the plan. All our Named Executive Officers were participants prior to this elimination and maintain entitlement to supplemental target contributions. Eligible employees may elect to defer up to 50 percent of their base salary, up to 100 percent of their Short-Term Incentive Plan award, and up to 100 percent of the cash portion of their Performance Share Plan award. In addition, the Nonqualified Deferred Compensation Plan was amended to provide certain officers whose Pension Plan benefit and Nonqualified Pension Plan benefits were frozen with non-elective supplemental matching contributions equal to 6 percent of eligible compensation in excess of the Internal Revenue Code limit plus matching contributions, if any, lost under the 401(k) Retirement Savings Plan due to nondiscrimination test results and provides non-elective supplemental age and service points-based contributions that cannot be made to the 401(k) Retirement Savings Plan due to the Internal Revenue Code limit (“Supplemental Matching and Retirement Contributions”). It also provides supplemental target contributions equal to a percentage of compensation that may differ by executive, based on the executive’s current age and length of service with us, as determined by the plans’ actuary (“Supplemental Target Contributions”). Messrs. Evans, Kinzley, Iverson, and Keller and Ms. Landis received Supplemental Target Contributions of 20 percent, 17.5 percent, 8 percent, 8 percent, and 8 percent respectively. 42 PROXY| PROXY STATEMENTThe deferrals are deposited into hypothetical investment accounts where the participants may direct the investment of the deferrals as allowed by the plan. The investment options are the same as those offered to all employees in the 401(k) Retirement Savings Plan except for a fixed rate option, which was set at 2.26 percent in 2022. Investment earnings are credited to the participants’ accounts. Upon retirement, we will distribute the account balance to the participant according to the participant's distribution election. The participants may elect either a lump sum payment or annual or monthly installments over a period of years designated by the participant, but not to exceed 10 years. As of January 1, 2023, Messrs. Evans, Kinzley, and Iverson and Ms. Landis are 100 percent vested in the plan. POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL The following table describes the potential payments and benefits under our compensation and benefit plans and arrangements to which our Named Executive Officers would be entitled upon termination of employment. Except for (i) certain terminations following a change in control (“CIC”), as described below, (ii) pro-rata payout of incentive compensation and the acceleration of vesting of equity awards upon retirement, death or disability, and (iii) certain pension and nonqualified deferred compensation arrangements described under Pension Benefits for 2022 and Nonqualified Deferred Compensation for 2022 above, there are no agreements, arrangements or plans that entitle the Named Executive Officers to severance, perquisites, or other enhanced benefits upon termination of their employment. Any agreements to provide other payments or benefits to a terminating executive officer would be in the discretion of the Compensation Committee. The amounts shown below assume that such termination was effective as of December 31, 2022, and thus includes estimates of the amounts that would be paid out to our Named Executive Officers upon their termination. The table does not include amounts such as base salary, short-term incentives and stock awards that the Named Executive Officers earned due to employment through December 31, 2022 and distributions of vested benefits such as those described under Pension Benefits for 2022 and Nonqualified Deferred Compensation for 2022. The table also does not include a value for outplacement services because this would be a de minimis amount. The actual amounts to be paid can only be determined at the time of such Named Executive Officer’s separation from us. Incremental Retirement Benefit (present value)(4) Continuation of Medical/ Welfare Benefits (present value)(5) Cash Severance Payment Acceleration of Equity Awards(6) Total Benefits Linden R. Evans Retirement Death or disability Involuntary termination CIC (1) Involuntary or good reason termination after CIC(2) Richard W. Kinzley Retirement Death or disability Involuntary termination CIC (1) Involuntary or good reason termination after CIC(2) Brian G. Iverson Retirement Death or disability Involuntary termination CIC (1) Involuntary or good reason termination after CIC(2) Erik D. Keller Retirement Death or disability Involuntary termination CIC (1) Involuntary or good reason termination after CIC(2) Jennifer C. Landis Retirement Death or disability Involuntary termination (3) CIC (1) Involuntary or good reason termination after CIC(2) $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ — $ — $ — $ — $ $ 5,107,919 — $ — $ — $ — $ $ 1,806,000 — $ — $ — $ — $ $ 1,594,600 — $ — $ — $ — $ $ 1,322,666 — $ — $ — $ — $ $ 1,055,001 438,600 — $ — $ $ — $ — $ — $ — $ — $ — $ $ 521,560 — $ — $ — $ — $ $ 292,864 — $ — $ — $ — $ $ 112,158 — $ — $ — $ — $ — $ — $ — $ — $ — $ $ 79,800 — $ — $ — $ — $ $ 34,600 — $ — $ — $ — $ $ 31,400 — $ — $ — $ — $ $ 56,300 27,000 — $ — $ $ — $ — $ 1,648,704 3,702,843 $ $ — $ — $ 1,648,704 3,702,843 — — $ 10,122,680 3,128,961 469,737 1,049,691 882,870 392,295 893,889 763,080 198,783 671,045 604,326 $ $ — $ — $ $ $ $ — $ — $ $ $ $ — $ — $ $ — $ — $ — $ — $ — $ 469,737 1,049,691 — — 3,033,630 392,295 893,889 — — 2,410,010 198,783 671,045 — — 1,827,785 — — 480,600 — — (1) (2) (3) The amounts reflected for after a change in control (with no involuntary or good reason termination) contemplate the assumption or replacement of the equity awards by the successor entity. The amounts reflected for involuntary or good reason termination after a change in control include the benefits a Named Executive Officer would receive in the event of a change followed by an involuntary or good reason termination. Ms. Landis’ employment with the Company will terminate effective April 1, 2023. The amounts reported reflect the amounts Ms. Landis is entitled to receive pursuant to a separation agreement we entered into with Ms. Landis in connection with her involuntary termination without cause, as described below. 43 PROXYPROXY STATEMENT | (4) Assumes that in the event of a change in control, Mr. Evans will receive an additional three years of credited and vesting service and the other Named Executive Officers will receive an additional two years of credited and vesting service towards the benefit accrual under their applicable retirement plans. For Messrs. Evans, Kinzley, and Iverson this would be the Retirement Contributions and Nonqualified Deferred Compensation contributions. The benefits will immediately vest and payments will commence at the earliest eligible date unless the executive has elected a later date for the nonqualified plans. With the exception of Ms. Landis, our Named Executive Officers are age 55 or older and are already retiree eligible. (6) (5) Welfare benefits include medical coverage, dental coverage, life insurance, short-term disability coverage and long-term disability coverage. The calculation assumes that the Named Executive Officer does not take employment with another employer following termination, elects continued welfare benefits until age 55 or, if later, the end of the two year benefit continuation period (three years for Mr. Evans) and elects retiree medical benefits thereafter. Retirement is assumed to occur at the earliest eligible date. In the event of death or disability, the acceleration of equity awards represents the acceleration of unvested restricted stock and the assumed payout of the pro-rata share of the performance shares for the January 1, 2021 to December 31, 2023 and January 1, 2022 to December 31, 2024 performance periods. In the event of retirement, all unvested restricted stock is forfeited and the acceleration of equity awards represents only the pro-rata share of the performance shares and performance share units. We assumed a 129 percent payout of the performance shares for the January 1, 2021 to December 31, 2023 performance period and a 103 percent payout of target for the January 1, 2022 to December 31, 2024 performance period based on assumed target achievement of performance metrics for EPS and average cost to serve and, for relative total shareholder return, our Monte Carlo valuations at December 31, 2022. In the event of a change in control without an involuntary or good reason termination after a change in control, the acceleration of equity awards only occurs if the awards are not assumed or replaced by the successor entity. In the event of a change in control or an involuntary or good reason termination after a change in control, the acceleration of equity awards represents the acceleration of unvested restricted stock and performance share units calculated as if the performance period ended on December 31, 2022 for the January 1, 2021 to December 31, 2023, and January 1, 2022 to December 31, 2024 performance periods. The valuation of the restricted stock was based upon the closing price of our common stock on December 31, 2022, and the valuation of the performance share units was based on the average closing price of our common stock for the last 10 trading days of 2022. Actual amounts to be paid out at the time of separation from us may vary significantly based upon the market value of our common stock at that time. Payments Made Upon Termination. Regardless of the manner in which a Named Executive Officer’s employment terminates, the Named Executive Officer or his/her beneficiaries may be entitled to receive amounts earned during his/her term of employment. These include: accrued salary and unused vacation pay; amounts vested under the Pension Plan and Nonqualified Pension Plans; amounts vested under the Nonqualified Deferred Compensation Plan; and amounts vested under the 401(k) Retirement Savings Plan. Payments Made Upon Retirement. In the event of retirement of a Named Executive Officer, in addition to the items identified above, he/she will also receive the benefit of the following: a pro-rata share of the performance shares for each outstanding performance period upon completion of the performance period; and a pro-rata share of the actual payout under the Short-Term Incentive Plan upon completion of the incentive period. Payments Made Upon Death or Disability. In the event of death or disability of a Named Executive Officer, in addition to the items identified above for payments made upon termination, he/she will also receive the benefit of the following: accelerated vesting of restricted stock and restricted stock units; a pro-rata share of the performance shares for each outstanding performance period upon completion of the performance period; and a pro-rata share of the actual payout under the Short-Term Incentive Plan upon completion of the incentive period. Payments Made Upon Involuntary Termination without Cause. We do not have a general severance policy applicable to executive officers, and any severance for an executive officer in connection with an involuntary termination of employment without cause requires approval by our Compensation Committee. In connection with the involuntary termination of Ms. Landis’ employment without cause, the Compensation Committee approved the terms of a separation arrangement pursuant to which we agreed to pay Ms. Landis cash severance equal to $438,600, to be paid in equal installments over a period of one year following her termination of employment, which amount approximates one year of her base salary and her 2023 target short-term incentive award prorated for the three months of 2023 when she was employed, plus $38,400. We will pay Ms. Landis $1,500 per month for 18 months (for a total of $27,000) to cover continued health care benefits and provide outplacement benefits through 2023 of up to $15,000 (which amount is included in Ms. Landis’ Total Benefits in the table above). Ms. Landis has agreed to be available for a period of one year following termination of her employment to provide information to assist in the transition of her responsibilities. In addition, all of the payments and benefits are subject to Ms. Landis’ execution of a general release and her compliance with certain post-termination restrictive covenants. 44 PROXY| PROXY STATEMENTPayments Made Upon a Change in Control. Our Named Executive Officers have change in control agreements that terminate November 15, 2025. The renewal of the change in control agreements is at the discretion of the Compensation Committee and the Board. The change in control agreements provide for certain payments and other benefits to be payable upon a change in control and a subsequent termination of employment, either involuntary or for a good reason. In order to receive any payments under the agreements, the Named Executive Officer must sign a waiver and release of claims that includes a one-year non-competition clause and two-year non-solicitation and non-disparagement clauses. A change in control is defined in the agreements as: an acquisition of 30 percent or more of our common stock, except for certain defined acquisitions, such as acquisition by employee benefit plans, us, any of our subsidiaries, or acquisition by an underwriter holding the securities in connection with a public offering thereof; or members of our incumbent Board cease to constitute at least a majority of the members of the Board, with the incumbent Board being defined as those individuals consisting of the Board on October 1, 2022 and any other directors elected subsequently whose election was approved by the incumbent Board; or approval by our shareholders of: - - - a merger, consolidation, or reorganization; liquidation or dissolution; or an agreement for sale or other disposition of all or substantially all of our assets, with exceptions for transactions which do not involve an effective change in control of voting securities or Board membership, and transfers to subsidiaries or sale of subsidiaries; and all regulatory approvals required to effect a change in control have been obtained and the transaction constituting the change in control has been consummated. In the change in control agreements, a good reason for termination that triggers payment of benefits includes: a material reduction of the executive’s authority, duties or responsibilities; a material reduction in the executive’s base salary or annual incentive target opportunity; any material breach by us of any provisions of the change in control agreement; requiring the executive to be based outside a 50-mile radius from his or her usual and normal place of work; or our failure to obtain an agreement, satisfactory to the executive, from any successor company to assume and agree to perform under the change in control agreement. Upon a change in control, an employment contract with Mr. Evans will become effective for a three-year period and for a two- year period for the other Named Executive Officers. During this time, the executive will receive annual compensation at least equal to the highest rate in effect at any time during the one-year period preceding the change in control and will also receive employment welfare benefits, pension benefits and supplemental retirement benefits on a basis no less favorable than those received prior to the change in control. Annual compensation is defined to include amounts which are includable in the gross income of the executive for federal income tax purposes, including base salary, targeted short-term incentive, targeted long- term incentive grants and awards, and matching contributions or other benefits payable under the 401(k) Retirement Savings Plan, but exclude restricted stock awards, performance units or stock options that become vested or exercisable pursuant to a change in control. If a Named Executive Officer’s employment is terminated prior to the end of the covered time by us for cause or disability, by reason of the Named Executive Officer’s death, or by the Named Executive Officer without good reason, the Named Executive Officer will receive all amounts of compensation earned or accrued through the termination date. If the Named Executive Officer’s employment is terminated because of death or disability, the Named Executive Officer or their beneficiaries will also receive a pro rata bonus equal to 100 percent of the target incentive for the portion of the year served. 45 PROXYPROXY STATEMENT |If Mr. Evans’ employment is terminated during the employment term (other than by reason of death) (i) by us other than for cause or disability, or (ii) by Mr. Evans for a good reason, then Mr. Evans is entitled to the following benefits: all accrued compensation, a pro-rata short-term incentive bonus and accelerated vesting of restricted stock and performance units valued at target as of the date of the change in control; severance pay equal to 2.99 times Mr. Evans’ severance compensation defined as his base salary and short-term incentive target on the date of the change in control; continuation of employee welfare benefits for eighteen months following the termination date unless Mr. Evans becomes covered under the health insurance coverage of a subsequent employer which does not contain any exclusion or limitation with respect to any preexisting condition of Mr. Evans or his eligible dependents; following the three-year period, Mr. Evans may elect to receive coverage under the employee welfare plans of the successor entity at his then-current level of benefits (or reduced coverage at his election) by paying the premiums charged to regular full-time employees for such coverage, and is eligible to continue receiving such coverage through the date of his retirement; three additional years of service and age will be credited to Mr. Evans’ retiree medical savings account and the account balance will become fully vested and he is eligible to use the account balance to offset retiree medical premiums at the later of age 55 or the end of the three year continuation period; three years of additional credited service under the Pension Restoration Plan and Pension Plan; and outplacement assistance services for up to six months. If any other NEO’s employment is terminated during the employment term (other than by death) (i) by us other than for cause or disability, or (ii) by the NEO for a good reason, then the NEO is entitled to the following benefits: all accrued compensation, a pro-rata short-term incentive bonus and accelerated vesting of restricted stock and performance units valued at target as of the date of the change in control; severance pay equal to two times the NEO’s severance compensation defined as the NEO’s base salary and short-term incentive target on the date of the change in control; continuation of employee welfare benefits for eighteen months following the termination date unless the NEO becomes covered under the health insurance coverage of a subsequent employer which does not contain any exclusion or limitation with respect to any preexisting condition of the NEO or the NEO’s eligible dependents; following the two-year period, the NEO may elect to receive coverage under the employee welfare plans of the successor entity at their then-current level of benefits (or reduced coverage at the NEO’s election) by paying the premiums charged to regular full-time employees for such coverage, and is eligible to continue receiving such coverage through the date of their retirement; two additional years of service and age will be credited to the NEO’s retiree medical savings account and the account balance will become fully vested and the NEO is eligible to use the account balance to offset retiree medical premiums at the later of age 55 or the end of the two year continuation period; two years of additional credited service under the executives’ applicable retirement plans; and outplacement assistance services for up to six months. The change in control agreements do not contain a benefit to cover any excise tax imposed by Section 4999 of the Internal Revenue Code of 1986. 46 PROXY| PROXY STATEMENTPAY RATIO FOR 2022 We are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of Mr. Evans, our Chief Executive Officer, in 2022. Based on the information below for the fiscal year 2022 and calculated in a manner consistent with Item 402(u) of Regulation S-K, we reasonably estimate that the ratio of our CEO’s annual total compensation to the annual total compensation of our median employee was 39:1. Name Linden R. Evans Median Employee (1) Year 2022 2022 $ $ Salary Stock Awards Non-Equity Incentive Plan Compensation Change in Pension Value(2) 854,167 98,082 $ $ 2,394,776 $ — $ 610,559 2,823 $ $ All Other Compensation(3) 627,046 14,754 — $ — $ $ $ Total 4,486,548 115,659 (2) (1) We identified our median employee based on the year-to-date total cash compensation actually paid as of October 4, 2020 to all of our employees, other than our CEO, who were employed on October 4, 2020. We are using the same median employee for 2022 because there has been no significant changes in our employee population or employee compensation arrangements. See footnote (4) to our Summary Compensation Table for a description of how the values in the Change in Pension Value column are calculated. All Other Compensation includes 401(k) match, defined contributions, NQDC contributions, dividends on restricted stock and other personal benefits for Mr. Evans and the 401(k) match and defined contributions for the median employee. (3) PAY VERSUS PERFORMANCE In accordance with rules adopted by the Securities and Exchange Commission pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, we provide the following disclosure regarding executive compensation for our principal executive officer (“PEO”) and Non-PEO NEOs and Company performance for the fiscal years listed below. The Compensation Committee did not consider the pay versus performance disclosure below in making its pay decisions for any of the years shown. Summary Compensation Table Total for Linden R. Evans (1) Compensation Actually Paid to Linden R. Evans (1) (2) (3) Average Summary Compensation Table Total for Non-PEO NEOs (1) Average Compensation Actually Paid to Non-PEO NEOs (1) (2) (3) Total Shareholder Return Peer Group Total Shareholder Return (4) Net income (GAAP), in millions Value of initial Fixed $100 Investment Based on: Company- Selected Performance Measure EPS from ongoing operations, as adjusted (non- GAAP) (5) 4,486,548 $ 4,506,289 $ 1,208,492 $ 1,224,584 $ 4,440,908 $ 5,151,457 $ 1,318,764 $ 1,453,664 $ 4,221,114 $ 3,055,790 $ 1,565,573 $ 1,003,991 $ 99.15 $ 96.19 $ 80.92 $ 101.15 $ 117.12 $ 98.84 $ 270.8 $ 251.3 $ 242.8 $ 3.97 3.74 3.73 2022 2021 $ $ $ 2020 _______________ (1) Linden R. Evans was our PEO for each year presented. The individuals comprising the Non-PEO NEOs for each year presented are listed below: 2020 Richard W. Kinzley Brian G. Iverson Stuart A. Wevik Scott A. Buchholz 2021 Richard W. Kinzley Brian G. Iverson Stuart A. Wevik Erik D. Keller 2022 Richard W. Kinzley Brian G. Iverson Erik D. Keller Jennifer C. Landis (2) (3) The amounts shown for Compensation Actually Paid have been calculated in accordance with Item 402(v) of Regulation S-K and do not reflect compensation actually earned, realized, or received by the Company's NEOs. These amounts reflect the Summary Compensation Table Total with certain adjustments as described in footnote (3) below. Compensation Actually Paid reflects the exclusions and inclusions of certain amounts for the PEO and the Non-PEO NEOs as set forth below. Equity values are calculated in accordance with FASB ASC Topic 718. Amounts in the Exclusion of Stock Awards column are the totals from the Stock Awards column set forth in the Summary Compensation Table. Amounts in the Exclusion of Change in Pension Value column reflect the amounts attributable to the Change in Pension Value reported in the Summary Compensation Table. Amounts in the Inclusion of Pension Service Cost are based on the service cost for services rendered during the listed year. 47 PROXYPROXY STATEMENT | Summary Compensation Table Total for Linden R. Evans Exclusion of Change in Pension Value for Linden R. Evans Exclusion of Stock Awards for Linden R. Evans Inclusion of Pension Service Cost for Linden R. Evans Inclusion of Equity Values for Linden R. Evans Compensation Actually Paid to Linden R. Evans $ $ $ 4,486,548 4,440,908 4,221,114 $ $ $ - - (79,100) $ $ $ (2,394,776) (2,238,529) (1,820,599) $ $ $ - - - $ $ $ 2,414,517 2,949,078 734,375 $ $ $ 4,506,289 5,151,457 3,055,790 Average Summary Compensation Table Total for Non-PEO NEOs Average Exclusion of Change in Pension Value for Non-PEO NEOs Average Exclusion of Stock Awards and Option Awards for Non-PEO NEOs Average Inclusion of Pension Service Cost for Non-PEO NEOs $ $ $ 1,208,492 1,318,764 1,565,573 $ $ $ - (37,453) (304,177) $ $ $ (481,530) (478,922) (405,174) $ $ $ - 9,128 33,347 Average Inclusion of Equity Values for Non-PEO NEOs 497,622 $ 642,147 $ 114,422 $ $ $ $ Average Compensation Actually Paid to Non-PEO NEOs 1,224,584 1,453,664 1,003,991 Year 2022 2021 2020 Year 2022 2021 2020 The amounts in the Inclusion of Equity Values in the tables above are derived from the amounts set forth in the following tables: Year-End Fair Value of Equity Awards Granted During Year That Remained Unvested as of Last Day of Year for Linden R. Evans Change in Fair Value from Last Day of Prior Year to Last Day of Year of Unvested Equity Awards for Linden R. Evans Vesting-Date Fair Value of Equity Awards Granted During Year that Vested During Year for Linden R. Evans Change in Fair Value from Last Day of Prior Year to Vesting Date of Unvested Equity Awards that Vested During Year for Linden R. Evans Fair Value at Last Day of Prior Year of Equity Awards Forfeited During Year for Linden R. Evans $ $ $ 2,543,388 2,919,069 1,183,535 $ $ $ 157,935 80,463 (259,008) $ $ $ - - - $ $ $ (286,806) (50,454) (190,152) $ $ $ - - - Value of Dividends or Other Earnings Paid on Stock or Option Awards Not Otherwise Included for Linden R. Evans - $ - $ - $ Total - Inclusion of Equity Values for Linden R. Evans $ $ $ 2,414,517 2,949,078 734,375 Average Year-End Fair Value of Equity Awards Granted During Year That Remained Unvested as of Last Day of Year for Non-PEO NEOs Average Change in Fair Value from Last Day of Prior Year to Last Day of Year of Unvested Equity Awards for Non-PEO NEOs Average Vesting- Date Fair Value of Equity Awards Granted During Year that Vested During Year for Non-PEO NEOs $ $ $ 511,412 624,512 263,362 $ $ $ 30,488 23,290 (68,513) $ $ $ - - - Average Change in Fair Value from Last Day of Prior Year to Vesting Date of Unvested Equity Awards that Vested During Year for Non-PEO NEOs $ $ $ (44,278) (5,655) (80,427) Average Fair Value at Last Day of Prior Year of Equity Awards Forfeited During Year for Non- PEO NEOs $ $ $ - - - Average Value of Dividends or Other Earnings Paid on Stock or Option Awards Not Otherwise Included for Non-PEO NEOs - $ - $ - $ Total - Average Inclusion of Equity Values for Non-PEO NEOs $ $ $ 497,622 642,147 114,422 Year 2022 2021 2020 Year 2022 2021 2020 (4) The Peer Group TSR set forth in this table utilizes the Edison Electric Institute Index (“EEI Index”), which we also utilize in the stock performance graph required by Item 201(e) of Regulation S-K included in our Annual Report for the year ended December 31, 2022. The comparison assumes $100 was invested for the period starting December 31, 2019, through the end of the listed year in the Company and in the EEI Index, respectively. All dollar values assume reinvestment of the pre-tax value of dividends paid by companies, where applicable, included in the EEI Index. Historical stock performance is not necessarily indicative of future stock performance. (5) We determined EPS from ongoing operations, as adjusted (non-GAAP) to be the most important financial performance measure used to link Company performance to Compensation Actually Paid to our PEO and Non-PEO NEOs in 2022. This performance measure may not have been the most important financial performance measure for years 2021 and 2020 and we may determine a different financial performance measure to be the most important financial performance measure in future years. A non-GAAP reconciliation to GAAP EPS is shown below: EPS from ongoing operations, as adjusted (Non-GAAP Measure) EPS available for common stock (GAAP) Impairment of investment EPS from ongoing operations, as adjusted (Non-GAAP) Relationship between Pay and Performance 2022 Year Ended December 31, 2021 2020 $ $ 3.97 $ — 3.97 $ 3.74 $ — 3.74 $ 3.65 0.08 3.73 The charts shown below present a graphical comparison of compensation actually paid to the PEO and the average compensation actually paid to the other NEOs set forth in the Pay Versus Performance table above, as compared against the following Company performance measures: (1) Total shareholder return (TSR); (2) Peer group TSR; (3) Net income; and (4) EPS from ongoing operations, as adjusted. As presented, the first chart below compares the Company's TSR and peer group TSR, assumes an initial investment of $100 on December 31, 2019, assumes all dividends were reinvested and depicts performance at the end of each applicable year. 48 PROXY| PROXY STATEMENT 49 PROXYPROXY STATEMENT |Financial Performance Measures The following table presents the financial performance measures that the Company considers to have been the most important in linking Compensation Actually Paid to our PEO and other NEOs for 2022 to Company performance. The measures in this table are not ranked. Most Important Performance Measures EPS from ongoing operations, as adjusted (non-GAAP) Net income Total Shareholder Return 50 PROXY| PROXY STATEMENTPROPOSAL 4 ADVISORY VOTE ON THE FREQUENCY OF THE ADVISORY VOTE ON OUR EXECUTIVE COMPENSATION Every six years, the Company is required to seek an advisory, non-binding shareholder vote on the frequency of submission to shareholders of the advisory vote on executive compensation once every year, every two years or every three years. We last submitted to our shareholders a vote on the frequency of future say on pay votes in 2017. The Board recognizes the importance of receiving regular input from our shareholders on important issues such as executive compensation and has been asking shareholders to provide their advisory vote on executive compensation since that time. The Board believes that an annual advisory vote on executive compensation is consistent with the Company's policy of seeking input from, and engaging in discussions with, our shareholders on corporate governance matters. As such, the Board recommends that shareholders approve holding a say on pay vote every year. Although the Board is recommending shareholders vote for a frequency of every year, for purposes of this proposal, shareholders are entitled to vote for any of the frequency alternatives, or they may abstain entirely from voting on the proposal, and they are not voting to approve or disapprove of on the Board's recommendation. The frequency of the say on pay vote receiving the greatest number of votes cast in favor of such frequency will be the frequency of the say on pay vote that shareholders are deemed to have approved. Although the outcome of this advisory vote is non-binding, the Board will review the voting results and consider the outcome of the vote when selecting the frequency of advisory votes on executive compensation. The Company will report its determination about the frequency of the advisory vote on executive compensation in a Form 8-K or amendment to a Form 8-K filed within 150 days following the meeting. The Board recommends a vote for the option of "1 YEAR" as the frequency with which shareholders will have an advisory, non-binding vote on executive compensation. 51 PROXYPROXY STATEMENT | TRANSACTION OF OTHER BUSINESS Our Board does not intend to present any business for action by our shareholders at the meeting except the matters referred to in this proxy statement. If any other matters should be properly presented at the meeting, it is the intention of the persons named in the accompanying form of proxy to vote thereon in accordance with the recommendations of our Board. SHAREHOLDER PROPOSALS FOR 2024 ANNUAL MEETING Shareholder proposals intended to be presented at our 2024 annual meeting of shareholders and considered for inclusion in our proxy materials must be received by our Corporate Secretary in writing at our executive offices at 7001 Mount Rushmore Road, P.O. Box 1400, Rapid City, South Dakota 57709, on or prior to November 16, 2023. Any proposal submitted must be in compliance with Rule 14a-8 of Regulation 14A of the Securities and Exchange Commission. Additionally, a shareholder may submit a proposal or director nominee for consideration at our 2024 annual meeting of shareholders, but not for inclusion of the proposal or director nominee in our proxy materials, if the shareholder gives timely written notice of such proposal in accordance with Article I, Section 9 of our Bylaws. In general, Article I, Section 9 provides that, to be timely, a shareholder’s notice must be delivered to our Corporate Secretary in writing not less than 90 days nor more than 120 days prior to the anniversary date of the immediately preceding annual meeting of shareholders. Our 2023 annual meeting is scheduled for April 25, 2023. Ninety days prior to the first anniversary of this date will be January 26, 2024, and 120 days prior to the first anniversary of this date will be December 27, 2023. For business to be properly requested by the shareholder to be brought before the 2024 annual meeting of shareholders, the shareholder must comply with all of the requirements of Article I, Section 9 of our Bylaws, not just the timeliness requirements set forth above. In addition to satisfying the foregoing requirements, to comply with the universal proxy rules, shareholders who intend to solicit proxies in support of director nominees other than the Board's nominees must provide notice that sets forth the information required by Rule 14a-19 under the exchange Act no later than February 25, 2024. 52 PROXY| PROXY STATEMENTSHARED ADDRESS SHAREHOLDERS In accordance with a notice sent to eligible shareholders who share a single address, we are sending only one annual report and proxy statement to that address unless we receive instructions to the contrary from any shareholder at that address. This practice, known as “householding,” is designed to reduce our printing and postage costs. However, if a shareholder of record residing at such an address wishes to receive a separate annual report or proxy statement in the future, he or she may contact Shareholder Relations at the below address. Shareholder Relations Black Hills Corporation 7001 Mount Rushmore Road P.O. Box 1400 Rapid City, SD 57709 (605) 721-1700 Eligible shareholders of record receiving multiple copies of our annual report and proxy statement can request householding by contacting us in the same manner. Shareholders who own shares through a bank, broker or other nominee can request householding by contacting the nominee. We hereby undertake to deliver promptly, upon written or oral request, a separate copy of the annual report to shareholders, or proxy statement, as applicable, to our shareholders at a shared address to which a single copy of the document was delivered. Please vote your shares by telephone, by the Internet or by promptly returning the accompanying form of proxy, whether or not you expect to be present at the annual meeting. ANNUAL REPORT ON FORM 10-K A copy of our Annual Report on Form 10-K (excluding exhibits) for the year ended December 31, 2022, which is required to be filed with the Securities and Exchange Commission, will be made available to shareholders to whom this proxy statement is mailed, without charge, upon written or oral request to Shareholder Relations, Black Hills Corporation, 7001 Mount Rushmore Road, P.O. Box 1400, Rapid City, SD 57709, Telephone Number: (605) 721-1700. Our Annual Report on Form 10-K also may be accessed through our website at www.blackhillscorp.com. IMPORTANT NOTICE REGARDING THE AVAILABILITY OF PROXY MATERIALS FOR THE SHAREHOLDER MEETING TO BE HELD ON APRIL 25, 2023 Shareholders may view this proxy statement, our form of proxy and our 2022 Annual Report to Shareholders over the Internet by accessing our website at www.blackhillscorp.com. Information on our website does not constitute a part of this proxy statement. By Order of the Board, /s/ AMY K. KOENIG Amy K. Koenig Vice President - Governance, Corporate Secretary and Deputy General Counsel Dated: March 15, 2023 53 PROXYPROXY STATEMENT |(This page has been left blank intentionally.) 54 10-K| FORM 10-KUNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, DC 20549 Form 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2022 Or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _______________ Commission File Number 001-31303 BLACK HILLS CORPORATION Incorporated in South Dakota IRS Identification Number 46-0458824 7001 Mount Rushmore Road Rapid City, South Dakota 57702 Registrant’s telephone number (605) 721-1700 Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbol Name of each exchange on which registered Common stock of $1.00 par value BKH New York Stock Exchange Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer Non-accelerated filer ☒ ☐ Accelerated filer Smaller reporting company Emerging growth company ☐ ☐ ☐ If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive oﬃcers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ The aggregate market value of the voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter, June 30, 2022, was $4,702,221,557 Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. Class Outstanding at January 31, 2023 Common stock, $1.00 par value 66,103,478 shares Documents Incorporated by Reference Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2023 Annual Meeting of Stockholders to be held on April 26, 2023, are incorporated by reference in Part III of this Form 10-K. 1 10-KFORM 10-K |TABLE OF CONTENTS Page GLOSSARY OF TERMS AND ABBREVIATIONS WEBSITE ACCESS TO REPORTS FORWARD-LOOKING INFORMATION Part I ITEM 1. BUSINESS History and Organization Electric Utilities Gas Utilities Utility Regulation Characteristics Environmental Matters Human Capital Resources RISK FACTORS UNRESOLVED STAFF COMMENTS PROPERTIES LEGAL PROCEEDINGS MINE SAFETY DISCLOSURES ITEM 1A. ITEM 1B. ITEM 2. ITEM 3. ITEM 4. INFORMATION ABOUT OUR EXECUTIVE OFFICERS Part II ITEM 5. ITEM 6. ITEM 7. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES RESERVED MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Executive Summary Key Elements of our Business Strategy Recent Developments Results of Operations - Consolidated Summary and Overview Non-GAAP Financial Measure Electric Utilities Gas Utilities Corporate and Other Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense) Liquidity and Capital Resources Cash Flow Activities Capital Resources Credit Ratings Capital Requirements Critical Accounting Estimates ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 4 10 10 11 11 11 14 16 20 21 23 30 30 30 30 31 32 33 33 33 34 38 39 40 41 44 46 46 47 47 49 50 50 52 54 2 10-K| FORM 10-K ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Management’s Report on Internal Controls Over Financial Reporting Reports of Independent Registered Public Accounting Firm Consolidated Statements of Income Consolidated Statements of Comprehensive Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Equity Notes to Consolidated Financial Statements Note 1. Business Description and Significant Accounting Policies Note 2. Regulatory Matters Note 3. Commitments, Contingencies and Guarantees Note 4. Revenue Note 5. Property, Plant and Equipment Note 6. Jointly Owned Facilities Note 7. Asset Retirement Obligations Note 8. Financing Note 9. Risk Management and Derivatives Note 10. Fair Value Measurements Note 11. Other Comprehensive Income Note 12. Variable Interest Entity Note 13. Employee Benefit Plans Note 14. Share-based Compensation Plans Note 15. Income Taxes Note 16. Business Segment Information Note 17. Subsequent Events ITEM 9. ITEM 9A. ITEM 9B. ITEM 9C. Part III ITEM 10. ITEM 11. ITEM 12. ITEM 13. ITEM 14. Part IV ITEM 15. ITEM 16. SIGNATURES CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE CONTROLS AND PROCEDURES OTHER INFORMATION DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE EXECUTIVE COMPENSATION SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE PRINCIPAL ACCOUNTANT FEES AND SERVICES EXHIBITS, FINANCIAL STATEMENT SCHEDULES FORM 10-K SUMMARY 56 56 57 60 61 62 64 65 66 66 74 78 80 82 83 83 84 87 90 92 93 93 99 102 105 107 107 107 107 107 107 108 108 109 109 109 112 113 3 10-KFORM 10-K | GLOSSARY OF TERMS AND ABBREVIATIONS The following terms and abbreviations appear in the text of this report and have the definitions described below: AC AFUDC AOCI APSC Arkansas Gas ARO ASC ASU ATM Availability BHC BHSC Alternating Current Allowance for Funds Used During Construction Accumulated Other Comprehensive Income (Loss) Arkansas Public Service Commission Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy). Asset Retirement Obligation Accounting Standards Codification Accounting Standards Update as issued by the FASB At-the-market equity offering program The availability factor of a power plant is the percentage of the time that it is available to provide energy. Black Hills Corporation; the Company Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy) Black Hills Colorado IPP Black Hills Colorado IPP, LLC, a 50.1% owned subsidiary of Black Hills Electric Generation Black Hills Electric Generation Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities. Black Hills Energy The name used to conduct the business of our utility companies Black Hills Energy Renewable Resources (BHERR) Black Hills Energy Renewable Resources, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings Black Hills Energy Services Black Hills Non-regulated Holdings Black Hills Power Black Hills Utility Holdings Black Hills Wyoming Blockchain Interruptible Service (BCIS) Tariff Btu Busch Ranch I 4 Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy). Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy). Also known as South Dakota Electric. Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy) Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation A WPSC-approved tariff applicable to prospective new Wyoming Electric blockchain customers. The tariff allows customers to negotiate rates and terms and conditions for interruptible electric utility service of 10 MW or greater that would be interconnected with Wyoming Electric’s system. Agreements under the BCIS tariff must be filed with the WPSC prior to the first customer billing, be at least 2 years in duration and include specific pricing for all electricity purchased (with pricing terms subject to renegotiation every three years). BCIS customers shall not participate in the PCA to the extent of service received under the tariff. British thermal unit The 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037. 10-K| FORM 10-KBusch Ranch II CACJA Adjustment CFTC Cheyenne Light Cheyenne Prairie Chief Operating Decision Maker (CODM) Choice Gas Program City of Gillette Clean Energy Plan CO2 Colorado Electric Colorado Gas Common Use System Consolidated Indebtedness to Capitalization Ratio Cooling Degree Day Corriedale COVID-19 CP Program CPUC CSAPR The 59.4 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a PPA expiring in November 2044. Clean Air Clean Jobs Act Adjustment is an adjustment mechanism that allows Colorado Electric to collect from customers the capital costs related to Pueblo Airport Generation CT #6. United States Commodity Futures Trading Commission Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as Black Hills Energy). Also known as Wyoming Electric. Cheyenne Prairie Generating Station serves the utility customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-cycle, 40 MW combustion turbine that is wholly-owned by Wyoming Electric and one combined-cycle, 100 MW unit that is jointly-owned by Wyoming Electric (42 MW) and South Dakota Electric (58 MW). Chief Executive Officer Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing the unbundling of the commodity service from the distribution delivery service. Gillette, Wyoming 2030 Ready Plan that establishes a roadmap and preferred resource portfolio for Colorado Electric to cost-effectively achieve the State of Colorado’s requirement calling upon electric utilities to reduce GHG emissions by a minimum of 80% by 2030. The preferred resource portfolio calls for the addition of 149 MW of wind, 258 MW of solar and 50 MW of battery storage to Colorado Electric’s system. The final mix of resources would be determined by the results of a competitive solicitation starting in 2023. Colorado legislation allows electric utilities to own up to 50% of the renewable generation assets added to comply with the Clean Energy Plan. Carbon dioxide Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy). Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy). The Common Use System is a jointly operated transmission system we participate in with Basin Electric Power Cooperative and Powder River Energy Corporation. The Common Use System provides transmission service over these utilities' combined 230- kilovolt (kV) and limited 69-kV transmission facilities within areas of southwestern South Dakota and northeastern Wyoming. Any Indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net-worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility. A cooling degree day is equivalent to each degree that the average of the high and low temperature for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations. The 52.5 MW wind farm near Cheyenne, Wyoming, jointly owned by South Dakota Electric (32.5 MW) and Wyoming Electric (20 MW), serving as the dedicated wind energy supply to the Renewable Ready program. The official name for the 2019 novel coronavirus disease announced on February 11, 2020, by the World Health Organization, that is causing a global pandemic. Commercial Paper Program Colorado Public Utilities Commission Cross-State Air Pollution Rule 5 10-KFORM 10-K |CT CTII Cushion Gas CVA DC Combustion Turbine The 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette. The portion of natural gas necessary to force saleable gas from a storage field into the transmission system and for system balancing, representing a permanent investment necessary to use storage facilities and maintain reliability. Credit Valuation Adjustment Direct Current Dividend Payout Ratio Annual dividends paid on common stock divided by net income from continuing operations available for common stock DRSPP DSM Dth EBITDA ECA Dividend Reinvestment and Stock Purchase Plan Demand Side Management Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu). Earnings before interest, taxes, depreciation and amortization, a non-GAAP measure. Energy Cost Adjustment is an adjustment that allows us to pass the prudently-incurred cost of fuel and purchased energy through to customers. Economy Energy Purchased energy that costs less than that produced with the utilities’ owned generation. Energy Efficiency Cost Recovery is an adjustment mechanism that allows us to recover from customers the costs associated with providing energy efficiency programs. Environmental Improvement Adjustment is an annual adjustment mechanism that allows us to recover from customers eligible investments in, and expense related to, new environmental measures. Electric generating unit The global energy sector’s shift from fossil-based systems of energy production and consumption, including oil, natural gas and coal to renewable energy sources like wind and solar, as well as battery storage solutions. United States Environmental Protection Agency Electric Vehicle Exempt Wholesale Generator Financial Accounting Standards Board United States Federal Energy Regulatory Commission Fitch Ratings Inc. Accounting principles generally accepted in the United States of America Gas Cost Adjustment is an adjustment that allows us to pass the prudently-incurred cost of gas and certain services through to customers. Greenhouse gases Settlement with a utility’s commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders. Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations. We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans. Non-regulated power generation and mining businesses that are vertically integrated within our Electric Utilities segment. EECR EIA EGU Energy Transition EPA EV EWG FASB FERC Fitch GAAP GCA GHG Global Settlement Happy Jack Heating Degree Day HomeServe Integrated Generation 6 10-K| FORM 10-KIowa Gas IPP IRA IRC IRP IRS ITC IUB Kansas Gas KCC kV LIBOR Mcf Mcfd MDU MEAN MISO MMBtu Moody’s MSHA MW MWh N/A NAAQS NAV Nebraska Gas Neil Simpson II NERC NOx NOL Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy). Independent Power Producer Inflation Reduction Act of 2022 Internal Revenue Code Integrated Resource Plan United States Internal Revenue Service Investment Tax Credit Iowa Utilities Board Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy). Kansas Corporation Commission Kilovolt London Interbank Offered Rate Thousand cubic feet Thousand cubic feet per day Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc. Municipal Energy Agency of Nebraska Midcontinent Independent System Operator, Inc. Million British thermal units Moody’s Investors Service, Inc. United States Department of Labor’s Mine Safety and Health Administration Megawatts Megawatt-hours Not Applicable National Ambient Air Quality Standards Net Asset Value Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy). A mine-mouth, coal-fired power plant owned and operated by South Dakota Electric with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. North American Electric Reliability Corporation Nitrogen oxide Net Operating Loss Northern Iowa Windpower Northern Iowa Windpower, LLC, a 87.1 MW wind farm located near Joice, Iowa, owned by Black Hills Electric Generation and operated by a third-party. We sell the wind energy generated in the MISO market. NPSC OCI OPEB OSHA OSM PacifiCorp PCA Nebraska Public Service Commission Other Comprehensive Income Other Post-Employment Benefits United States Department of Labor’s Occupational Safety & Health Administration United States Department of the Interior’s Office of Surface Mining PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an affiliate of Berkshire Hathaway. Power Cost Adjustment is an annual adjustment mechanism that allows us to pass a portion of prudently-incurred delivered power costs, including fuel, purchased capacity and energy, and transmission costs, through to customers. 7 10-KFORM 10-K |PCCA Peak View PHMSA PPA PRPA PSA PTC Pueblo Airport Generation PUHCA 2005 Ready Ready Wyoming Renewable Ready RESA Revolving Credit Facility RMNG RNG RTO SDPUC SEC Power Capacity Cost Adjustment is an annual adjustment that allows us to pass the prudently-incurred purchased capacity costs, incremental to costs included in base rates, through to customers. The 60.8 MW wind farm owned by Colorado Electric. United States Department of Transportation Pipeline and Hazardous Materials Safety Administration Power Purchase Agreement Platte River Power Authority Power Sales Agreement Production Tax Credit The 440 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (240 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on January 1, 2012. Public Utility Holding Company Act of 2005 The Company’s branding platform which emphasizes that we will 1) prioritize our customers; 2) act as a thoughtful, responsible leader; 3) listen first and lead with a focus on relationships; and 4) be creative in our approach to solutions. A 260-mile, multi-phase transmission expansion project in Wyoming. This transmission project will serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region. Voluntary renewable energy subscription program for large commercial, industrial and governmental customers in South Dakota and Wyoming. Renewable Energy Standard Adjustment is an incremental retail rate limited to 2% for Colorado Electric customers that provides funding for renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard. Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 19, 2021, and now terminates on July 19, 2026. Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy). Renewable natural gas Regional Transmission Organization South Dakota Public Utilities Commission United States Securities and Exchange Commission Service Guard Comfort Plan Appliance protection plan that provides home appliance repair services through on- going monthly service agreements to residential utility customers. Silver Sage SO2 S&P SourceGas Transaction South Dakota Electric SPP SSIR Silver Sage Windpower, LLC, owned by Duke Energy Generation Services Sulfur dioxide S&P Global Ratings, a division of S&P Global Inc. On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy). Southwest Power Pool, a regional transmission organization (RTO) that oversees the bulk electric grid and wholesale power market in the central United States. System Safety and Integrity Rider System Peak Demand Represents the highest point of retail customer usage for a single hour. TCA 8 Transmission Cost Adjustment is an annual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the next rate review. 10-K| FORM 10-KPueblo Airport Generation The 440 MW combined cycle gas-fired power generation plants jointly owned by Colorado Electric (240 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP owns and operates this facility. The plants commenced operation on PCCA Peak View PHMSA PPA PRPA PSA PTC PUHCA 2005 Ready Ready Wyoming RESA RMNG RNG RTO SDPUC SEC Silver Sage SO2 S&P SPP SSIR TCA Power Capacity Cost Adjustment is an annual adjustment that allows us to pass the prudently-incurred purchased capacity costs, incremental to costs included in base rates, through to customers. The 60.8 MW wind farm owned by Colorado Electric. United States Department of Transportation Pipeline and Hazardous Materials Safety Administration Power Purchase Agreement Platte River Power Authority Power Sales Agreement Production Tax Credit January 1, 2012. Public Utility Holding Company Act of 2005 The Company’s branding platform which emphasizes that we will 1) prioritize our customers; 2) act as a thoughtful, responsible leader; 3) listen first and lead with a focus on relationships; and 4) be creative in our approach to solutions. A 260-mile, multi-phase transmission expansion project in Wyoming. This transmission project will serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and expanding access to power markets and renewable resources. The project will help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region. governmental customers in South Dakota and Wyoming. Renewable Energy Standard Adjustment is an incremental retail rate limited to 2% for Colorado Electric customers that provides funding for renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard. Renewable Ready Voluntary renewable energy subscription program for large commercial, industrial and Revolving Credit Facility Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 19, 2021, and now terminates on July 19, 2026. Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas transmission and wholesale services in western Colorado (doing business as Black Hills Energy). Service Guard Comfort Plan Appliance protection plan that provides home appliance repair services through on- Renewable natural gas Regional Transmission Organization South Dakota Public Utilities Commission United States Securities and Exchange Commission going monthly service agreements to residential utility customers. Silver Sage Windpower, LLC, owned by Duke Energy Generation Services Sulfur dioxide S&P Global Ratings, a division of S&P Global Inc. SourceGas Transaction On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing. South Dakota Electric Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy). Southwest Power Pool, a regional transmission organization (RTO) that oversees the bulk electric grid and wholesale power market in the central United States. System Safety and Integrity Rider System Peak Demand Represents the highest point of retail customer usage for a single hour. Transmission Cost Adjustment is an annual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the next rate review. TCAM TCJA Tech Services TFA Transmission Tie TSA Utilities VEBA VIE WEIS Wind Capacity Factor Winter Storm Uri Transmission Cost Adjustment Mechanism is a WPSC-approved tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmisson costs. Tax Cuts and Jobs Act enacted on December 22, 2017 Non-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts. Transmission Facility Adjustment is an annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers. South Dakota Electric owns 35% of a AC-DC-AC transmission tie that interconnects the Western and Eastern transmission grids, which are independently-operated transmission grids serving the western and eastern United States, respectively. Basin Electric Power Cooperative owns the remaining ownership percentage. This transmission tie allows us to buy and sell energy in the Eastern grid without having to isolate and physically reconnect load or generation between the two transmission grids, thus enhancing the reliability of our system. It accommodates scheduling transactions in both directions simultaneously, provides additional opportunities to sell excess generation or to make economic purchases to serve our native load and contract obligations, and enables us to take advantage of power price differentials between the two grids. The total transfer capacity of the tie is 400 MW, including 200 MW from West to East and 200 MW from East to West. United States Department of Homeland Security’s Transportation Security Administration Black Hills’ Electric and Gas Utilities Voluntary Employee Benefit Association Variable Interest Entity Western Energy Imbalance Service Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy. Working Capacity Total gas storage capacity minus cushion gas WPSC WRDC Wygen I Wygen II Wygen III Wyodak Plant Wyoming Electric Wyoming Gas Wyoming Public Service Commission Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities (doing business as Black Hills Energy). A mine-mouth, coal-fired generating facility with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%. A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex. A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 116 MW located at our Gillette, Wyoming energy complex. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23%. The 402.3 MW mine-mouth, coal-fired generating facility located at our Gillette, Wyoming energy complex, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility. Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy). Black Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy). 9 10-KFORM 10-K |WEBSITE ACCESS TO REPORTS The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information contained on our website is not part of this document. FORWARD-LOOKING INFORMATION This Form 10-K contains forward-looking statements as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward- looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of Financial Condition and Results of Operations. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations, beliefs or projections may not be achieved or accomplished. Any forward-looking statement contained in this document speaks only as of the date on which the statement is made and the Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, such as adverse macroeconomic conditions, global pandemics or severe weather events, and it is not possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are expressly qualified by the risk factors and cautionary statements in this Annual Report on Form 10-K, including statements contained within Item 1A - Risk Factors. 10 10-K| FORM 10-KPART I ITEM 1. BUSINESS History and Organization Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,” “us” or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota (incorporated in South Dakota in 1941). 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 220,000 electric utility customers in Colorado, Montana, South Dakota and Wyoming. We also own and operate non-regulated power generation and mining assets that are vertically integrated into and primarily contracted to our Electric Utilities. Our Electric Utilities own 1,482 MW of generation and 9,024 miles of electric transmission and distribution lines. Our Gas Utilities segment serves approximately 1,107,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate 4,713 miles of intrastate gas transmission pipelines and 42,222 miles of gas distribution mains and service lines, seven natural gas storage sites, more than 50,000 horsepower of compression and over 515 miles of gathering lines. Electric Utilities We conduct electric utility operations through our Colorado, South Dakota and Wyoming subsidiaries. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our retail customers. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services. Additionally, we own and operate non-regulated power generation and mining assets that are vertically integrated into and primarily support our Electric Utilities. Nearly all of these operations are located at our electric generating complexes and are physically integrated into our Electric Utilities’ operations. Retail Customers Residential Commercial Industrial Other Total Electric Retail Customers at End of Year Retail Customers Colorado Electric South Dakota Electric Wyoming Electric Total Electric Retail Customers at End of Year 2022 As of December 31, 2021 2020 188,921 30,404 82 1,024 220,431 186,852 30,326 81 1,010 218,269 2022 As of December 31, 2021 100,573 75,169 44,689 220,431 99,709 74,509 44,051 218,269 184,872 30,225 83 1,017 216,197 2020 98,735 73,700 43,762 216,197 Capacity and Demand. System Peak Demand for the Electric Utilities’ retail customers for each of the last three years are listed below: 2022 (a) Summer Winter 410 403 294 334 355 281 System Peak Demand (in MW) 2021 2020 Summer Winter Summer Winter 407 397 274 279 299 246 401 378 271 297 304 246 Colorado Electric South Dakota Electric Wyoming Electric ____________________ (a) In December 2022, each of our Electric Utilities set new winter peak loads. In July 2022, South Dakota Electric and Wyoming Electric set new all-time and summer peak loads. See recent peak discussion in the 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 additional information. 11 10-KFORM 10-K | As of December 31, 2022, our Electric Utilities’ ownership interests in electric generating plants were as follows: Colorado Electric: Unit Busch Ranch I (a) Peak View (b) (c) Pueblo Airport Generation #1-2 Pueblo Airport Generation CT #6 AIP Diesel Diesel #1 and #3-5 Diesel #1-5 South Dakota Electric: Cheyenne Prairie Corriedale (c) Wygen III Neil Simpson II Wyodak Plant Neil Simpson CT Lange CT Ben French Diesel #1-5 Ben French CTs #1-4 Wyoming Electric: Cheyenne Prairie Cheyenne Prairie CT Corriedale (c) Wygen II Integrated Generation: Wygen I Pueblo Airport Generation #4-5 Busch Ranch I (a) Busch Ranch II (c) Northern Iowa Windpower (c) Fuel Type Wind Wind Gas Gas Oil Oil Oil Gas Wind Coal Coal Coal Gas Gas Oil Gas/Oil Gas Gas Wind Coal Coal Gas Wind Wind Wind Total MW Capacity ____________________ (a) Location Ownership Interest % (d) Owned Nameplate Capacity (MW) In Service Date Pueblo, Colorado Pueblo, Colorado Pueblo, Colorado Pueblo, Colorado Pueblo, Colorado Pueblo, Colorado Rocky Ford, Colorado Cheyenne, Wyoming Cheyenne, Wyoming Gillette, Wyoming Gillette, Wyoming Gillette, Wyoming Gillette, Wyoming Rapid City, South Dakota Rapid City, South Dakota Rapid City, South Dakota Cheyenne, Wyoming Cheyenne, Wyoming Cheyenne, Wyoming Gillette, Wyoming Gillette, Wyoming Pueblo, Colorado Pueblo, Colorado Pueblo, Colorado Joice, Iowa 50% 100% 100% 100% 100% 100% 100% 58% 62% 52% 100% 20% 100% 100% 100% 100% 42% 100% 38% 100% 76.5% 50.1% (e) 50% 100% 100% 14.5 60.8 200.0 40.0 10.0 8.0 10.0 58.0 32.5 60.3 90.0 80.5 40.0 40.0 10.0 100.0 42.0 40.0 20.0 95.0 68.9 200.0 14.5 59.4 87.1 1,481.5 2012 2016 2011 2016 2001 1964 1964 2014 2020 2010 1995 1978 2000 2002 1965 1977-1979 2014 2014 2020 2008 2003 2012 2012 2019 2019 In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American Recovery and Reinvestment Act. The PTCs for Peak View flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins. This facility qualifies for PTCs at $26/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service. Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. In 2016, Black Hills Electric Generation sold a 49.9% non-controlling interest in Black Hills Colorado IPP to a third party. See Note 12 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information. (b) (c) (d) (e) Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended December 31 was as follows: Power Supply Coal Natural Gas and Diesel Oil (a) Wind Total Generated Coal, Natural Gas, Oil and Other Market Purchases Wind Purchases Total Purchased Total 2022 2021 2020 35.1% 18.8% 11.4% 65.3% 29.6% 5.1% 34.7% 100.0% 34.2% 24.4% 11.3% 69.9% 25.1% 5.0% 30.1% 100.0% 40.3% 25.0% 8.8% 74.1% 21.1% 4.8% 25.9% 100.0% ____________________ (a) The diesel-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. 12 10-K| FORM 10-KOur Electric Utilities’ weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power (excluding contracted capacity) per MWh for the years ended December 31 were as follows: Fuel and Purchased Power (dollars per MWh) Coal Natural Gas and Diesel Oil Total Generated Weighted Average Fuel Cost Coal, Natural Gas, Oil and Other Market Purchases Wind Purchases Total Purchased Power Weighted Average Cost Total Weighted Average Fuel and Purchased Power Cost 2022 2021 2020 $ $ 12.76 37.09 17.57 66.35 33.78 61.56 32.82 $ $ 11.55 33.65 17.40 64.85 34.69 59.84 30.17 $ $ 11.38 8.59 9.09 40.80 42.06 41.03 17.36 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 2022. 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., $1.09 per MMBtu for year ended December 31, 2022) 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, 2022, we estimated our recoverable reserves to be approximately 174 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, 2022, our Electric Utilities owned the electric transmission and distribution lines shown below: Utility Colorado Electric South Dakota Electric (b) Wyoming Electric State Colorado South Dakota, Wyoming Wyoming Transmission (a) (in Line Miles) Distribution (in Line Miles) 598 1,235 59 1,892 3,198 2,587 1,347 7,132 ____________________ (a) (b) Electric transmission line miles include voltages of 69 kV and above. South Dakota Electric transmission line miles include 43 miles within the Common Use System. Material transmission services agreements are disclosed 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 performance. 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. 13 10-KFORM 10-K | 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, our electric utility is subject to rules which may require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non- affiliated IPPs for the right to supply electric energy and capacity for Colorado Electric 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 the WRDC mine. Rail transport market opportunities for WRDC are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC mine is served by only one railroad, resulting in less competitive transportation rates. Additionally, coal competes with other energy sources, such as natural gas, 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 approximately 1,107,000 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 52,600 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we provide services under the Service Guard Comfort Plan, Tech Services and HomeServe. Retail Customers Residential Commercial Industrial Transportation Total Natural Gas Retail Customers at End of Year Retail Customers Arkansas Gas Colorado Gas Iowa Gas Kansas Gas Nebraska Gas Wyoming Gas Total Natural Gas Retail Customers at End of Year 2022 As of December 31, 2021 864,038 85,203 2,189 155,685 1,107,115 853,908 84,234 2,158 153,929 1,094,229 2022 As of December 31, 2021 183,270 208,060 162,801 118,599 301,007 133,378 1,107,115 180,216 202,747 161,905 117,862 298,832 132,667 1,094,229 2020 844,999 83,135 2,235 152,568 1,082,937 2020 178,281 197,817 160,952 116,973 296,778 132,136 1,082,937 We procure natural gas for our distribution customers from a diverse mix of producers, processors and marketers and generally use hedging, 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 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. 14 10-K| FORM 10-K The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities as of December 31, 2022: Arkansas Gas Colorado Gas Wyoming Gas Total Working Capacity (Mcf) 9,273,700 2,361,495 5,733,900 17,369,095 Cushion Gas (Mcf) 13,433,040 6,164,715 17,545,600 37,143,355 Total Capacity (Mcf) 22,706,740 8,526,210 23,279,500 54,512,450 Maximum Daily Withdrawal Capability (Mcfd) 196,000 30,000 36,000 262,000 The following table summarizes certain information regarding our system infrastructure as of December 31, 2022: Arkansas Gas Colorado Gas Iowa Gas Kansas Gas Nebraska Gas Wyoming Gas Total Intrastate Gas Transmission Pipelines (in line miles) Gas Distribution Mains (in line miles) Gas Distribution Service Lines (in line miles) 877 699 173 331 1,317 1,316 4,713 5,070 7,088 2,879 3,004 8,558 3,563 30,162 1,330 2,372 2,503 1,388 2,796 1,671 12,060 Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. 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 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. 15 10-KFORM 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 TSA, which regulates certain activities related to the safety and security of natural gas pipelines. In May and July 2021 the TSA issued security directives that included several new cybersecurity requirements for critical pipeline owners and operators; and 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. 16 10-K| FORM 10-KElectric Utilities The following table provides regulatory information for each of our Electric Utilities: Subsidiary Jurisdiction Colorado Electric (a) South Dakota Electric Wyoming Electric (a) (c) CO CO WY SD FERC WY Authorized Rate of Return on Equity Authorized Return on Rate Base Authorized Capital Structure Debt/Equity Authorized Rate Base (in millions) Effective Date Additional Regulatory Mechanisms Percentage of Power Marketing Profit Shared with Customers 9.37% 7.43% 48%/52% $539.6 1/2017 ECA, TCA, PCCA, EECR/DSM, RESA 9.37% 9.90% Global Settlement 10.80% 9.75% 6.02% 8.13% 7.76% 8.76% 7.48% $57.9 $46.8 $543.9 1/2017 CACJA Adjustment Rider 10/2014 10/2014 67%/33% 47%/53% Global Settlement 43%/57% $177.8 (b) 2/2009 FERC Transmission Tariff PCA, EECR/DSM, Rate 3/2023 48%/52% Base Recovery on Acquisition Adjustment, TCAM ECA ECA, TFA, EIA $506.4 90% N/A 65% 70% N/A N/A ____________________ (a) For both Colorado Electric and Wyoming Electric, transmission investments are recovered through retail rates rather than FERC Transmission Tariffs. Effective September 1, 2022, a formulaic approach determines the revenue component of Colorado Electric's open access transmission tariff. Includes $160.7 million in 2022 rate base for the 2022 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. 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) (c) The following table summarizes the mechanisms we have in place for each of our Electric Utilities: Electric Utility Jurisdiction Colorado Electric South Dakota Electric (SD) (a) South Dakota Electric (WY) (b) South Dakota Electric (FERC) (c) Wyoming Electric (d) ____________________ (a) Environmental Cost ☑ EECR/DSM ☑ ☑ ☑ Cost Recovery Mechanisms Transmission Expense ☑ ☑ ☑ ☑ Fuel Cost ☑ ☑ ☑ ☑ Transmission Capital ☑ ☑ ☑ ☑ Purchased Power ☑ ☑ ☑ ☑ RESA ☑ 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. 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. South Dakota Electric has an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff. (b) (c) (d) Wyoming Electric has a WPSC-approved transmission tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmission costs. 17 10-KFORM 10-K |Gas Utilities The following table provides regulatory information for each of our Gas Utilities: Subsidiary Arkansas Gas (a) Jurisdiction AR Authorized Rate of Return on Equity 9.60% Authorized Return on Rate Base 6.20% (b) Authorized Capital Structure Debt/Equity 55%/45% Authorized Rate Base (in millions) $674.6 (c) Colorado Gas (a) RMNG Iowa Gas (a) CO CO IA 9.20% 9.90% 6.56% 6.71% 50%/50% 53%/47% $303.20 $118.70 9.60% 6.75% 50%/50% $300.90 Kansas Gas (a) KS Global Settlement Global Settlement Global Settlement Global Settlement Effective Date Additional Regulatory Mechanisms 10/2022 GCA, Safety and Integrity Rider, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment 1/2022 GCA, SSIR, EECR/DSM 6/2018 SSIR, Liquids/Off-system/Market Center Services Revenue Sharing 1/2022 GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing 1/2022 GCA, Weather Normalization Tariff, Gas System Reliability Surcharge, Ad Valorem Tax Surcharge, Cost of Bad Debt Collected through GCA, Pension Levelized Adjustment, Tax Adjustment Rider, Gas Supply Optimization revenue sharing Nebraska Gas (d) NE 9.50% 6.71% 50%/50% $504.20 3/2021 GCA, Cost of Bad Debt Collected Wyoming Gas (d) WY 9.40% 6.98% 50%/50% $354.40 through GCA, Infrastructure System Replacement Cost Recovery Surcharge, Choice Gas Program, SSIR, Bad Debt expense recovered through Choice Supplier Fee, Line Locate Surcharge, HEAT Program 3/2020 GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program ____________________ (a) For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Arkansas Gas return on rate base is adjusted to remove certain liabilities from rate review capital structure for comparison with other subsidiaries. Arkansas Gas rate base is adjusted to include certain liabilities for comparison with other subsidiaries. The Choice Gas Program mechanisms are applicable to only a portion of Nebraska Gas and Wyoming Gas customers. (b) (c) (d) 18 10-K| FORM 10-KThe following table summarizes the mechanisms we have in place for each of our Gas Utilities: Gas Utility Jurisdiction Arkansas Gas Colorado Gas RMNG (a) Iowa Gas Kansas Gas Nebraska Gas Wyoming Gas EECR/DSM ☑ ☑ ☑ ☑ Integrity Additions ☑ ☑ ☑ ☑ ☑ ☑ ☑ Cost Recovery Mechanisms Weather Normal ☑ Pension Recovery Bad Debt Gas Cost (b) ☑ ☑ Revenue Decoupling ☑ ☑ ☑ ☑ ☑ ☑ ☑ ☑ ☑ ____________________ (a) RMNG, which is an intrastate transmission pipeline that provides natural gas transmission and wholesale services in western Colorado, has an SSIR mechanism which allows recovery of investments through December 31, 2021. The other cost recovery mechanisms are not applicable to RMNG. (b) 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. 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 public 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 three EWGs, Wygen I, Pueblo Airport Generation (facilities #4-5) and Northern Iowa Windpower. Each of these three 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. 19 10-KFORM 10-K | Pipeline Security In May and July 2021, the TSA issued security directives in response to a ransomware attack on the Colonial Pipeline that occurred earlier in 2021 that included several new cybersecurity requirements for critical pipeline owners and operators. Among these requirements is the implementation of specific mitigation measures to protect against ransomware attacks and other known threats to information and operational technology systems; development and implementation of a cybersecurity contingency and recovery plan; and performance of a cybersecurity architecture design review. We have implemented several of these directives and are evaluating the potential effect of several others on our operations and facilities, as well as the potential cost of implementation, and will continue to monitor for any clarifications or amendments to these directives. 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 requires states to develop plans by 2022 for GHG reductions from coal-fired power plants. In a January 2021 decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. Four petitions for review of the D.C. Circuit’s opinion were subsequently granted by the U.S. Supreme Court on October 29, 2021, consolidated under West Virginia v. EPA et al. On June 30, 2022, the U.S. Supreme Court released its opinion in favor of West Virginia and aligned parties. The decision clarifies that there are limits on how the EPA may regulate GHGs absent further direction from the U.S. Congress. The court concluded that emission caps that would cause generation shifting from fossil-fuel-fired power plants to renewable energy facilities would require specific congressional authorization and that such authorization had not been given under the Clean Air Act. The decision by the U.S. Supreme Court may affect the EPA’s development of any new regulations to address CO2 emissions from coal- and natural gas-fired power plants; however, at this time, we cannot predict the impact of any such regulations or the decision by the U.S. Supreme Court on the results of operations, financial position, and liquidity. The EPA has indicated that it intends to issue a proposed rule in early 2023 with a new set of emission guidelines for states to follow in submitting state plans to establish and implement standards of performance for GHG emissions from existing fossil fuel-fired electric generating units. We will continue to monitor any related guidelines and rulemakings issued by the EPA or state regulatory authorities. In February 2022, the EPA proposed the Good Neighbor Rule Provisions, which are part of the CSAPR framework and is intended to address ozone transport for the 2015 ozone NAAQS. The rule focuses on reductions of NOx, which is a precursor to ozone formation, for states that do not have an approved State Implementation Plan (SIP). On January 31, 2023, the EPA finalized a notice which disapproved 19 SIPs, partially disapproved two other SIPs and deferred action until December 2023 on two SIPs, which included Wyoming. The EPA action on January 31, 2023 was a necessary prerequisite for the EPA to finalize a proposed Good Neighbor Rule by the March 15, 2023 deadline. The EPA also released a new air quality modeling that indicated two states (including Wyoming), which were previously within scope of the Good Neighbor Rule, no longer exceeded the cross- state ozone emissions threshold. It is likely that the EPA will rely on this new air quality modeling as part of the final Good Neighbor Rule. Based on the new air quality modeling, Wyoming will not be required to purchase additional NOx allowances during the 2023 ozone season. Until the EPA takes action on Wyoming's SIP, which is anticipated in December 2023, we cannot determine our future CSAPR compliance costs or impacts on our operations, but they could be material. However, we anticipate that any costs incurred as a result of the proposed rule would 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. 20 10-K| FORM 10-KHuman Capital Resources Overview We are committed to supporting operational excellence by attracting, motivating, retaining and encouraging the development of a highly qualified and diverse employee team. Our employees’ drive and dedication to their work, and their commitment to the safety of our customers and their fellow employees, allows us to successfully grow and manage our business year over year. Our Team Total employees Women in executive leadership positions (a) Gender diversity (women as a % of total employees) Represented by a union Military veterans Ethnic diversity (non-white employees as a % of total) Number of external hires External hires gender diversity (as a % of total external hires) External hires ethnic diversity (as a % of total external hires) Turnover rate (b) Retirement rate ____________________ (a) (b) As of December 31, 2022 2,982 33% 25% 25% 11% 14% For the year ended December 31, 2022 487 30% 23% 13% 3% As of December 31, 2021 2,884 30% 26% 25% 14% 12% For the year ended December 31, 2021 214 25% 20% 11% 3% Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title. Includes voluntary and involuntary separations but excludes internships. Total Employees Electric Utilities Gas Utilities Corporate and Other Total Number of Employees As of December 31, 2022 442 1,226 1,314 2,982 At December 31, 2022, approximately 19% of our total employees and 21% 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, 2022, 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. Utility Colorado Electric South Dakota Electric Wyoming Electric Total Electric Utilities Iowa Gas Kansas Gas Nebraska Gas Nebraska Gas Wyoming Gas Wyoming Gas Total Gas Utilities Total Number of Employees 105 130 35 270 Union Affiliation IBEW Local 667 IBEW Local 1250 IBEW Local 111 Expiration Date of Collective Bargaining Agreement April 15, 2023 March 31, 2027 June 30, 2024 IBEW Local 204 Communications Workers of America, AFL-CIO Local 6407 IBEW Local 244 CWA Local 7476 IBEW Local 111 CWA Local 7476 January 31, 2026 December 31, 2024 March 13, 2025 October 30, 2023 June 30, 2024 October 30, 2023 129 18 83 137 15 82 464 734 21 10-KFORM 10-K | Attraction Attracting talent to join our team is critical to our ability to serve over 1.3 million customers safely and efficiently. We continuously evaluate our recruitment strategies to determine their effectiveness to attract and build a high-performing, diverse workforce. Our diversity recruiting strategies support our efforts to attract qualified individuals with targeted efforts to reach underrepresented talent pools. Our internship program and our partnerships and participation in outreach programs with local schools and colleges attract students to careers in energy. Our commitment to equitable and inclusive hiring practices, including pay equity, further supports our vision of attracting, developing and retaining a high-performing workforce driven by improving life with energy. Diversity & Inclusion We believe in the benefits of diversity, equity and inclusion. We believe that a diverse workforce will assist us in executing our strategic business plans, including our growth strategy. Workforce diversity trends, which include gender and diverse new hires, promotions and turnover, are monitored at regular intervals throughout the year. Development and Retention Retaining and developing team members is critical to our continued success. Our retention efforts include competitive compensation programs, monitoring employee engagement, career development resources for all employees and internal training programs. Our compensation programs are designed to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective and legally compliant. We continuously monitor employee engagement through bi-annual engagement surveys and quarterly pulse surveys. Every leader is responsible for creating and implementing an action plan based on their team’s engagement survey results. Our career development resources include management onboarding, leadership development programs, mentoring programs, individual development assessments 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 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. We are committed to consistently outperforming utility industry averages in key safety metrics. Meetings of three or more employees begin with a safety share, a practice which contributes to keeping safety top of mind. Since 2009, we have reduced workplace injuries by more than 75% and continue to see long-term, sustained improvements in our safety practices and performance. Total Case Incident Rate (incidents per 200,000 hours worked) Preventable Motor Vehicle Incident Rate (vehicle accidents per 1 million miles driven) % of injuries reported within 1 day For the year ended December 31, 2022 1.39 1.33 90.8% 22 10-K| FORM 10-K ITEM 1A. RISK FACTORS 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 continued success depends, in significant part, on our ability to execute our strategic business plans, including our growth strategy. Our plans and strategy include building sustainable operations and supporting the Energy Transition; consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operational efficiencies. 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 plans. 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: availability of low cost capital to fund projects, weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, impacts of supply chain disruptions on availability and cost of materials, governmental approvals and permitting, regulatory cost recovery and return on investment. An inability to successfully and timely adapt to changing conditions and execute our strategic plans 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 Electric and Gas 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 Electric and Gas 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. 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. 23 10-KFORM 10-K |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 costs of operation for existing facilities or impede the development of new facilities. There is significant uncertainty regarding if and when new climate legislation, regulations or administrative 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 natural gas, and potential increased 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. 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. To date, we have been successful in resolving or defending most of these challenges. 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 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. Changes in Federal tax law may significantly impact our business. 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, 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. Our business, financial condition, results of operations and prospects may be materially adversely affected due to adverse results of litigation. Material legal proceedings are summarized in Note 3 of Notes to Consolidated Financial Statement in this Annual Report on Form 10-K. Unfavorable resolution of legal or administrative proceedings in which we are involved or other future legal or administrative proceedings could have an adverse effect on our financial operating results, including earnings, cash flow and liquidity. 24 10-K| FORM 10-KOPERATING RISKS Failure to attract and retain an appropriately qualified workforce could have a negative impact on our operations and long-term business strategy. Recent trends, such as higher turnover, a competitive and tight labor market and an aging workforce may lead to higher costs and increased risk of negative outcomes for safety, compliance, customer service, and operations. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2022, approximately 19% of our employees were eligible for retirement. Our ability to avoid or minimize supply interruptions, work stoppages and labor disputes is also a risk with approximately 25% of our employees represented by unions. Failure to hire and retain qualified employees, including the ability to transfer significant internal historical knowledge and expertise to new employees, may adversely affect our ability to manage and operate our business. If we are unable to successfully attract and retain an appropriately qualified workforce and maintain satisfactory collective bargaining agreements, safety, service reliability, customer satisfaction and our results of operations could be adversely affected. Our plans and strategy include building sustainable operations and supporting the Energy Transition; consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operating efficiencies. As part of our strategic plan, we will need to attract and retain personnel who are qualified to implement our strategy and may need to retrain or re-skill certain employees to support our long-term objectives. 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 performance. To the extent weather conditions are affected by climate change, fluctuations in customers’ energy usage could be magnified. Climate change may lead to increased intensity and frequency of storms, resulting in increased likelihood of fire, wind and extreme temperature events. Severe weather events, such as snow and ice storms (e.g., Winter Storm Uri), fire, and strong winds could negatively 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. Unmitigated impacts of 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) intended to reduce GHG emissions. 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 sustainable companies and consumers preference for renewable energy could impact our reputation and overall access to capital and/or adequate insurance policies. 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, 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. railroad labor union strikes), increased environmental threats from weather-related disasters, rising demand for raw materials associated with the Energy Transition and/or geopolitical unrest (e.g. Russian invasion of Ukraine). An inability to successfully manage challenges in our supply chain network could materially affect our financial operating results including earnings, cash flow and liquidity. 25 10-KFORM 10-K |Cyberattacks, terrorism, or other malicious acts targeting our key technology systems could disrupt our operations or lead to a loss or misuse of confidential and proprietary information. 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. Cyberattacks, 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. Recent geopolitical conflicts (e.g. Russia's invasion of Ukraine) have increased the risk of cyberattack. Any disruption of these 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 Utility Regulation Characteristics above, in 2021 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 cyberattacks, to continue to modify or enhance protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. Any failure to comply with such government regulations or failure in our cybersecurity protective measures may result in enforcement actions that may have a material adverse effect on our business, results of operations and financial condition. In addition, there is no certainty that costs incurred related to securing against threats will be recovered through rates. We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. Despite our implementation of security measures and safeguards, all of our technology systems may still be vulnerable to disability, failures or unauthorized access. 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, 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 above); Acts of sabotage, terrorism or other malicious 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 could negatively impact our results of operations; 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 results of 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. The cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities could negatively impact our results of operations; 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 and our results of operations; 26 10-K| FORM 10-K• • • • • 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, could negatively impact our results of operations; 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 could negatively impact our results of operations; Supply chain challenges (discussed above); Workforce capabilities and labor relations (discussed above); and 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 incur significant costs or 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. 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. Our results of operations and cash flows are affected by the demand for electricity and natural gas, which 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. Our utility businesses are impacted by economic cycles and the competitiveness of the commercial and industrial customers we serve. Any economic downturn, inflation, disruption of financial markets, or reduced incentives by state government for economic development could adversely affect the financial condition of our customers and demand for their products or services. 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 utility businesses 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 utility operations 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. Unusually mild summers and winters, therefore, could have an adverse effect on our financial operating results, including earnings, cash flow and liquidity. Our customers' focus on energy conservation. 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 of energy and delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system 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. 27 10-KFORM 10-K |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, 2022. 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 forced 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. Widespread public health crises and epidemics or pandemics could negatively affect our business operations, results of operations, financial condition and cash flows. We are subject to the impacts of widespread public health crises, epidemics and pandemics, including, but not limited to, impacts on the global, national or local economies, capital and credit markets, our workforce, customers and suppliers. There is no assurance that our businesses will be able to operate without material adverse impacts depending on the nature of the public health crisis, epidemic or pandemic. The ultimate severity, duration and impact of public health crises, epidemics and pandemics cannot be predicted. Additionally, there is no assurance that vaccines, or other treatments, are or will be widely available or effective, or that the public will be willing to participate, in an effort to contain the spread of disease. Actions taken in response to such crises by federal, state and local government or regulatory agencies may adversely affect our financial operating results including earnings, cash flow and liquidity. 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; BBB+ (Stable outlook) by S&P; and BBB+ (Stable outlook) by Fitch. 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. 28 10-K| FORM 10-KOur 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. 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. 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. 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. Market performance or changes in key valuation assumptions could require us to make significant unplanned contributions to our pension plan and other postretirement 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 postretirement 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 8 of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information 29 10-KFORM 10-K |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 substantially 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 benefit costs continue to rise, however, there is no assurance that the utility commissions will allow recovery of these increased costs. The rising employee benefit costs, or inadequate recovery of such costs, may adversely affect our financial operating results including earnings, cash flow, or liquidity. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES 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. ITEM 3. LEGAL PROCEEDINGS 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. ITEM 4. MINE SAFETY DISCLOSURES Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95 of this Annual Report. 30 10-K| FORM 10-KINFORMATION ABOUT OUR EXECUTIVE OFFICERS Linden R. Evans, age 60, has been President and Chief Executive Officer since January 1, 2019, President and Chief Operating Officer from 2016 through 2018, and President and Chief Operating Officer - Utilities from 2004 through 2015. Mr. Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and Associate Counsel from 2001 to 2003. Mr. Evans has 21 years of experience with the Company. Brian G. Iverson, age 60, has been Senior Vice President, General Counsel and Chief Compliance Officer since August 26, 2019. He served as Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary from February 1, 2019 to August 26, 2019, Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019, Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel from 2004 to 2008. Mr. Iverson has 19 years of experience with the Company. Erik D. Keller, age 59, joined the Company as Senior Vice President and Chief Information Officer on July 27, 2020. Prior to joining the company, he was an Information Technology consultant to Ontic Inc., a global provider of parts and services for legacy aerospace platforms, from January 2020 to July 2020, and Chief Information Officer for BBA Aviation, a global aviation support and aftermarket services provider, from February 2012 to January 2020. Richard W. Kinzley, age 57, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 23 years of experience with the Company. As previously announced, Mr. Kinzley intends to retire in mid-2023 He will continue to serve in his current position until March 31, 2023, after which Kimberly F. Nooney, the Company’s Vice President, Treasurer, will succeed Mr. Kinzley and Mr. Kinzley will continue as Senior Vice President until his retirement to provide for a reasonable transition period. Jennifer C. Landis, age 48, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 21 years of experience with the Company. 31 10-KFORM 10-K |PART II ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of January 31, 2023, we had 3,403 common shareholders of record and 70,195 beneficial owners, representing all 50 states, the District of Columbia and 6 foreign countries. COMPARATIVE STOCK PERFORMANCE The following performance graph compares the cumulative total stockholder return from Black Hills Corporation common stock, as compared with the S&P 500 Index, S&P 500 Utilities index, and our Performance Peer Group for the past five years. The graph assumes an initial investment of $100 on December 31, 2017, and assumes all dividends were reinvested. The stockholder return shown below for the five-year historical period may not be indicative of future performance. The information in this "Comparative Stock Performance" section shall not be deemed to be "soliciting material" or to be "filed" with the Securities and Exchange Commission or subject to Regulation 14A or 14C, or to the liabilities of Section 18 of the Securities Exchange Act of 1934. Black Hills Corporation S&P 500 S&P 500 Utilities Performance Peer Group (a) ____________________ (a) Years ended December 31, 2017 2018 2019 2020 2021 2022 $ $ 100.00 100.00 100.00 100.00 $ 107.97 95.62 104.11 103.67 $ 138.83 125.72 131.54 130.41 $ 112.34 148.85 132.18 128.89 $ 133.55 191.58 155.53 150.96 137.65 156.88 157.97 152.70 Performance Peer Group represents the Edison Electric Institute Index, which was used in our 2022 Proxy Statement filed with the SEC on March 17, 2022. DIVIDENDS For information concerning dividends, our dividend policy and factors that may limit our ability to pay dividends, see “Key Elements of our Business Strategy” and “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report on Form 10-K. UNREGISTERED SECURITIES ISSUED There were no unregistered securities sold during 2022. 32 10-K| FORM 10-KSECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS See Item 12 in this Annual Report on Form 10-K for information regarding Securities Authorized for Issuance Under Equity Compensation Plans. ISSUER PURCHASES OF EQUITY SECURITIES The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2022: Period October 1, 2022 - October 31, 2022 November 1, 2022 - November 30, 2022 December 1, 2022 - December 31, 2022 Total Total Number of Shares Purchased (a) Average Price Paid per Share 2 $ 294 $ 10,035 $ 10,331 $ 67.73 64.75 68.87 68.75 Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs — — — — — — — — ____________________ (a) Shares were acquired under the share withholding provisions of the Amended and Restated 2015 Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans. ITEM 6. (RESERVED) 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 more than 1.3 million customers and 800+ communities we serve. Our vision to be the Energy Partner of Choice directs our strategy to invest in the safety, sustainability and growth of our eight-state service territory, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming, and to meet our essential objective of providing safe, reliable and cost-effective electricity and natural gas. 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 139 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. A critical component of our strategy involves sustainable operations and supporting the Energy Transition. How we operate our company for the social good has never been more important. 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. In addition, we are committed to a more sustainable future by better managing our impacts to the planet, whether that is water usage, recycling, biodiversity, or other important measures, and remaining focused on our human capital through diversity and inclusion. Our emphasis is on consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operating efficiencies. These areas of focus will present the company with significant investment needs as we harden our infrastructure systems, meet customer growth and fulfill customer expectations for cleaner energy services. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective solutions. 33 10-KFORM 10-K |Key Elements of our Business Strategy 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 1,482 MW of generation capacity and 9,024 miles of transmission and distribution lines and our Gas Utilities own and operate approximately 47,000 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. We rigorously comply with all applicable federal, state and local regulations and strive to consistently meet industry best practice standards. A key component of our modernization effort is the development of programs by our Electric and Gas Utilities to systematically and proactively replace aging infrastructure on a system-wide basis. 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. In alignment with this program, in November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The 260-mile, multi-phase transmission expansion project will provide customers long-term price stability and greater flexibility as power markets develop in the Western States. On October 11, 2022, the WPSC approved a CPCN submitted by Wyoming Electric to construct the transmission expansion project. Construction of the project is expected to take place in multiple phases or segments from 2023 through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems. 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, 2022, we estimate our five-year capital investment to be approximately $3.5 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 2022 and forecasted capital expenditures for the next five years from 2023 through 2027 are as follows (in millions). Minor differences may result due to rounding. Actual (a) Forecasted Capital Expenditures By Segment: (in millions) Electric Utilities Gas Utilities Corporate and Other Incremental projects (b) Total $ $ 2022 2023 2024 2025 2026 2027 243 349 5 - 598 $ $ 212 386 17 - 615 $ $ 348 452 19 - 819 $ $ 268 412 20 - 700 $ $ 184 393 19 104 700 $ $ 163 444 18 75 700 (a) (b) 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. These represent projects that 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. 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 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. 34 10-K| FORM 10-KRate Base Generation: We continue to believe that customers are best served when the power generation facilities are owned and rate-based by our Electric Utilities. 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; 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, except Northern Iowa Windpower, are contracted to our Electric Utilities under long-term contracts and are located at our utility-generating complexes, including Busch Ranch, Pueblo Airport Generation, and the Gillette, Wyoming energy complex, and are 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 coal mine. We operate and own majority interests in four of the five power plants and own 20% of the fifth power plant. Our coal mine 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., $1.09 per MMBtu for year ended December 31, 2022) 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. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck. Supporting the Energy Transition by proactively integrating alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. 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 includes Scope 1 emissions from distribution system main and service lines. On August 31, 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubles the previous target of a 50% reduction by 2035 and expands 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. Since 2005, we have reduced GHG emissions intensity from our Gas Utilities distribution system mains and services by more than 33% and achieved a one-third reduction from our Electric Utilities (a nearly 10% reduction since announcing our goal in 2020 for our Electric Utilities). We have plans in place today, without reliance on future technologies, to achieve our corporate climate goals calling for a 40% reduction in greenhouse gas emissions intensity from our electric utility operations by 2030 and 70% by 2040. Additionally, our Electric Utilities have reduced nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Colorado Electric has achieved a nearly 50% reduction in GHG emissions since 2005 and is on track to reach the State of Colorado’s 80% carbon reduction goal by 2030. 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. 35 10-KFORM 10-K |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. To support this interest: • • • We created the Renewable Ready program for South Dakota Electric and Wyoming Electric customers. In support of this program, we created and received approvals for new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmental customer requests for renewable energy resources. To meet the renewable energy commitments under the new tariffs, in November 2020, we completed construction and placed into service the Corriedale wind project, a 52.5 MW wind energy project near Cheyenne, Wyoming. In June 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. The IRP outlines a range of options for the two electric utilities 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. The IRP’s preferred options for South Dakota Electric in the near-term planning period through 2026 are the addition of 100 MW of renewable generation, the conversion of Neil Simpson II to natural gas in 2025 and consideration of up to 10 MW of battery storage. On January 13, 2023, Colorado Electric submitted a unanimous settlement for its Clean Energy Plan filed May 25, 2022, with the CPUC. If approved, the plan would add approximately 400 MW of new clean energy resources needed to reduce carbon emissions 80% by 2030. A final decision from the CPUC is expected in the first quarter of 2023. 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. Inflation Reduction Act The IRA, signed into law by President Biden on August 16, 2022, features $370 billion in 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; include energy storage, EVs, RNG, and carbon capture and sequestration; and allow for the transferability of clean energy tax credits on existing and qualifying new facilities. We see the IRA as generally supportive of our Energy Transition strategy and as having the potential to drive increased value for our customers and shareholders. We are still evaluating the impacts of the IRA provisions on our future capital projects. Explore opportunities as an energy solutions provider. Another strategic initiative is to grow our business through creative energy solutions with new customers and partnerships. We see value creation by recruiting new customers and expanding existing partnerships with data centers and blockchain opportunities; exploring energy markets such as RTOs; and expanding our transmission capabilities. A few recent examples of our initiatives to grow our business through creative solutions include: • • In 2022, Wyoming Electric entered into two new PPAs with third parties to purchase up to 106 MW of wind energy and up to 150 MW of solar energy, upon construction of new renewable generation facilities (to be owned by third parties) which are expected to be completed by the end of 2023. The renewable energy from these PPAs will be used to serve our expanding partnerships with data centers. We have supported enabling legislation in Wyoming for the growing blockchain businesses while implementing our own BCIS Tariff to serve these customers. In June 2022, Wyoming Electric completed its first agreement, a five-year agreement to deliver up to 45 MW with an option to expand service up to 75 MW to a new customer in Cheyenne, Wyoming, under this Tariff. Energy will be sourced through the electric energy market and delivered through our Electric Utilities’ infrastructure. Under the agreement, the customer will be responsible for costs of service, and the load will be interruptible to prioritize the needs of Wyoming Electric’s existing retail customers. 36 10-K| FORM 10-K• During the first quarter of 2022, Colorado Electric agreed to join SPP’s WEIS Market. On September 26, 2022, South Dakota Electric and Wyoming Electric also agreed to join the WEIS Market. South Dakota Electric and Wyoming Electric will join Colorado Electric in integrating into the WEIS Market in April 2023 and expects to continue studying long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market. Additionally, we are pursuing two important initiatives in the form of sustainable energy solutions for electric vehicles and RNG. These two programs support our near-term sustainable strategy and contribute to the achievement of our aspirational greenhouse gas emissions reduction goals. • • Electric Vehicles: We expect EV market share to increase over the next one to three years, commensurate with a significant uptick in vehicle range and product offerings and marked decrease in EV purchase prices. In addition to future load growth opportunities, we are investigating behind-the-meter solutions for customers. In January 2022, the CPUC approved a transportation electrification plan for Colorado Electric including the implementation of EV and charger rebates and EV rates. Renewable Natural Gas: In 2021, we developed a voluntary RNG and carbon offset program to help our residential and small business natural gas customers offset up to 100% or more of the emissions associated with their own natural gas usage. In 2022, we filed for approval to launch these programs in three of our states, receiving regulatory approval for the program from both the KCC and the NPSC in Q4 2022. We intend to begin offering the program to customers in 2023, as well as completing additional regulatory filings with commissions in our other natural gas states. Our teams are also evaluating multiple RNG investment opportunities and exploring value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with six projects actively injecting RNG into our natural gas system. In 2022, we created a new non-regulated business, BHERR, which will drive new growth by investing capital into infrastructure assets that provide a pathway for RNG to enter the market. BHERR builds on our expertise and experience in both RNG and natural gas asset operations, and aligns with market demand and the path to a cleaner energy future. Execute disciplined capital allocation and explore small strategic opportunities. We are planning a disciplined capital investment program of approximately $600 million during the next year to improve our cash flows and reduce our debt to total capitalization ratio. By carefully managing capital, we plan to continue to strengthen our balance sheet and enhance our liquidity. With this goal in mind, we will continue to evaluate smaller scale acquisitions of private utility infrastructure systems and small municipal systems that can be easily incorporated into our existing utility systems. 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. 2022 represented our 52nd consecutive year of increasing dividends. In January 2023, our Board of Directors declared a quarterly dividend of $0.625 per share, equivalent to an annual dividend of $2.50 per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 55% to 65% of net income. 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. 37 10-KFORM 10-K |Macroeconomic Trends Recent Developments We are monitoring adverse macroeconomic trends including potential recession, inflationary pressures on the prices of commodities, materials, outside services and employee costs; supply chain constraints; rising interest rates and a competitive and tight labor market. To date, we have experienced moderate net impacts from these trends. However, if current macroeconomic conditions continue or deteriorate in 2023, adverse impacts to our businesses may be magnified. Higher commodity energy costs continue to have an effect on customer bills and deferred energy costs. Our utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer, which mitigates our exposure. Customer billing rates are adjusted periodically to reflect changes in our cost of energy. As a result of increased customer billings, we incurred higher bad debt expense. Higher deferred energy costs and rising interest rates have led to increased interest expense and increased short-term variable rate borrowings, which include our Revolving Credit Facility and CP Program. However, the increased interest expense for the year ended December 31, 2022 was limited since 88% of our debt at December 31, 2022, is fixed rate debt. Rising discount rates and recent capital markets volatility had a limited impact to the unfunded status of the BHC Pension Plan when compared to the prior year. We are proactively managing increased costs of materials and supply chain disruptions to achieve our forecasted capital investment targets. To support our 2023 capital investment program, we have contracted materials for the majority of our largest forecasted projects. We continue to forecast multi-year key material requirements with suppliers to enhance predictable material availability, challenge vendor price increases to ensure best value and cost transparency and invest in our distribution network to ensure the safety and continuity of our system. We have also evaluated each of our forecasted projects and will prioritize depending on future constraints. Project delays may occur if costs rise significantly or if materials are not available. Inflationary pressures and supply chain constraints have increased our operating expenses, which included higher outside services expenses (i.e., consulting and contractor rates), materials expenses and vehicle expenses driven by higher fuel prices. We are faced with increased competition for employee and contractor talent in the current labor market. To date, we have seen a limited net increase in total employee costs due to increased employee and contractor costs related to attraction and retention of talent mostly offset by workforce attrition. More detailed discussion of the future uncertainties can be found in Item 1A - Risk Factors. Business Segment Highlights and Corporate Activity 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 Wyoming Electric. See Key Elements of our Business Strategy section above for discussion of recent developments related to Ready Wyoming, Wyoming Electric's BCIS tariff, Colorado Electric's Clean Energy Plan filing, and the Electric Utilities joining the WEIS Market. In December 2022, each of our Electric Utilities set new winter peak loads: • • • On December 22, 2022, Colorado Electric set a new winter peak load of 334 MW, surpassing the previous winter peak of 313 MW set in October 2018. On December 21, 2022, South Dakota Electric set a new winter peak load of 355 MW, surpassing the previous winter peaks of 327 MW set on January 5, 2022 and 326 MW set in February 2021. On December 21, 2022, Wyoming Electric set a new winter peak load of 281 MW, surpassing the previous peaks of 263 MW set on November 17, 2022, 262 MW set on February 23, 2022, 252 MW set on January 5, 2022 and 247 MW set in December 2019. In December 2022, WRDC entered into a new agreement with PacifiCorp, effective January 1, 2023, to continue as the sole supplier of coal (fuel) to the Wyodak Plant through December 31, 2026 with a one-year extension option to December 31, 2027. Pricing and other terms of the new fuel supply agreement are similar to the previous contract which ended December 31, 2022. 38 10-K| FORM 10-K• In July 2022, South Dakota Electric and Wyoming Electric both set new all-time and summer peak loads: • • On July 21, 2022, Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous peaks of 288 MW set on July 18, 2022, 282 MW set on June 13, 2022 and 274 MW set in July 2021. On July 18, 2022, South Dakota Electric set a new all-time and summer peak load of 403 MW, surpassing the previous summer peak of 397 MW set in July 2021. 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 and RMNG. See Key Elements of our Business Strategy section above for discussion of recent developments related to our Gas Utilities' voluntary RNG and carbon offset programs. Corporate and Other • On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3-million-acre concession award in Costa Rica that was acquired by a BHC subsidiary in 2003. We believe we have meritorious defenses to the verdict and have appealed the verdict. See additional information in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information. Results of Operations Our discussion and analysis for the year ended December 31, 2022 compared to 2021 is included herein. For discussion and analysis for the year ended December 31, 2021 compared to 2020, 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, 2021, which was filed with the SEC on February 15, 2022. Segment information does not include intercompany eliminations and 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 Operating income (loss): Electric Utilities Gas Utilities Corporate and Other Operating Income Interest expense, net Impairment of investment Other income (expense), net Income tax (expense) Net income Net income attributable to non-controlling interest Net income available for common stock Total earnings per share of common stock, Diluted For the Years Ended December 31, 2021 (in thousands, except per share amounts) 2020 2022 $ $ $ 214,258 244,160 (3,174) 455,244 (160,989) — 1,708 (25,205) 270,758 (12,371) 258,387 3.97 $ $ $ 202,676 211,157 (4,404) 409,429 (152,404) — 1,404 (7,169) 251,260 (14,516) 236,744 3.74 $ $ $ 210,974 215,889 1,440 428,303 (143,470) (6,859) (2,293) (32,918) 242,763 (15,155) 227,608 3.65 39 10-KFORM 10-K | 2022 Compared to 2021 The variance to the prior year included the following: • • • • • • Electric Utilities’ operating income increased $12 million primarily due to increased rider revenues, prior year impacts related to the Wygen I unplanned outage and Colorado Electric’s TCJA-related bill credits to customers, increased transmission services revenue and off-system excess energy sales partially offset by higher operating expenses and lower pricing on the new Wygen I PPA; Gas Utilities’ operating income increased $33 million primarily due to new rates and rider recovery, favorable weather, carrying costs on our Winter Storm Uri regulatory asset, prior year Black Hills Energy Services Winter Storm Uri costs, customer growth partially offset by higher operating expenses; Corporate and Other expenses decreased $1.2 million primarily due to an allocation of a 2020 employee cost true- up in the first quarter of 2021, which was offset in our business segments; Interest expense increased $8.6 million due to higher interest rates on higher short-term debt balances; Income tax expense increased $18 million driven by higher pre-tax income and a higher effective tax rate primarily due to prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits and decreased flow-through tax benefits driven by prior year repairs and gain deferral partially offset by tax benefits from various state tax rate changes; and Net income attributable to non-controlling interest decreased $2.1 million due to lower net income from Black Hills Colorado IPP primarily driven by lower fired-engine hours and a planned outage. Segment Operating Results Non-GAAP Financial Measure The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure, Electric and Gas Utility margin, that is considered a “non-GAAP financial measure.” 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 property and production 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. 40 10-K| FORM 10-KElectric Utilities Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands): Revenue: Electric - regulated Other - non-regulated Total revenue Fuel and Purchased Power: Electric - regulated Other - non-regulated Total fuel and purchased power 2022 2021 2022 vs 2021 Variance 2020 2021 vs 2020 Variance $ 852,141 48,021 900,162 $ 800,747 41,511 842,258 $ 51,394 6,510 57,904 $ 699,712 39,145 738,857 $ 101,035 2,366 103,401 261,726 4,558 266,284 244,504 3,514 248,018 17,222 1,044 18,266 136,374 2,198 138,572 108,130 1,316 109,446 Electric Utility margin (non-GAAP) 633,878 594,240 39,638 600,285 (6,045) Operations and maintenance Depreciation and amortization Total operating expenses 283,654 135,966 419,620 260,036 131,528 391,564 23,618 4,438 28,056 265,679 123,632 389,311 (5,643) 7,896 2,253 Operating income $ 214,258 $ 202,676 $ 11,582 $ 210,974 $ (8,298) 2022 Compared to 2021 Electric Utility margin increased over the prior year as a result of: New rates and rider recovery Prior year TCJA-related bill credits (a) Prior year Wygen I unplanned outage Transmission services and off-system excess energy sales Integrated Generation (b) Weather Retail load growth Lower pricing on new Wygen I PPA Other $ $ (in millions) 11.2 9.3 8.5 7.6 5.7 3.2 1.2 (8.5) 1.4 39.6 (a) (b) In February 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income. Primarily driven by favorable market pricing on contracts and off-system sales. Operations and maintenance expense increased due to $10.3 million of higher generation-related expenses primarily due to higher fuel and materials costs and increased royalties on higher mining revenues, $4.5 million of higher outside services expenses primarily driven by higher contractor and consultant rates, $3.4 million of increased property taxes due to an expiration of an abatement and a higher asset base driven by recent capital expenditures, $3.4 million of higher cloud computing licensing costs, and $1.1 million of increased bad debt expense primarily attributable to higher customer billings. Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures. 41 10-KFORM 10-K |Operating Statistics For the year ended December 31, Revenue (in thousands) 2021 2022 2020 2022 Quantities Sold (MWh) 2021 2020 Residential Commercial Industrial Municipal Subtotal Retail Revenue - Electric Contract Wholesale Off-system/Power Marketing Wholesale Other (a) Total Regulated Non-Regulated (b) Total Revenue and Quantities Sold Other Uses, Losses or Generation, net (c) Total Energy $ $ 246,651 277,981 166,374 20,497 711,503 25,869 48,578 66,191 852,141 48,021 900,162 244,589 275,998 149,040 19,092 688,719 16,128 41,682 54,218 800,747 41,511 842,258 $ 221,530 239,166 131,154 16,860 608,710 17,847 15,511 57,644 699,712 39,145 738,857 1,513,092 2,087,800 1,912,529 159,248 5,672,669 654,016 643,189 — 6,969,874 293,026 7,262,900 450,010 7,712,910 1,494,028 2,075,690 1,751,344 162,903 5,483,965 574,137 638,923 — 6,697,025 269,558 6,966,583 475,280 7,441,863 1,477,515 1,974,043 1,794,795 158,222 5,404,575 492,637 437,288 — 6,334,500 258,399 6,592,899 406,422 6,999,321 (a) (b) (c) Primarily related to transmission revenues from the Common Use System. Includes Integrated Generation and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services. Includes company uses and line losses. For the year ended December 31, Colorado Electric South Dakota Electric Wyoming Electric Integrated Generation $ Total Revenue and Quantities Sold $ $ Electric Revenue (in thousands) 2021 302,896 319,362 180,413 39,587 842,258 2022 321,113 335,211 197,673 46,166 900,162 2020 252,094 280,431 169,179 37,153 738,857 $ $ $ 2022 2,439,954 2,626,175 1,903,745 293,026 7,262,900 Quantities Sold (MWh) 2021 2,574,016 2,389,407 1,733,602 269,558 6,966,583 2020 2,243,034 2,363,776 1,727,690 258,399 6,592,899 Quantities Generated and Purchased by Fuel Type (MWh) Generated: Coal Natural Gas and Oil Wind Total Generated Purchased: Coal, Natural Gas, Oil and Other Market Purchases Wind Total Purchased Total Generated and Purchased For the year ended December 31, 2021 2022 2020 2,708,804 1,454,164 875,843 5,038,811 2,280,776 393,323 2,674,099 7,712,910 2,546,926 1,817,133 842,616 5,206,675 1,866,382 368,806 2,235,188 7,441,863 2,817,846 1,753,568 614,236 5,185,650 1,478,536 335,135 1,813,671 6,999,321 42 10-K| FORM 10-K 43 10-KFORM 10-K | For the year ended December 31,Quantities Generated and Purchased (MWh)202220212020Generated:Colorado Electric474,401412,127265,552South Dakota Electric1,889,9811,980,6601,901,009Wyoming Electric905,796883,596851,522Integrated Generation1,768,6331,842,3772,085,042Total Generated5,038,8115,118,7605,103,125Purchased:Colorado Electric1,005,4461,027,728714,139South Dakota Electric826,392563,603489,457Wyoming Electric757,191643,857610,075Integrated Generation85,07087,91582,525Total Purchased2,674,0992,323,1031,896,196Total Generated and Purchased7,712,9107,441,8636,999,321For the year ended December 31,Degree Days202220212020ActualVariance from NormalActualVariance from NormalActualVariance from NormalHeating Degree Days:Colorado Electric5,5519%5,023(11)%5,103(9)%South Dakota Electric7,4956%6,819(5)%6,910(3)%Wyoming Electric7,0513%6,702(6)%6,771(5)%Combined (a)6,5186%5,974(7)%6,056(6)%Cooling Degree Days:Colorado Electric1,3629%1,24539%1,38454%South Dakota Electric81427%82730%6827%Wyoming Electric70147%60474%59471%Combined (a)1,04018%97340%98541%(a)Degree days are calculated based on a weighted average of total customers by state. For the year ended December 31,Contracted generating facilities availability by fuel type (a)202220212020Coal (b)91.5%86.7%94.3%Natural gas and diesel oil96.1%95.5%84.6%Wind93.7%95.8%95.1%Total availability94.4%93.2%89.2%Wind Capacity Factor34.7%34.0%31.8%(a)Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.(b)2021 included planned outages at Neil Simpson II, Wygen II, and Wygen III and unplanned outages at Wygen I, Neil Simpson II and Wyodak Plant.Gas Utilities Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands): 2022 2021 2022 vs 2021 Variance 2020 2021 vs 2020 Variance Revenue: Natural gas - regulated Other - non-regulated services $ Total revenue $ 1,584,634 84,456 1,669,089 $ 1,051,610 73,255 1,124,865 $ 533,024 11,201 544,224 $ 900,637 74,033 974,670 150,973 (778) 150,195 Cost of natural gas sold: Natural gas - regulated Other - non-regulated services Total cost of natural gas sold Gas Utility margin (non-GAAP) Operations and maintenance Depreciation and amortization Total operating expenses 942,148 22,960 965,108 703,982 345,143 114,679 459,822 480,293 14,445 494,738 630,127 314,810 104,160 418,970 461,855 8,515 470,370 73,855 30,333 10,519 40,852 347,611 7,034 354,645 620,025 303,577 100,559 404,136 132,682 7,411 140,093 10,102 11,233 3,601 14,834 Operating income $ 244,160 $ 211,157 $ 33,003 $ 215,889 $ (4,732) 2022 Compared to 2021 Gas Utility margin increased over the prior year as a result of: New rates and rider recovery Weather Carrying costs on Winter Storm Uri regulatory asset (a) Prior year Black Hills Energy Services Winter Storm Uri costs (b) Customer growth and increased usage per customer Mark-to-market on non-utility natural gas commodity contracts Other $ $ (in millions) 30.0 18.5 17.9 8.2 3.7 (3.3) (1.1) 73.9 (a) (b) In certain jurisdictions, we have commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset increased interest expense. Additionally, the carrying costs accrued during the year ended December 31, 2022 included a one-time, $10.3 million true-up to reflect commission authorized rates. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details. Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri was not recoverable through a regulatory mechanism. Operations and maintenance expense increased due to $11.6 million of higher outside services and materials expenses driven primarily by higher contractor and consultant fees, $5.0 million of increased bad debt expense primarily attributable to higher customer billings, $4.6 million of higher cloud computing licensing costs, $3.2 million of higher property taxes driven by a higher asset base on recent capital expenditures, $2.1 million of higher vehicle expense driven by higher fuel costs, $1.6 million of higher employee-related expenses and $1.2 million increased travel and training expenses. Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures. 44 10-K| FORM 10-KOperating Statistics Revenue (in thousands) For the year ended December 31, 2020 2021 2022 Quantities Sold and Transported (Dth) For the year ended December 31, 2021 2022 2020 Residential Commercial Industrial Other Total Distribution $ $ 940,201 398,585 63,035 8,693 1,410,514 613,475 242,115 33,368 3,816 892,774 $ 527,518 193,017 24,014 582 745,131 66,915,630 32,362,343 7,667,231 — 106,945,204 60,080,805 29,091,657 6,260,235 — 95,432,697 61,962,171 28,784,319 6,881,354 — 97,627,844 Transportation and Transmission 174,120 158,836 155,506 160,917,802 154,570,280 149,062,476 Total Regulated 1,584,634 1,051,610 900,637 267,863,006 250,002,977 246,690,320 Non-regulated Services (a) 84,456 73,255 74,033 — — — Total Revenue and Quantities Sold $ 1,669,089 $ 1,124,865 $ 974,670 267,863,006 250,002,977 246,690,320 (a) Includes Black Hills Energy Services and non-regulated services under the Service Guard Comfort Plan, Tech Services and HomeServe. Revenue (in thousands) For the year ended December 31, 2020 2021 2022 Quantities Sold and Transported (Dth) For the year ended December 31, 2021 2020 2022 Arkansas Gas Colorado Gas Iowa Gas Kansas Gas Nebraska Gas Wyoming Gas Total Revenue and Quantities Sold $ 311,239 320,890 283,938 191,392 384,823 176,807 $ 1,669,089 $ 218,497 208,019 171,673 121,603 273,361 131,712 $ 1,124,865 $ 184,849 186,085 137,982 101,118 246,381 118,255 $ 974,670 32,282,324 34,343,485 40,883,742 38,630,944 85,050,323 36,672,188 267,863,006 31,478,303 32,247,042 38,022,801 34,475,799 81,035,572 32,743,460 250,002,977 28,572,621 32,077,083 36,824,548 33,732,897 80,202,783 35,280,388 246,690,320 Heating Degree Days Arkansas Gas (a) Colorado Gas Iowa Gas Kansas Gas (a) Nebraska Gas Wyoming Gas Combined (b) 2022 For the year ended December 31, 2021 2020 Actual 3,844 6,325 7,037 4,968 6,220 7,644 6,536 Variance From Normal 2% 4% 7% 7% 4% 12% 5% Actual 3,565 5,866 6,239 4,508 5,599 7,074 5,948 Variance From Normal (12)% (11)% (8)% (8)% (9)% (7)% (8)% Actual 3,442 6,068 6,504 4,648 5,853 7,289 6,038 Variance From Normal (15)% (8)% (4)% (5)% (5)% (4)% (6)% (a) (b) Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins. 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. 45 10-KFORM 10-K | Corporate and Other Corporate and Other operating results for the years ended December 31 were as follows (in thousands): (in thousands) 2022 2021 2022 vs 2021 Variance 2020 2021 vs 2020 Variance Operating income (loss) $ (3,174) $ (4,404) $ 1,230 $ 1,440 $ (5,844) 2022 Compared to 2021 The variance in Operating income (loss) was primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments. Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense) (in thousands) 2022 2021 2022 vs 2021 Variance 2020 2021 vs 2020 Variance Interest expense, net Impairment of investment Other income (expense), net Income tax (expense) 2022 Compared to 2021 Interest expense, net $ (160,989) $ (152,404) $ (8,585) $ (143,470) $ — 1,708 (25,205) — 1,404 (7,169) — 304 (18,036) (6,859) (2,293) (32,918) (8,934) 6,859 3,697 25,749 The increase in Interest expense, net was due to higher interest rates on higher short-term debt balances. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details. Other income (expense), net Other income (expense), net was comparable to the prior year primarily due to lower costs for our non-qualified benefit plans which were driven by market performance mostly offset by a prior year recognition of death benefits from Company-owned life insurance and higher non-service pension costs primarily driven by a higher discount rate. Income tax benefit (expense) Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the year ended December 31, 2022, the effective tax rate was 8.5% compared to 2.8% in 2021. The higher effective tax rate was primarily due to $10 million of prior year tax benefits from Colorado Electric TCJA-related bill credits to customers (which were offset by reduced revenue) and $5.4 million decreased flow-through tax benefits driven by prior year repairs and gain deferral partially offset by $4.0 million of current year tax benefits from various state rate changes, and $1.8 million of increased tax benefits from federal PTCs driven by a current year PTC rate increase (inflation adjustment). See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details. 46 10-K| FORM 10-KOVERVIEW Liquidity and Capital Resources Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our operating activities, five-year 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 financial position as of December 31 (dollars in thousands): Financial Position Summary Cash and cash equivalents Restricted cash and equivalents Notes payable Current maturities of long-term debt Long-term debt (a) Stockholders’ equity Ratios Long-term debt ratio (b) Total debt ratio (c) 2022 21,430 5,555 535,600 525,000 3,607,340 2,994,913 $ $ $ $ $ $ 2021 8,921 4,889 420,180 — 4,126,923 2,787,094 $ $ $ $ $ $ 55% 61% 60% 62% (a) (b) (c) Carrying value of long-term debt is net of deferred financing costs. Long-term debt as a percentage of long-term debt and stockholders' equity combined. Total debt (notes payable, current maturities of long-term debt and long-term debt) as a percentage of total debt and stockholders' equity combined. CASH FLOW ACTIVITIES The following tables summarize our cash flows for the years ended December 31 (in thousands): Operating Activities: Cash earnings (net income plus non-cash adjustments) $ Changes in certain operating assets and liabilities: Accounts receivable and other current assets Accounts payable and accrued liabilities Regulatory assets and liabilities Contributions to defined benefit pension plans Other operating activities Net cash provided by (used in) operating activities $ 2022 Compared to 2021 2022 566,392 $ 2021 527,705 $ 2022 vs. 2021 38,687 $ 2020 549,092 2021 vs. 2020 (21,387) (259,851) 89,405 203,869 33,423 — (15,014) 584,801 $ (78,877) $ 10,660 (524,220) (592,437) — 167 (64,565) $ (180,974) 78,745 728,089 625,860 — (15,181) 649,366 $ (8,088) 24,659 (15,753) 818 (12,700) 4,653 (70,789) (13,999) (508,467) (593,255) 12,700 (4,486) 541,863 $ (606,428) Cash earnings (income from continuing operations plus non-cash adjustments) were $39 million higher than prior year primarily due to increased Electric and Gas Utility margins due to new rates and rider revenues and prior year impacts from Winter Storm Uri. 47 10-KFORM 10-K |Net inflows from changes in certain operating assets and liabilities were $626 million higher than prior year, primarily attributable to: • • • Cash inflows increased by approximately $728 million primarily as a result of changes in our regulatory assets and liabilities primarily driven by prior year incremental fuel, purchased power and natural gas costs due to Winter Storm Uri and current year recovery of a portion of Winter Storm Uri incremental and carrying costs from customers; Cash outflows increased by approximately $181 million primarily as a result of changes in accounts receivable and other current assets driven by increased revenue due to higher commodity prices and colder weather and increased purchases of natural gas in storage; Cash inflows increased by approximately $79 million as a result of changes in accounts payable and other current liabilities driven by payment timing related to natural gas and power purchases and other working capital requirements; Cash outflows increased $15.2 million from other operating activities primarily due to higher cloud computing licensing costs, increased payments on settled commodity derivatives and higher preliminary survey charges. Investing Activities: Capital expenditures Other investing activities Net cash provided by (used in) investing activities $ $ (604,365) $ 485 (603,880) $ (677,492) $ 13,262 (664,230) $ 73,127 $ (12,777) 60,350 $ (767,404) $ 5,740 (761,664) $ 89,912 7,522 97,434 2022 2021 2022 vs. 2021 2020 2021 vs. 2020 2022 Compared to 2021 Capital expenditures of approximately $604 million in 2022 compared to $677 million in 2021. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas and Electric Utilities; and Cash inflows decreased $13 million for other investing activities which was primarily driven by prior year sales of transmission assets and facilities, none of which were individually material. Financing Activities: Dividends paid on common stock Common stock issued Short-term and long-term debt borrowings, net Distributions to non-controlling interests Other financing activities Net cash provided by (used in) financing activities 2022 Compared to 2021 2022 2021 2022 vs. 2021 $ $ (156,723) $ 90,044 115,420 (17,418) 931 32,254 $ (145,023) $ 118,979 777,704 (15,749) (4,045) 731,866 $ (11,700) $ (28,935) (662,284) (1,669) 4,976 (699,612) $ 2020 (135,439) $ 99,278 275,943 (15,839) (7,061) 216,882 $ 2021 vs. 2020 (9,584) 19,701 501,761 90 3,016 514,984 Net cash provided by financing activities decreased $700 million primarily due to prior year financing activities related to Winter Storm Uri. 48 10-K| FORM 10-KCAPITAL RESOURCES Short-term Debt Revolving Credit Facility and CP Program We have a $750 million Revolving Credit Facility that matures on July 19, 2026, with two one-year extension options (subject to consent from lenders). This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment. 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 our other utilities 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. Covenant Requirements The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in compliance with these covenants as of December 31, 2022. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. Equity Shelf Registration We have a shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the shelf registration statement does not limit our issuance capacity, our ability to issue securities is limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions imposed by federal and state regulatory authorities. The shelf registration expires in August 2023. Our articles of incorporation authorize the issuance of 100 million shares of common stock and 25 million shares of preferred stock. As of December 31, 2022, we had approximately 66 million shares of common stock outstanding and no shares of preferred stock outstanding. ATM Our ATM allows us to sell shares of our common stock with an aggregate value of up to $400 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. For additional information regarding equity, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 49 10-KFORM 10-K |Future Financing Plans We will continue to assess debt and equity needs to support our capital investment plans and other strategic objectives. 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, the issuance of common stock under our ATM program or in an opportunistic block trade. In the first quarter of 2023, we plan to re-finance a portion of our short-term borrowings into long-term debt. We also plan to re-finance our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date. Additionally, we plan to renew our ATM and shelf registration at or before shelf expiration in August 2023. 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, 2022: Rating Agency S&P (a) Moody’s (b) Fitch (c) Senior Unsecured Rating BBB+ Baa2 BBB+ Outlook Stable Stable Stable (a) (b) (c) On August 26, 2022, S&P reported BBB+ rating and maintained a Stable outlook. On December 20, 2022, Moody's reported our Baa2 rating and maintained a Stable outlook. On October 6, 2022, Fitch reported BBB+ rating and maintained a Stable outlook. Certain fees and interest rates under our Revolving Credit Facility are based on our credit ratings at all three rating agencies. If all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level below. Therefore, if Fitch or S&P downgrades our senior unsecured debt, we will be required to pay higher fees and interest rates under our Revolving Credit Facility. The following table represents the credit ratings of South Dakota Electric at December 31, 2022: S&P (a) Fitch (b) Rating Agency (a) (b) On March 31, 2022, S&P reported A rating. On October 6, 2022, Fitch reported A rating. Senior Secured Rating A A We do not have any trigger 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. 50 10-K| FORM 10-KOur 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 $35 million as of December 31, 2022, compared to $20 million as of December 31, 2021. The increase in the unfunded status of the Pension Plan was primarily driven by an increase in the discount rate. We do not have required contributions and we do not expect to make contributions to our Pension Plan in 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 25, 2023, our Board of Directors declared a quarterly dividend of $0.625 per share, equivalent to an annual dividend rate of $2.50 per share. The table below provides our dividends paid (in thousands), dividend payout ratio and dividends paid per share for the three years ended December 31: Common Stock Dividends Paid Dividend Payout Ratio Dividends Per Share Our three-year compound annualized dividend growth rate was 5.5%. Collateral Requirements 2022 156,723 61% 2.41 2021 145,023 61% 2.29 2020 135,439 60% 2.17 $ $ $ $ $ $ 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, 2022, 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, 2022 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. 51 10-KFORM 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, 2022 and 2021, we had total regulatory assets of $653 million and $797 million, respectively, and total regulatory liabilities of $519 million and $503 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. 52 10-K| FORM 10-K97% 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 and for which the CODM regularly reviews the operating results. 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 industries. 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 industries. Varying by reporting unit, weighted average cost of capital in the range of 6.9% to 7.0% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2022. 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. At October 1, 2022, fair value exceeded the carrying value at all reporting units. However, the Gas Utilities reporting unit’s fair value exceeded its carrying value by less than 10% and could be at risk for impairment if adverse macroeconomic conditions persist or deteriorate. The decrease in the fair value cushion of the Gas Utilities reporting unit when compared to the prior year was primarily due to an increase in the weighted average cost of capital. 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, 2022, 2021, and 2020, there were no impairment losses recorded. At December 31, 2022, 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. 53 10-KFORM 10-K |ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Our activities in the regulated and non-regulated energy sectors 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 the COVID-19 pandemic, weather (e.g. Winter Storm Uri), geopolitical events, 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, such as the 2008 financial crisis and the COVID-19 pandemic. 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 any 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 We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments and do not qualify for the normal purchase and normal sales exception for derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income. A potential risk related to wholesale power sales is the price risk arising from the sale of power that exceeds our generating capacity. These potential short positions can 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. 54 10-K| FORM 10-KBlack Hills Energy Services To support our Choice Gas Program customers, we buy and sell natural gas 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, 2022 and 2021, 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, 2022, 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, 2022, 88% 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 $4.1 million and $2.7 million for the years ended December 31, 2022 and 2021, 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 Critical Accounting Estimates in Item 7 and 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 ongoing 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. Our credit exposure at December 31, 2022 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. See more information in Notes 1 and 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K. 55 10-KFORM 10-K |ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Management’s Report on Internal Control Over Financial Reporting We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a- 15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2022, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of December 31, 2022. Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial reporting as of December 31, 2022. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein. Black Hills Corporation 56 10-K| FORM 10-KREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of Black Hills Corporation Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the "Company") as of December 31, 2022 and 2021, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2022, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2023, expressed an unqualified opinion on the Company's internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matter The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Regulatory Accounting - Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 2 to the Financial Statements. Critical Audit Matter Description The Company is subject to cost-of-service regulation and earnings oversight by state and federal utility commissions (collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense). 57 10-KFORM 10-K |Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to have been prudently incurred or that the rate regulation process in which rates are determined will not always result in rates that produce a full recovery of costs and a reasonable return on invested capital. We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers. Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others: • • • • • We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) refunds or future reductions in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates. We read relevant regulatory orders issued by the Commissions, procedural memorandums, filings made by the Company, and other publicly available information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on precedence of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external information and compared it to the Company’s recorded regulatory asset and liability balances for completeness and for any evidence that might contradict management’s assertions. We obtained and evaluated an analysis from management regarding probability of recovery for regulatory assets or refund or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order to assess management’s assertion that amounts are probable of recovery or of a future reduction in rates. We inspected minutes of the board of directors to identify any evidence that may contradict management’s assertions regarding probability of recovery or refunds. We also inquired of management regarding current year rate filings and new regulatory assets or liabilities. We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments. /s/ DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 14, 2023 We have served as the Company's auditor since 2002. 58 10-K| FORM 10-KREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of Black Hills Corporation Opinion on Internal Control over Financial Reporting We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the “Company”) as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO. We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Company and our report dated February 14, 2023, expressed an unqualified opinion on those financial statements. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. /s/ DELOITTE & TOUCHE LLP Minneapolis, Minnesota February 14, 2023 59 10-KFORM 10-K |BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF INCOME December 31, 2022 December 31, 2021 (in thousands, except per share amounts) December 31, 2020 Revenue $ 2,551,816 $ 1,949,102 $ 1,696,941 Operating expenses: Fuel, purchased power and cost of natural gas sold Operations and maintenance Depreciation, depletion and amortization Taxes - property and production Total operating expenses Operating income Other income (expense): Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) Interest income Impairment of investment Other income (expense), net Total other income (expense) Income before income taxes Income tax expense Net income Net income attributable to non-controlling interest Net income available for common stock Earnings per share of common stock: Earnings per share, Basic Earnings per share, Diluted Weighted average common shares outstanding: Basic Diluted 1,230,550 548,430 250,909 66,683 2,096,572 741,934 501,690 235,953 60,096 1,539,673 492,404 495,404 224,457 56,373 1,268,638 455,244 409,429 428,303 (162,584) 1,595 — 1,708 (159,281) 295,963 (25,205) 270,758 (12,371) 258,387 3.98 3.97 64,858 65,021 $ $ $ (154,112) 1,708 — 1,404 (151,000) 258,429 (7,169) 251,260 (14,516) 236,744 3.74 3.74 63,219 63,325 $ $ $ (144,931) 1,461 (6,859) (2,293) (152,622) 275,681 (32,918) 242,763 (15,155) 227,608 3.65 3.65 62,378 62,439 $ $ $ The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. 60 10-K| FORM 10-KBLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Year ended Net income December 31, 2022 $ 270,758 December 31, 2021 (in thousands) 251,260 $ December 31, 2020 $ 242,763 Other comprehensive income (loss), net of tax: Benefit plan liability adjustments - net gain (loss) (net of tax of $(1,505), $(664) and $191, respectively) Reclassification adjustment of benefit plan liability - net loss (net of tax of $(226), $(665) and $(958), respectively) Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $28, $27 and $23, respectively) Derivative instruments designated as cash flow hedges: Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(721), $(677) and $(287), respectively) Net unrealized gains (losses) on commodity derivatives (net of tax of $193, $(980) and $14, respectively) Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $663, $502 and $(96), respectively) Other comprehensive income (loss), net of tax 4,604 525 (65) 2,129 (631) (2,045) 4,517 1,959 1,726 (71) 2,174 3,023 (1,549) 7,262 (1,062) 1,429 (80) 2,564 (47) 505 3,309 Comprehensive income Less: comprehensive income attributable to non-controlling interest Comprehensive income available for common stock 275,275 (12,371) 262,904 $ 258,522 (14,516) 244,006 $ 246,072 (15,155) 230,917 $ See Note 11 for additional disclosures related to Comprehensive Income. The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. 61 10-KFORM 10-K |BLACK HILLS CORPORATION CONSOLIDATED BALANCE SHEETS ASSETS Current assets: Cash and cash equivalents Restricted cash and equivalents Accounts receivable, net Materials, supplies and fuel Derivative assets, current Income tax receivable, net Regulatory assets, current Other current assets Total current assets Property, plant and equipment Less accumulated depreciation and depletion Total property, plant and equipment, net Other assets: Goodwill Intangible assets, net Regulatory assets, non-current Other assets, non-current Total other assets, non-current TOTAL ASSETS As of December 31, 2022 December 31, 2021 (in thousands) $ $ 21,430 5,555 508,192 207,421 582 17,637 260,312 50,579 1,071,708 8,374,790 (1,576,842) 6,797,948 1,299,454 9,589 392,669 46,862 1,748,574 9,618,230 $ $ 8,921 4,889 321,652 150,979 4,373 18,017 270,290 29,012 808,133 7,856,573 (1,407,397) 6,449,176 1,299,454 10,770 526,309 38,054 1,874,587 9,131,896 The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. 62 10-K| FORM 10-KBLACK HILLS CORPORATION CONSOLIDATED BALANCE SHEETS (Continued) LIABILITIES AND EQUITY Current liabilities: Accounts payable Accrued liabilities Derivative liabilities, current Regulatory liabilities, current Notes payable Current maturities of long-term debt Total current liabilities Long-term debt, net of current maturities Deferred credits and other liabilities: Deferred income tax liabilities, net Regulatory liabilities, non-current Benefit plan liabilities Other deferred credits and other liabilities Total deferred credits and other liabilities Commitments, contingencies and guarantees (Note 3) Equity: Stockholders’ equity - Common stock $1.00 par value; 100,000,000 shares authorized; issued: 66,140,396 and 64,793,095, respectively Additional paid-in capital Retained earnings Treasury stock at cost - 36,726 and 54,078, respectively Accumulated other comprehensive income (loss) Total stockholders’ equity Non-controlling interest Total equity TOTAL LIABILITIES AND TOTAL EQUITY As of December 31, 2022 December 31, 2021 (in thousands, except share amounts) $ 310,020 243,457 6,600 46,013 535,600 525,000 1,666,690 217,761 244,759 1,439 17,574 420,180 — 901,713 3,607,340 4,126,923 508,941 472,560 116,742 156,062 1,254,305 465,388 485,377 123,925 141,447 1,216,137 66,140 1,882,653 1,064,122 (2,435) (15,567) 2,994,913 94,982 3,089,895 9,618,230 $ 64,793 1,783,436 962,458 (3,509) (20,084) 2,787,094 100,029 2,887,123 9,131,896 $ $ The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. 63 10-KFORM 10-K |BLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended Operating activities: Net income Adjustments to reconcile net income to net cash provided by (used in) operating activities: December 31, 2022 December 31, 2021 (in thousands) December 31, 2020 $ 270,758 $ 251,260 $ 242,763 Depreciation, depletion and amortization Deferred financing cost amortization Impairment of investment Stock compensation Deferred income taxes Employee benefit plans Other adjustments, net Change in certain operating assets and liabilities: Materials, supplies and fuel Accounts receivable and other current assets Accounts payable and other current liabilities Regulatory assets Regulatory liabilities Contributions to defined benefit pension plans Other operating activities, net Net cash provided by (used in) operating activities Investing activities: Property, plant and equipment additions Other investing activities Net cash (used in) investing activities Financing activities: Dividends paid on common stock Common stock issued Term Loan - borrowings Term Loan - repayments Net borrowings (payments) of Revolving Credit Facility and CP Program Long-term debt - issuance Long-term debt - repayments Distributions to non-controlling interests Other financing activities Net cash provided by financing activities Net change in cash, restricted cash and cash equivalents Cash, restricted cash and cash equivalents beginning of year Cash, restricted cash and cash equivalents end of year Supplemental cash flow information: Cash (paid) refunded during the period: Interest (net of amounts capitalized) Income taxes Non-cash investing and financing activities: Accrued property, plant and equipment purchases at December 31 Increase in capitalized assets associated with asset retirement obligations $ $ $ $ $ 250,909 9,843 — 8,551 25,592 5,459 (4,720) (75,403) (184,448) 89,405 203,869 — — (15,014) 584,801 (604,365) 485 (603,880) (156,723) 90,044 — — 115,420 — — (17,418) 931 32,254 13,175 13,810 26,985 $ 235,953 6,968 — 9,655 7,261 9,590 7,018 (35,707) (43,170) 10,660 (514,687) (9,533) — 167 (64,565) (677,492) 13,262 (664,230) (145,023) 118,979 800,000 (800,000) 186,140 600,000 (8,436) (15,749) (4,045) 731,866 3,071 10,739 13,810 $ 224,457 7,883 6,859 5,373 38,091 11,997 11,669 2,755 (10,843) 24,659 (5,047) (10,706) (12,700) 4,653 541,863 (767,404) 5,740 (761,664) (135,439) 99,278 — — (115,460) 400,000 (8,597) (15,839) (7,061) 216,882 (2,919) 13,658 10,739 (152,546) $ $ 771 (142,685) $ $ 1,521 (136,549) 2,172 59,347 14,032 $ $ 68,758 2,109 $ $ 72,215 4,774 The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. 64 10-K| FORM 10-KBLACK HILLS CORPORATION CONSOLIDATED STATEMENTS OF EQUITY Common Stock Treasury Stock Shares 61,480,658 — — — 123,578 1,222,943 — — — 62,827,179 — — — 153,719 1,812,197 — — — 64,793,095 — — — 39,546 1,307,755 — — 66,140,396 Value $ 61,481 — — — 123 1,223 — — — $ 62,827 — — — 154 1,812 — — — $ 64,793 — — — 39 1,308 — — $ 66,140 Shares Value $ 3,956 — — — 28,536 — — — — $ 32,492 — — — 21,586 — — — — 54,078 — — — (17,352) — — — 36,726 $ (267) — — — (1,852) — — — — $ (2,119) — — — (1,390) — — — — $ (3,509) — — — 1,074 — — — $ (2,435) Additional Paid in Capital $ 1,552,788 — — — 6,923 98,777 (1,203) — — $ 1,657,285 — — — 9,256 118,112 (1,217) — — $ 1,783,436 — — — 10,481 89,889 (1,153) — $ 1,882,653 (in thousands except share amounts) Balance at December 31, 2019 Net income Other comprehensive income, net of tax Dividends on common stock ($2.17 per share) Share-based compensation Issuance of common stock Issuance costs Implementation of ASU 2016-13 Financial Instruments - Credit Losses Distributions to non-controlling interest Balance at December 31, 2020 Net income Other comprehensive income, net of tax Dividends on common stock ($2.29 per share) Share-based compensation Issuance of common stock Issuance costs Other Distributions to non-controlling interest Balance at December 31, 2021 Net income Other comprehensive income, net of tax Dividends on common stock ($2.41 per share) Share-based compensation Issuance of common stock Issuance costs Distributions to non-controlling interest Balance at December 31, 2022 $ Retained Earnings 778,776 227,608 — (135,439) — — — $ (207) — 870,738 236,744 — (145,023) — — — (1) — 962,458 258,387 — (156,723) — — — — $ 1,064,122 $ Non controlling Interest $ $ $ $ 101,946 15,155 — — — — — — (15,839) 101,262 14,516 — — — — — — (15,749) 100,029 12,371 — — — — — (17,418) 94,982 AOCI $ (30,655) — 3,309 — — — — — — $ (27,346) — 7,262 — — — — — — $ (20,084) — 4,517 — — — — — $ (15,567) Total $ 2,464,069 242,763 3,309 (135,439) 5,194 100,000 (1,203) (207) (15,839) $ 2,662,647 251,260 7,262 (145,023) 8,020 119,924 (1,217) (1) (15,749) $ 2,887,123 270,758 4,517 (156,723) 11,594 91,197 (1,153) (17,418) $ 3,089,895 The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements. 65 10-KFORM 10-K |BLACK HILLS CORPORATION Notes to Consolidated Financial Statements December 31, 2022, 2021 and 2020 (1) BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES Business Description Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. Use of Estimates and Basis of Presentation The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and circumstances or additional information may result in revised estimates and actual results could differ materially from those estimates. COVID-19 Pandemic In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations. The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the years ended December 31, 2022, 2021 and 2020, there were no material adverse impacts on the Company’s results of operations. Principles of Consolidation The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 16. Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generation facility, wind farm or transmission tie. See Note 6 for additional information. Variable Interest Entities We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary. GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, non- controlling interest and results of activities of a VIE in its consolidated financial statements. A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and non- controlling interests at fair value and subsequently account for the VIE as if it were consolidated. Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the purpose of the arrangement. Black Hills Colorado IPP is a VIE. See additional information in Note 12. 66 10-K| FORM 10-KCash, Cash Equivalents and Restricted Cash We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We maintain cash accounts for various specified purposes, which are classified as restricted cash. Revenue Recognition Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time, represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer and provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary types of revenue contracts are: • • Regulated natural gas and electric utility services tariffs - Our Utilities have regulated operations, as defined by ASC 980, Regulated Operations, that provide services to regulated customers under tariff rates, charges, terms and conditions of service and prices determined by the jurisdictional regulators designated for our service territories. Our regulated services primarily encompass single performance obligations for delivery of either commodity natural gas, commodity electricity, natural gas transportation or electric transmission services. These service revenues are variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to establish contractual rates between the utility and its customers. All of our Utilities’ regulated sales are subject to regulatory-approved tariffs. Power sales agreements - Our Electric Utilities segment has long-term wholesale power sales agreements with other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based on energy delivered. Certain energy sale and purchase transactions with the same counterparty and at the same delivery point are netted to reflect the economic substance of the arrangement. The majority of our revenue contracts are based on variable quantities delivered. Any fixed consideration contracts with an expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to those services being transferred to the customer. Revenue Not in Scope of ASC 606 Other revenues included in the tables in Note 4 include our revenue accounted for under separate accounting guidance, including lease revenue under ASC 842, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative revenue programs revenue under ASC 980, Regulated Operations. Significant Judgments and Estimates Unbilled Revenue To the extent that deliveries have occurred, but a bill has not been issued, our Utilities accrue an estimate of the revenue since the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month and prices in effect in our jurisdictions. Each month, the estimated unbilled revenue amounts are trued-up and recorded in Accounts receivable, net on the accompanying Consolidated Balance Sheets. Contract Balances The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our Accounts receivable, which is further discussed below. Additional information is included in Note 4. 67 10-KFORM 10-K |Accounts Receivable and Allowance for Credit Losses Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses. Accounts receivable for our power generation and mining businesses consists of amounts due from sales of electric energy and capacity and coal primarily to affiliates or regional utilities. We maintain an allowance for credit losses which reflects our estimate of uncollectible trade receivables. We regularly review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the receivable balances and current economic conditions that may affect collectability. In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for credit losses to reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the contract has expired. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. Following is a summary of accounts receivable as of December 31 (in thousands): Billed Accounts Receivable Unbilled Revenue Less Allowance for Credit Losses Accounts Receivable, net 2022 2021 267,571 243,574 (2,953) 508,192 $ $ 181,027 142,738 (2,113) 321,652 $ $ Changes to allowance for credit losses for the years ended December 31, were as follows (in thousands): Balance at Beginning of Year $ $ $ 2,113 7,003 2,444 $ $ $ Additions Charged to Costs and Expenses Recoveries and Other Additions Write-offs and Other Deductions Balance at End of Year 9,110 2,444 8,927 $ $ $ 3,529 3,560 4,728 $ $ $ (11,799) $ (10,894) $ (9,096) $ 2,953 2,113 7,003 2022 2021 2020 Materials, Supplies and Fuel The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): Materials and supplies Fuel Natural gas in storage Total materials, supplies and fuel 2022 2021 99,734 3,115 104,572 207,421 $ $ 86,400 1,267 63,312 150,979 $ $ Materials and supplies represent parts and supplies for business segments. Fuel represents diesel oil and gas used by our Electric Utilities to produce power. Natural gas in storage primarily represents gas purchased for use by our gas customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our business and the commodity price of natural gas. 68 10-K| FORM 10-K Property, Plant and Equipment Additions to property, plant and equipment are recorded at cost. Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite cost of borrowed funds and a return on equity used to finance a regulated utility project. The following table presents AFUDC amounts (in thousands) for the years ended December 31: Income Statement Location 2022 2021 2020 AFUDC Borrowed AFUDC Equity Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts) Other income (expense), net $ 5,638 $ 4,068 $ 5,617 644 593 318 We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets. We also classify our Cushion Gas as Property, plant and equipment. The cost of regulated utility property, plant and equipment retired, or otherwise disposed in the ordinary course of business, less salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs related to our regulated properties that do not have legal retirement obligations are reclassified from accumulated depreciation and reflected as regulatory liabilities. Retirement or disposal of all other assets result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred. Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the applicable estimated service life of the various classes of property. The composite depreciation method is applied to regulated utility property. Capitalized mining costs and coal leases are amortized on a unit-of-production method based on volumes produced and estimated reserves. For certain non-regulated power plant components, depreciation is computed on a unit-of- production methodology based on plant hours run. See Note 5 for additional information. Asset Retirement Obligations Accounting standards for AROs associated with long-lived assets require that the present value of retirement costs for which we have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an appropriate period. The associated ARO accretion expense for our non-regulated operations, and regulated operations without a corresponding recovery mechanism, is included within Depreciation, depletion and amortization on the accompanying Consolidated Statements of Income. The accounting for the obligation for regulated operations with a regulatory mechanism has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a regulatory liability. We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non- regulated operations. Additional information is included in Note 7. Goodwill and Intangible Assets Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of impairment or at least annually. Intangible assets with a finite life are amortized over their estimated useful lives. 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 our testing date with our financial planning process. The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment. 69 10-KFORM 10-K |Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies. We believe that goodwill reflects the inherent value of the relatively stable, long-lived cash flows of our Utilities businesses, considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our Utilities, and those businesses vertically integrated. Goodwill amounts have not changed since 2016. As of December 31, 2022 and 2021, Goodwill balances were as follows (in thousands): Goodwill Electric Utilities Gas Utilities Total $ 257,244 $ 1,042,210 $ 1,299,454 Our intangible assets represent contract intangibles, easements, rights-of-way, customer listings and trademarks. The finite-lived intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being amortized from 3 years to 37 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands): Intangible assets, net, beginning balance Amortization expense (a) Intangible assets, net, ending balance 2022 2021 2020 $ $ 10,770 (1,181) 9,589 $ $ 11,944 (1,174) 10,770 $ $ 13,266 (1,322) 11,944 (a) Amortization expense for existing intangible assets is expected to be $1.2 million for each year of the next five years. Accrued Liabilities The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of December 31 (in thousands): Accrued employee compensation, benefits and withholdings Accrued property taxes Customer deposits and prepayments Accrued interest Other (none of which is individually significant) Total accrued liabilities Fair Value Measurements 2022 2021 62,890 52,430 47,655 33,798 46,684 243,457 $ $ 74,387 50,874 48,814 33,680 37,004 244,759 $ $ Financial Instruments We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories: Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis. Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments. 70 10-K| FORM 10-K Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs. Valuation Methodologies for Derivatives The wholesale electric energy and natural gas commodity contracts for our Utilities are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps and over-the-counter swaps and options (Level 2). For exchange-traded futures, options and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a CVA based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. Additional information on fair value measurements is included in Notes 10 and 13. Derivatives and Hedging Activities All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets, except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable amount of time and pricing is clearly and closely related to the asset being purchased or sold. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed under the accrual basis of accounting. In addition, certain derivative contracts approved by regulatory authorities are either recovered or refunded through customer rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory liability pursuant to ASC 980, Regulated Operations. We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on these designated derivatives is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is recognized in earnings. Changes in the fair value of all other derivative contracts are recognized in earnings. We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either our actual credit or net economic exposures. See additional information in Notes 9, 10 and 11. Deferred Financing Costs Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities. See additional information in Note 8. Regulatory Accounting Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our Electric and Gas Utilities account for income and expense items in accordance with accounting standards for regulated operations. These accounting policies differ in some respects from those used by our non- regulated businesses. Under these regulated operations accounting standards: • Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates. 71 10-KFORM 10-K |• Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred. Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and 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. If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment and may be required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of operations, financial position or cash flows. See Note 2 for further information. Income Taxes The Company and its subsidiaries file consolidated federal income tax returns. Each entity records both federal and state income taxes as if it were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company computations of taxable income or loss. We use 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. It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method, which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax expense over the estimated useful lives of the underlying property that gave rise to the credit. We recognize interest income or interest expense and penalties related to income tax matters in Income tax expense on the Consolidated Statements of Income. We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information. Earnings per Share of Common Stock Basic earnings per share is computed by dividing Net income available for common stock by the weighted average number of common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted stock and performance shares under our equity compensation plans. A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in thousands): Net income available for common stock Weighted average shares - basic Dilutive effect of: Equity compensation Weighted average shares - diluted Net income available for common stock, per share - Diluted 2022 258,387 64,858 163 65,021 3.97 $ $ 2021 236,744 63,219 106 63,325 3.74 $ $ 2020 227,608 62,378 61 62,439 3.65 $ $ The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands): Equity compensation Anti-dilutive shares excluded from computation of earnings per share 2022 2021 2020 - - 13 13 60 60 72 10-K| FORM 10-K Non-controlling Interests We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidation. ASC 810 requires that the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that non- controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the amounts attributable to the non-controlling interest net income (loss) of those subsidiaries are reported separately in the consolidated statements of income and comprehensive income. See Note 12 for additional detail on non-controlling interests. Share-Based Compensation We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation, by recognizing compensation costs for all share-based awards over the respective service period for employee services received in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as liabilities and the compensation expense is re-measured each period based on the current market price and performance achievement measures. See additional information in Note 14. Recently Issued Accounting Standards Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2020-04 In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01 and ASU 2022-06. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2024. We are currently evaluating if we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements. We do not expect the ASU to have a material impact on our financial position, results of operations and cash flows. 73 10-KFORM 10-K |(2) REGULATORY MATTERS We had the following regulatory assets and liabilities as of December 31 (in thousands): Regulatory assets Winter Storm Uri (a) Deferred energy and fuel cost adjustments (b) Deferred gas cost adjustments (b) Gas price derivatives (b) Deferred taxes on AFUDC (b) Employee benefit plans and related deferred taxes (c) Environmental (b) Loss on reacquired debt (b) Deferred taxes on flow-through accounting (b) Decommissioning costs (b) Other regulatory assets (b) Total regulatory assets Less current regulatory assets Regulatory assets, non-current Regulatory liabilities Deferred energy and gas costs (b) Employee benefit plan costs and related deferred taxes (c) Cost of removal (b) Excess deferred income taxes (c) Other regulatory liabilities (c) Total regulatory liabilities Less current regulatory liabilities Regulatory liabilities, non-current 2022 2021 347,980 72,580 12,147 8,793 7,333 89,259 1,343 19,213 69,529 3,472 21,332 652,981 (260,312) 392,669 24,030 34,258 175,614 254,833 29,838 518,573 (46,013) 472,560 $ $ $ $ 509,025 59,973 9,488 2,584 7,457 88,923 1,385 21,011 63,243 5,961 27,549 796,599 (270,290) 526,309 6,113 32,241 179,976 264,042 20,579 502,951 (17,574) 485,377 $ $ $ $ (a) (b) (c) Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below. Recovery of costs, but we are not allowed a rate of return. In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base. Regulatory assets represent items we expect to recover from customers through probable future rates. Winter Storm Uri - See discussion below for Winter Storm Uri regulatory asset information. Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity delivered to our Electric Utilities’ customers that is either higher or lower than the current rates and will be recovered or refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved by the appropriate state regulatory commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions. Deferred Gas Cost Adjustments - Our regulated Gas Utilities have GCA provisions that allow them to pass the cost of gas on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under- recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded as a regulatory asset or liability, respectively. Our Gas Utilities file periodic monthly, quarterly, semi-annual and/or annual filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory commissions. Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory commissions, have entered into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities. Gas price derivatives at December 31, 2022 are hedged over a maximum forward term of two years. Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action, it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment. 74 10-K| FORM 10-K Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans include the unrecognized prior service costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in regulatory assets rather than in AOCI. In addition, this regulatory asset includes the income tax effect of the adjustment required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Environmental - Environmental costs associated with certain former manufactured gas plant sites. These costs are first offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the applicable state regulatory commission and therefore, the recovery period is unknown at this time. Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if refinanced, over the life of the new issue. Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items are reflected in our cost of service for the customer and result in lower utility rates in the year in which the tax benefits are realized. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a tax benefit for costs considered currently deductible for tax purposes but are capitalized for book purposes. Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas received approval to record Liquefied Natural Gas Plant decommissioning costs as a regulatory asset and received approval in 2020 to begin recovering those costs over three years. Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates. Deferred Energy and Gas Costs - Deferred energy and gas costs that have been over-recovered through customer rates and will be returned to customers in future periods. Employee Benefit Plan Costs and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with ASC 715, Compensation-Retirement Benefits. In addition, this regulatory liability includes the income tax effect of the adjustment required under ASC 715, Compensation-Retirement Benefits, to record the full pension and post-retirement benefit obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate regulated environment. Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which there is no legal obligation for removal included in depreciation expense. Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the passage of the TCJA was recorded as an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. See Note 15 for additional information. Recent Regulatory Activity Winter Storm Uri In February 2021, Winter Storm Uri caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result, we incurred significant incremental fuel, purchased power and natural gas costs. Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.5 years. In these applications, we sought approval to recover carrying costs. We have received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow our Utilities to recover incremental fuel, purchased power and natural gas costs. For the years ended December 31, 2022 and 2021, our Utilities collected $174 million and $40 million, respectively, of Winter Storm Uri incremental costs and carrying costs from customers. As of December 31, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 2.6 years. 75 10-KFORM 10-K |For years ended December 31, 2022 and 2021, $22 million and $4.1 million, respectively, of carrying costs were accrued and recorded to a regulatory asset. The carrying costs accrued during the year ended December 31, 2022 included a one-time, $10 million true-up recorded in the second quarter to reflect commission authorized rates. TCJA On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017. In 2018 and 2019, the Company successfully delivered several of these tax benefits from the TCJA to its utility customers. On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in February 2021. On January 26, 2021, the NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in June 2021. As part of Kansas Gas’ 2021 rate review settlement agreement, Kansas Gas will deliver $9.1 million, or approximately $3.0 million of TCJA and state tax reform benefits to customers annually, for three years starting in 2022. For the year ended December 31, 2022, Kansas Gas delivered TCJA and state tax reform benefits to customers of $2.9 million. These Colorado Electric, Kansas Gas and Nebraska Gas tax benefits delivered to customers, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net income for the years ended December 31, 2022 and 2021. Arkansas Gas On December 10, 2021, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. On October 10, 2022, the APSC approved a partial settlement agreement with all intervening parties for a general rate increase and authorized a capital structure of 45% equity and 55% debt and a return on equity of 9.6%. The APSC’s decision shifts approximately $10 million of rider revenue to base rates and is expected to generate $8.8 million of new annual revenue. The APSC also approved a new comprehensive safety and integrity rider which replaces three former riders. New rates were effective on October 21, 2022. Wyoming Electric On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 1330-mile electric distribution and 59-mile electric transmission systems. On January 26, 2023, the WPSC approved a settlement agreement with intervening parties for a general rate increase. The settlement is expected to generate $8.7 million in new annual revenue with a capital structure of 52% equity and 48% debt and a return on equity of 9.75%. New rates will be effective on March 1, 2023. The agreement also includes approval of a new rider that will be filed annually to recover transmission investment and expenses. Colorado Gas RMNG Rate Review On October 7, 2022, RMNG filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 600-mile natural gas pipeline system. The rate review requests $12.3 million in new annual revenue based on a future test year with a capital structure of 52% equity and 48% debt and a return on equity of 12.3%. The rate review also requests a $7.7 million shift of SSIR revenues to base rates. The request seeks to finalize rates in the third quarter of 2023. 76 10-K| FORM 10-KColorado Gas Rate Reviews and SSIR On June 1, 2021, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 7,000-mile natural gas pipeline system. In the fourth quarter of 2021, Colorado Gas reached a settlement agreement with the CPUC staff and various intervenors for a general rate increase, which was subsequently approved by an administrative law judge. New rates were effective January 1, 2022, and the settlement is expected to generate $6.5 million of new annual revenue. The new revenue is based on a return on equity of 9.2% and a capital structure of 50.3% equity and 49.7% debt. On September 11, 2020, in accordance with the final Order from the rate review filed on February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. On July 6, 2021, Colorado Gas received approval from the CPUC for its SSIR proposal to recover these investments for three years effective January 1, 2022. The return on SSIR investments will be the current weighted-average cost of long-term debt. Iowa Gas Rate Review On June 1, 2021, Iowa Gas filed a rate review with the IUB seeking recovery of significant infrastructure investments in its 5,000- mile natural gas pipeline system. On December 28, 2021, the IUB approved a settlement agreement with all intervening parties for a general rate increase. The settlement shifted $2.2 million of rider revenue to base rates and is expected to generate $3.7 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.6%. Final rates were enacted on January 1, 2022 and replaced interim rates effective June 11, 2021. Kansas Gas Rate Review On May 7, 2021, Kansas Gas filed a rate review and rider renewal with the KCC seeking recovery of significant infrastructure investments in its 4,600-mile natural gas pipeline system. On December 30, 2021, Kansas Gas received approval from the KCC on its Global Settlement agreement with KCC staff and various intervenors for a general rate increase and renewal of its safety and integrity rider. The settlement shifted $6.6 million of rider revenue to base rates, effective January 1, 2022, and also allowed rider renewal for at least five more years. South Dakota Electric FERC Formula Rate The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint- access transmission tariff. Effective January 1, 2022, the annual revenue requirement for the FERC Transmission Formula Rate was $30 million and included estimated weighted average capital additions of $30 million for 2021 and 2022 combined. Black Hills Wyoming and Wyoming Electric Wygen I FERC Filing On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement commenced on January 1, 2022, replaced the existing PPA and will expire after 11 years. 77 10-KFORM 10-K |(3) COMMITMENTS, CONTINGENCIES AND GUARANTEES Unconditional Purchase Obligations We have various PPAs and transmission service agreements, which extend to 2030, to support our Electric Utilities' capacity and energy needs beyond our regulated power plants' generation. Our Utilities purchase natural gas, including transportation and storage capacity, to meet customers' needs under short-term and long-term purchase contracts. These contracts extend to 2044. The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and natural gas transportation and storage agreements (in thousands): PPAs (a) Transmission Services Agreements Natural gas supply, transportation and storage agreements (b) $ Future commitments for the year ending December 31, 2023 2024 2025 2026 2027 Thereafter Total future commitments ___________________________ (a) This schedule does not reflect renewable energy PPA future obligations since these agreements vary based on weather conditions. (b) Our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days. 130,031 98,881 72,662 45,102 14,862 56,595 418,133 12,320 - - - - - 12,320 11,175 2,738 - - - - 13,913 $ $ $ $ $ Lease Agreements Lessee We lease from third parties certain office and operation center facilities, communication tower sites, equipment and materials storage. Our leases have remaining terms ranging from less than one year to 33 years, including options to extend that are reasonably certain to be exercised. Our operating and finance leases were not material to the Company’s Consolidated Financial statements. Lessor We lease to third parties certain generating station ground leases, communication tower sites and a natural gas pipeline. These leases have remaining terms ranging from less than one year to 34 years. Lease revenue was not material for the years ended December 31, 2022, 2021 and 2020. As of December 31, 2022, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands): 2023 2024 2025 2026 2027 Thereafter Total lease receivables Environmental Matters $ $ Operating Leases 2,381 2,125 2,070 1,881 1,845 49,387 59,689 We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other requirements of regulatory bodies. 78 10-K| FORM 10-KReclamation Liability For our Pueblo Airport Generation site, we posted a bond of $4.1 million with the State of Colorado to cover the costs of remediation for a waste water containment pond permitted to provide wastewater storage and processing for this zero-discharge facility. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. Under our land leases for our wind generation facilities, we are required to reclaim land where we have placed wind turbines. The reclamation liabilities are recorded at the present value of the estimated future cost to reclaim the land. Under its mining permit, WRDC is required to reclaim all land where it has mined reserves. The reclamation liability is recorded at the present value of the estimated future cost to reclaim the land. See Note 7 for additional information. Manufactured Gas Processing In 2008, we acquired whole and partial liabilities for former manufactured gas processing sites in Nebraska and Iowa, which were previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.3 million recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs. We also have a $1.3 million regulatory asset for manufactured gas processing sites; see Note 2 for additional information. As of December 31, 2022, we had $2.6 million accrued for remediation of Iowa’s manufactured gas processing site as the landowner. As of December 31, 2022, we had $0.6 million accrued for remediation of Nebraska’s manufactured gas processing site as the land owner. These liabilities are included in Other deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties. Legal Proceedings In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements. We record gain contingencies when realized and expected recoveries under applicable insurance contracts when we are assured of recovery. In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies that may provide coverage against certain claims under these indemnities. GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (U.S. District Court for the City and County of Denver, Colorado) On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3 million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. GTR retained rights to receive a royalty interest on any hydrocarbon production from the concession upon the occurrence of contingent events. GTR contended that BHC and its subsidiaries failed to adequately pursue the opportunity and failed to transfer the concession to GTR. We believe we have meritorious defenses to the verdict and have appealed the verdict. At this time, we believe that the liability related to this matter, if any, is not reasonably estimable. 79 10-KFORM 10-K |Guarantees We have entered into various parent company-level guarantees providing financial or performance assurance to third parties on behalf of certain of our subsidiaries. These guarantees do not represent incremental consolidated obligations, but rather, represent guarantees of subsidiary obligations to allow those subsidiaries to conduct business without posting other forms of assurance. The agreements, which are off-balance sheet commitments, include support for business operations, indemnification for reclamation and surety bonds. The guarantees were entered into in the normal course of business. To the extent liabilities are incurred as a result of activities covered by these guarantees, such liabilities are included in our Consolidated Balance Sheets. See Note 8 for additional information on our off-balance sheet Letters of Credit commitment. We had the following guarantees in place as of (in thousands): Nature of Guarantee Indemnification for reclamation/surety bonds Guarantees supporting business transactions (4) REVENUE Maximum Exposure at December 31, 2022 $ $ $ 107,314 484,968 592,282 The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments, for the years ended December 31, 2022, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues. Year ended December 31, 2022 Customer types: Retail Transportation Wholesale Market - off-system sales Transmission/Other Revenue from contracts with customers Other revenues Total revenues Timing of revenue recognition: Services transferred at a point in time Services transferred over time Revenue from contracts with customers Year ended December 31, 2021 Customer types: Retail Transportation Wholesale Market - off-system sales Transmission/Other Revenue from contracts with customers Other revenues Total revenues Timing of revenue recognition: Services transferred at a point in time Services transferred over time Revenue from contracts with customers 80 Electric Utilities Gas Utilities Inter- company Revenues Total (in thousands) 739,734 — 44,832 48,578 61,470 894,614 5,548 900,162 $ 1,453,266 173,275 — 829 37,879 1,665,249 3,841 $ 1,669,090 $ $ (413) — — (16,594) (17,007) (429) — $ 2,193,000 172,862 44,832 49,407 82,755 2,542,856 8,960 (17,436) $ 2,551,816 30,454 864,160 894,614 $ — $ 1,665,249 $ 1,665,249 $ — $ 30,454 (17,007) 2,512,402 (17,007) $ 2,542,856 Electric Utilities Gas Utilities Inter- company Revenues Total (in thousands) 711,448 — 30,848 41,682 52,945 836,923 5,335 842,258 $ 913,725 158,053 — 396 39,365 1,111,539 13,326 $ 1,124,865 $ $ (428) — — (17,200) (17,628) (393) — $ 1,625,173 157,625 30,848 42,078 75,110 1,930,834 18,268 (18,021) $ 1,949,102 27,141 809,782 836,923 $ — $ 1,111,539 $ 1,111,539 $ — $ 27,141 (17,628) 1,903,693 (17,628) $ 1,930,834 $ $ $ $ $ $ $ $ 10-K| FORM 10-K Year ended December 31, 2020 Customer types: Retail Transportation Wholesale Market - off-system sales Transmission/Other Revenue from contracts with customers Other revenues Total revenues Timing of revenue recognition: Services transferred at a point in time Services transferred over time Revenue from contracts with customers Electric Utilities Gas Utilities Inter- company Revenues Total (in thousands) 636,902 $ — 24,845 15,512 55,422 732,681 6,176 738,857 $ 765,922 $ 154,581 — 260 43,658 964,421 10,249 974,670 $ (526) — — (15,772) (16,298) (288) — $ 1,402,824 154,055 24,845 15,772 83,308 1,680,804 16,137 (16,586) $ 1,696,941 27,089 $ 705,592 732,681 $ — $ 964,421 964,421 $ — $ 27,089 (16,298) 1,653,715 (16,298) $ 1,680,804 $ $ $ $ 81 10-KFORM 10-K |(5) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment at December 31 consisted of the following (dollars in thousands): 2022 2021 Lives (in years) Electric Utilities Electric plant: Production Electric transmission Electric distribution Integrated Generation Plant acquisition adjustment (a) General Total electric plant in service Construction work in progress Total electric plant Less accumulated depreciation and depletion Electric plant net of accumulated depreciation and depletion Property, Plant and Equipment $ 1,482,081 632,872 1,082,535 713,519 4,870 274,857 4,190,734 152,953 4,343,687 (1,104,056) $ 3,239,631 Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) 41 49 47 30 32 28 41 48 47 31 32 27 $ 1,452,055 546,126 1,000,619 720,490 4,870 266,935 3,991,095 181,451 4,172,546 (1,016,738) $ 3,155,808 ____________________ (a) The plant acquisition adjustment is included in rate base and is being recovered with 8 years remaining. Minimum Maximum 32 40 45 19 32 24 46 51 50 38 32 31 2022 2021 Lives (in years) Gas Utilities Gas plant: Production Gas transmission Gas distribution Cushion gas - depreciable (a) Cushion gas - not depreciable (a) Storage General Total gas plant in service Construction work in progress Total gas plant Less accumulated depreciation Property, Plant and Equipment Weighted Average Useful Life (in years) Property, Plant and Equipment Weighted Average Useful Life (in years) $ 17,843 695,345 2,620,174 — 63,137 65,781 497,407 3,959,687 52,041 4,011,728 (471,013) 3,540,715 45 58 57 N/A N/A 41 23 $ $ 14,841 645,550 2,394,352 3,539 42,478 56,289 474,964 3,632,013 37,860 3,669,873 (389,115) 3,280,758 40 58 53 28 N/A 38 21 Minimum Maximum 24 32 48 N/A N/A 36 3 47 72 60 N/A N/A 48 25 Gas plant net of accumulated depreciation $ ____________________ (a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. In 2022, assets classified as Cushion gas - depreciable were fully depreciated and removed from gross plant in service and accumulated depreciation. 2022 2021 Lives (in years) Corporate Total plant in service Construction work in progress Total gross property, plant and equipment Less accumulated depreciation Total net of accumulated depreciation Property, Plant and Equipment $ $ 5,685 13,690 19,375 (1,773) 17,602 Weighted Average Useful Life (in years) 11 Property, Plant and Equipment 5,694 $ 8,460 14,154 (1,544) 12,610 $ Weighted Average Useful Life (in years) 10 Minimum Maximum 4 24 82 10-K| FORM 10-K(6) JOINTLY OWNED FACILITIES Our consolidated financial statements include our share of several jointly-owned facilities as described below. Our share of the facilities’ expenses is reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income. Each owner of the facility is responsible for financing its investment in the jointly-owned facilities. At December 31, 2022, our interests in jointly-owned generating facilities and transmission systems were (in thousands): Wyodak Plant (a) Transmission Tie Wygen III (b) Wygen I (c) Ownership Interest 20% $ 35% $ 52% $ 76.5% $ Plant in Service 121,769 24,482 143,818 114,811 Construction Work in Progress Less Accumulated Depreciation Plant Net of Accumulated Depreciation $ $ $ $ 93 300 1,051 1,579 $ $ $ $ (70,884) $ (7,375) $ (29,634) $ (56,553) $ 50,978 17,407 115,235 59,837 (a) (b) (c) In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our mine supplies PacifiCorp’s share of the coal under a separate long-term agreement. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves. South Dakota Electric retains responsibility for plant operations. Our mine supplies fuel to Wygen III for the life of the plant. Black Hills Wyoming retains responsibility for plant operations. Our mine supplies fuel to Wygen I for the life of the plant. (7) ASSET RETIREMENT OBLIGATIONS We have identified legal obligations related to reclamation of mining sites; removal of fuel tanks, transformers containing polychlorinated biphenyls, an evaporation pond; and reclamation of wind turbine sites at our Electric Utilities segment. In addition, we have identified legal obligations related to retirement of gas pipelines, wells and compressor stations at our Gas Utilities and removal of asbestos at our Utilities. We periodically review and update estimated costs related to these AROs. The actual cost may vary from estimates due to regulatory requirements, changes in technology and increased labor, materials and equipment costs. The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other deferred credits and other liabilities (in thousands): Electric Utilities Gas Utilities (a) Total Electric Utilities Gas Utilities (a) Total $ $ 30,089 45,455 75,544 December 31, 2020 $ $ 29,157 42,274 71,431 $ $ $ $ December 31, 2021 Liabilities Incurred Liabilities Settled Accretion — $ — — $ (3,003) $ (158) (3,161) $ 1,353 2,016 3,369 Revisions to Prior Estimates $ (856) $ $ 14,032 13,176 $ December 31, 2022 27,583 61,345 88,928 Liabilities Incurred Liabilities Settled Accretion — $ — — $ (978) $ (66) (1,044) $ 1,315 1,733 3,048 Revisions to Prior Estimates 595 $ 1,514 2,109 $ December 31, 2021 $ $ 30,089 45,455 75,544 (a) The Revisions to Prior Estimates were primarily driven by changes in estimates associated with natural gas wells and compressor stations. We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these obligations could be settled, and therefore, a liability for the cost of these obligations cannot be measured at this time. 83 10-KFORM 10-K | (8) FINANCING Short-term debt Revolving Credit Facility and CP Program On July 19, 2021, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 19, 2026 with two one year extension options (subject to consent from lenders). This Revolving Credit 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. Borrowings continue to be available under a base rate or various Eurodollar rate options. The interest costs associated with the letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our Corporate credit rating from S&P, Fitch and Moody's for our senior unsecured long-term debt. Based on our current credit ratings, the margins for base rate borrowings, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, at December 31, 2022. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2022. We 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 notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration exemption. Our Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following borrowings, outstanding letters of credit, and available capacity at December 31 (dollars in thousands): Amount outstanding Letters of credit (a) Available capacity Weighted average interest rates $ 2022 2021 $ 535,600 24,626 189,774 4.88% 420,180 27,209 302,611 0.30% (a) Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility. Revolving Credit Facility and CP Program borrowing activity for the years ended December 31 was as follows (in thousands): Maximum amount outstanding (based on daily outstanding balances) Average amount outstanding (based on daily outstanding balances) Weighted average interest rates Deferred Financing Costs on the Revolving Credit Facility $ 2022 2021 $ 572,300 390,653 2.11% 440,000 258,392 0.22% Total accumulated deferred financing costs on the Revolving Credit Facility of $8.9 million are being amortized over its estimated useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See below for additional details. Term Loan On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and to meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan carried no prepayment penalty and was subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. Proceeds from the August 26, 2021 public debt offering (discussed below) were used to repay the remaining balance on this term loan. 84 10-K| FORM 10-KLong-term debt Long-term debt outstanding was as follows (dollars in thousands): Corporate Senior unsecured notes due 2023 Senior unsecured notes due 2024 Senior unsecured notes due 2026 Senior unsecured notes due 2027 Senior unsecured notes, due 2029 Senior unsecured notes, due 2030 Senior unsecured notes due 2033 Senior unsecured notes, due 2046 Senior unsecured notes, due 2049 Total Corporate debt Less unamortized debt discount Total Corporate debt, net South Dakota Electric First Mortgage Bonds due 2032 First Mortgage Bonds due 2039 First Mortgage Bonds due 2044 Total South Dakota Electric debt Less unamortized debt discount Total South Dakota Electric debt, net Wyoming Electric Industrial development revenue bonds due 2027(a) (b) First Mortgage Bonds due 2037 First Mortgage Bonds due 2044 Total Wyoming Electric debt Less unamortized debt discount Total Wyoming Electric debt, net Total long-term debt Less current maturities Less unamortized deferred financing costs (c) Long-term debt, net of current maturities and deferred financing costs Interest Rate at December 31, 2022 Balance Outstanding December 31, 2022 December 31, 2021 Due Date November 30, 2023 August 23, 2024 January 15, 2026 January 15, 2027 October 15, 2029 June 15, 2030 May 1, 2033 September 15, 2046 October 15, 2049 $ 4.25% 1.04% 3.95% 3.15% 3.05% 2.50% 4.35% 4.20% 3.88% August 15, 2032 November 1, 2039 October 20, 2044 7.23% 6.13% 4.43% March 1, 2027 November 20, 2037 October 20, 2044 3.68% 6.67% 4.53% $ 525,000 600,000 300,000 400,000 400,000 400,000 400,000 300,000 300,000 3,625,000 (5,259) 3,619,741 75,000 180,000 85,000 340,000 (69) 339,931 10,000 110,000 75,000 195,000 — 195,000 4,154,672 (525,000) (22,332) 525,000 600,000 300,000 400,000 400,000 400,000 400,000 300,000 300,000 3,625,000 (6,125) 3,618,875 75,000 180,000 85,000 340,000 (74) 339,926 10,000 110,000 75,000 195,000 — 195,000 4,153,801 — (26,878) $ 3,607,340 $ 4,126,923 (a) (b) (c) Variable interest rate. A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million due March 1, 2027. In the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds. Includes deferred financing costs associated with our Revolving Credit Facility of $1.8 million and $2.5 million as of December 31, 2022 and December 31, 2021, respectively. Scheduled maturities of long-term debt and associated interest payments by year are shown below (in thousands): 2023 2024 Payments Due by Period 2027 2026 2025 Thereafter Total Principal payments on Long- term debt including current maturities (a) Interest payments on Long- term debt (a) $ 525,000 $ 600,000 $ — $ 300,000 $ 410,000 $ 2,325,000 $ 4,160,000 148,125 125,813 119,591 113,666 101,134 994,804 1,603,133 (a) Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on variable rate debt are calculated by utilizing the applicable rates as of December 31, 2022. We plan to re-finance our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date. In the event we are unable to refinance these senior unsecured notes, we have sufficient alternative measures available to manage cash flows such that our current plans to manage liquidity would be sufficient to meet our obligations in the foreseeable future. 85 10-KFORM 10-K | Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2022. See below for additional information. Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in amounts limited by property, earnings and other provisions of the mortgage indentures. Debt Transactions On August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% three-year senior unsecured notes due August 23, 2024. The notes include an optional redemption provision and may be redeemed, in whole or in part, without premium, on or after February 23, 2022. The proceeds from the offering, which were net of $3.7 million of deferred financing costs, were used to repay amounts outstanding under our term loan entered into on February 24, 2021. On June 17, 2020, we completed a public debt offering which consisted of $400 million of 2.50% 10-year senior unsecured notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes. Amortization of Deferred Financing Costs Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands): Deferred Financing Costs Remaining at December 31, 2022 Amortization Expense for the years ended December 31, 2020 2021 2022 $ 22,332 $ 4,549 $ 3,769 $ 3,272 Debt Covenants Revolving Credit Facility Under our Revolving Credit Facility, we are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Subject to applicable cure periods, a violation of any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. We were in compliance with our covenants at December 31, 2022 as shown below: Consolidated Indebtedness to Capitalization Ratio 60.9% Less than 65% As of December 31, 2022 Covenant Requirement Wyoming Electric Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2022, we were in compliance with these financial covenants. Dividend Restrictions Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends when a default or event of default occurs. Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our subsidiaries. Our Utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2022, the amount of restricted net assets at our Utilities that may not be distributed to our utility holding company in the form of a loan or dividend was approximately $155 million. South Dakota Electric and Wyoming Electric are generally limited to the amount of dividends allowed to be paid to our utility holding company under certain financing agreements. 86 10-K| FORM 10-K Equity At-the-Market Equity Offering Program On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. This forward sales option allows us to sell our shares through the ATM program at the current trading price without actually issuing any shares to satisfy the sale until a future date. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August 3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC. ATM activity for the years ended December 31 was as follows (net proceeds and issuance costs in millions): Number of shares issued Average price per share Proceeds, (net of issuance costs of $(0.9), $(1.1) and $0 respectively) February 2020 Equity Issuance December 31, 2022 1,307,755 69.74 90.3 $ $ December 31, 2021 1,812,197 66.18 118.8 $ $ December 31, 2020 $ $ - - - On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the SEC. Shareholder Dividend Reinvestment and Stock Purchase Plan We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2022, there were 74,198 shares of unissued stock available for future offering under the DRSPP. Preferred Stock Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding as of December 31, 2022 and 2021. (9) RISK MANAGEMENT AND DERIVATIVES Market and Credit Risk Disclosures Our activities in the energy industry expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1. Market Risk Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed, but not limited to, the following market risks: • • Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as the COVID-19 pandemic, weather (e.g. Winter Storm Uri), geopolitical events, market speculation, recession, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic. 87 10-KFORM 10-K |Credit Risk Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty. We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit and other security agreements. We perform ongoing 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. Our credit exposure at December 31, 2022 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies. Derivatives and Hedging Activity Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income and Consolidated Statements of Comprehensive Income (Loss) are detailed below and within Note 10. The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP. For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income. We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity derivatives are recognized in the Consolidated Statements of Income. To support our Choice Gas Program customers, we buy, sell and deliver natural gas at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales during time frames ranging from January 2023 through December 2024. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly. The contract or notional amounts and terms of the natural gas derivative commodity instruments held by our utilities are comprised of both short and long positions. We had the following net long positions as of: Natural gas futures purchased Natural gas options purchased, net Natural gas basis swaps purchased Natural gas over-the-counter swaps, net (b) Natural gas physical commitments, net (c) December 31, 2022 December 31, 2021 Notional Amounts 630,000 1,790,000 900,000 4,460,000 17,864,412 Maximum Term (months) (a) 3 3 3 24 12 Notional Amounts 590,000 3,100,000 870,000 4,570,000 16,416,677 Maximum Term (months) (a) 3 3 3 34 24 Units MMBtus MMBtus MMBtus MMBtus MMBtus (a) (b) (c) Term reflects the maximum forward period hedged. As of December 31, 2022, 1,646,200 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges. Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP. 88 10-K| FORM 10-K We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At December 31, 2022, the Company posted $2.9 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets. Derivatives by Balance Sheet Classification As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements that allow us to settle positive and negative positions. The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands): Derivatives designated as hedges: Asset derivative instruments: Current commodity derivatives Noncurrent commodity derivatives Liability derivative instruments: Current commodity derivatives Total derivatives designated as hedges Derivatives not designated as hedges: Asset derivative instruments: Current commodity derivatives Noncurrent commodity derivatives Liability derivative instruments: Current commodity derivatives Noncurrent commodity derivatives Total derivatives not designated as hedges Derivatives Designated as Hedge Instruments Balance Sheet Location 2022 2021 Derivative assets - current Other assets, non-current Derivative liabilities - current Derivative assets - current Other assets, non-current Derivative liabilities - current Other deferred credits and other liabilities $ $ $ $ $ 118 198 (1,703) (1,387) $ $ 464 337 (4,897) (18) (4,114) $ 2,017 18 — 2,035 2,356 804 (1,439) (20) 1,701 The impact of cash flow hedges on our Consolidated Statements of Comprehensive Income and Consolidated Statements of Income is presented below for the years ended December 31, 2022, 2021 and 2020. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled. Derivatives in Cash Flow Hedging Relationships Interest rate swaps Commodity derivatives $ 2022 2021 2020 Amount of Gain/(Loss) Recognized in OCI (in thousands) $ 2,851 $ 2,850 2,851 Total (3,532) $ (682) $ 1,952 4,803 540 3,391 $ Income Statement Location Interest expense Fuel, purchased power and cost of natural gas sold 2022 2020 2021 Amount of Gain/(Loss) Reclassified from AOCI into Income (in thousands) $ (2,850) $ (2,851) $ (2,851) 2,708 $ (142) $ 2,051 (601) (800) $ (3,452) As of December 31, 2022, $4.5 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods. 89 10-KFORM 10-K | Derivatives Not Designated as Hedge Instruments The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the years ended December 31, 2022, 2021 and 2020. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic gross profit we realized when the underlying physical and financial transactions were settled. Derivatives Not Designated as Hedging Instruments Income Statement Location Commodity derivatives - Electric Commodity derivatives - Natural Gas Fuel, purchased power and cost of natural gas sold Fuel, purchased power and cost of natural gas sold 2022 2021 Amount of Gain/(Loss) on Derivatives Recognized in Income (in thousands) 2020 $ $ — $ (144) $ 144 (797) (797) $ 2,599 2,455 $ 1,640 1,784 As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in a Regulatory asset related to these financial instruments used in our Gas Utilities were $8.8 million and $2.6 million at December 31, 2022 and 2021, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income. (10) FAIR VALUE MEASUREMENTS Recurring Fair Value Measurements Derivatives The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments. Level 1 Level 2 As of December 31, 2022 Cash Collateral and Counterparty Netting (a) Level 3 (in thousands) Total Assets: Commodity derivatives - Gas Utilities Total Liabilities: Commodity derivatives - Gas Utilities Total $ $ $ $ — — $ 5,407 5,407 — — $ 11,455 11,455 $ $ $ $ — — $ — — $ (4,290) $ (4,290) $ 1,117 1,117 (4,837) $ (4,837) $ 6,618 6,618 (a) As of December 31, 2022, $4.3 million of our commodity derivative gross assets and $4.8 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements. 90 10-K| FORM 10-K As of December 31, 2021 Level 1 Level 2 Level 3 Cash Collateral and Counterparty Netting (a) Total Assets: Commodity derivatives - Gas Utilities Total Liabilities: Commodity derivatives - Gas Utilities Total $ $ $ $ — — $ 7,569 7,569 — $ — $ 3,273 3,273 $ $ $ $ — $ — $ — $ — $ (2,374) $ (2,374) $ 5,195 5,195 (1,814) $ (1,814) $ 1,459 1,459 (a) As of December 31, 2021, $2.4 million of our commodity derivative assets and $1.8 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements. Pension and Postretirement Plan Assets A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 13. Other Fair Value Measurements The carrying amount of cash and cash equivalents, restricted cash and equivalents and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and are not traded on an exchange; therefore, they are classified as Level 2 in the fair value hierarchy. The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets at December 31 (in thousands): Long-term debt, including current maturities (a) $ 4,132,340 $ 3,760,848 $ 4,126,923 $ 4,570,619 (a) Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs. 2022 Carrying Amount Fair Value 2021 Carrying Amount Fair Value 91 10-KFORM 10-K |(11) OTHER COMPREHENSIVE INCOME We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized. The following table details reclassifications out of AOCI and into Net income. The amounts in parentheses below indicate decreases to Net income in the Consolidated Statements of Income for the period, net of tax (in thousands): Location on the Consolidated Statements of Income Amount Reclassified from AOCI December 31, 2022 December 31, 2021 Gains and (losses) on cash flow hedges: Interest rate swaps Commodity contracts Interest expense Fuel, purchased power and cost of natural gas sold Income tax Income tax benefit (expense) Total reclassification adjustments related to cash flow hedges, net of tax Amortization of components of defined benefit plans: Prior service cost Operations and maintenance Actuarial gain (loss) Operations and maintenance Income tax Income tax benefit (expense) Total reclassification adjustments related to defined benefit plans, net of tax Total reclassifications $ $ $ $ $ (2,850) $ (2,851) 2,708 (142) 58 (84) $ 93 $ (751) (658) 198 (460) $ (544) $ 2,051 (800) 175 (625) 98 (2,391) (2,293) 638 (1,655) (2,280) Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows (in thousands): As of December 31, 2021 Other comprehensive income (loss) before reclassifications Amounts reclassified from AOCI As of December 31, 2022 As of December 31, 2020 Other comprehensive income (loss) before reclassifications Amounts reclassified from AOCI As of December 31, 2021 Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total (10,384) $ 1,476 $ (11,176) $ (20,084) — 2,129 (8,255) $ (631) (2,045) (1,200) $ 4,604 460 (6,112) $ 3,973 544 (15,567) Derivatives Designated as Cash Flow Hedges Interest Rate Swaps Commodity Derivatives Employee Benefit Plans Total (12,558) $ 2 $ (14,790) $ (27,346) — 2,174 (10,384) $ 3,023 (1,549) 1,476 $ 1,959 1,655 (11,176) $ 4,982 2,280 (20,084) $ $ $ $ 92 10-K| FORM 10-K(12) VARIABLE INTEREST ENTITY Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo, Colorado. In 2016, Black Hills Electric Generation sold a 49.9%, non-controlling interest in Black Hills Colorado IPP to a third- party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy through 2031 to Colorado Electric. The accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated is specified under ASC 810, Consolidation. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that non-controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. Net income available for common stock for the years ended December 31, 2022, 2021 and 2020 was reduced by $12 million, $15 million, and $15 million, respectively, attributable to this non-controlling interest. The net income allocable to the non- controlling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of net income attributable to this non-controlling interest are due within 30 days following the end of a quarter but may be withheld as necessary by Black Hills Electric Generation. Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre- existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash flows from operations are sufficient to support its ongoing operations. We have recorded the following assets and liabilities on our Consolidated Balance Sheets related to the VIE described above as of December 31 (in thousands): Assets: Current assets Property, plant and equipment of variable interest entities, net Liabilities: Current liabilities (13) EMPLOYEE BENEFIT PLANS Defined Contribution Plans 2022 2021 $ $ $ 12,761 178,761 5,394 $ $ $ 13,220 189,079 5,841 We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis. The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the participant has 5 years of service with the Company. Defined Benefit Pension Plan We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain employees who did not meet age and service-based criteria. The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy. The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets consist primarily of equity, fixed income and hedged investments. 93 10-KFORM 10-K | The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns and the mix of active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2022, the expected rate of return on pension plan assets was based on the targeted asset allocation range of 20% to 28% return-seeking assets and 72% to 80% liability-hedging assets. Our Pension Plan is funded in compliance with the federal government’s funding requirements. Plan Assets The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows: Return-seeking Assets Equity Real estate Fixed income Hedge funds Total Liability-hedging Assets Fixed income Cash Total Total Assets 2022 14% 7% 2% 3% 26% 2022 72% 2% 74% 100% 2021 15% 7% 3% 3% 28% 2021 71% 1% 72% 100% Supplemental Non-qualified Defined Benefit Plans We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are funded on a cash basis as benefits are paid. Non-pension Defined Benefit Postretirement Healthcare Plan BHC sponsors a retiree healthcare plan (Healthcare Plan) for employees who meet certain age and service requirements at retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion of the Healthcare Plan for participating business units are pre-funded via VEBA trusts. Pre-65 retirees as well as a grandfathered group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans. Healthcare coverage for post-65 Medicare-eligible retirees is provided through an individual market healthcare exchange. We fund the Healthcare Plan on a cash basis as benefits are paid. The Healthcare Plan provides for partial pre-funding via VEBA trusts. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in the states of Arkansas, Iowa and Kansas. We do not pre-fund the Healthcare Plan for those employees outside Arkansas, Iowa and Kansas. Plan Contributions Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums. Contributions for the years ended December 31 were as follows (in thousands): Defined Contribution Plan Company retirement contributions Company matching contributions Defined Benefit Plans Defined Benefit Pension Plan Non-Pension Defined Benefit Postretirement Healthcare Plan Supplemental Non-Qualified Defined Benefit Plans 2022 2021 $ $ $ $ $ 11,885 16,187 2022 - 6,131 3,061 $ $ $ $ $ 11,332 15,938 2021 - 6,432 2,576 We do not have any required contributions to our Pension Plan in 2023 and do not intend to make any contributions. 94 10-K| FORM 10-K Fair Value Measurements The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a recurring basis (in thousands): Pension Plan December 31, 2022 Common Collective Trust - Cash and Cash Equivalents Common Collective Trust - Equity Common Collective Trust - Fixed Income Common Collective Trust - Real Estate Hedge Funds Total investments measured at fair value Pension Plan Common Collective Trust - Cash and Cash Equivalents Common Collective Trust - Equity Common Collective Trust - Fixed Income Common Collective Trust - Real Estate Hedge Funds Total investments measured at fair value Level 1 Level 2 Level 3 Total Investments Measured at Fair Value - - - - - - $ 6,374 45,087 242,025 - - $ 293,486 $ $ - - - - - - $ $ 6,374 45,087 242,025 - - 293,486 December 31, 2021 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value - - - - - - $ $ 6,009 70,262 339,219 - - 415,490 $ $ - - - - - - $ $ 6,009 70,262 339,219 - - 415,490 $ $ $ $ NAV (a) $ - - - 21,572 8,084 $ 29,656 Total Investments $ $ 6,374 45,087 242,025 21,572 8,084 323,142 NAV (a) $ - - - 30,407 12,490 $ 42,897 Total Investments $ $ 6,009 70,262 339,219 30,407 12,490 458,387 (a) Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair value of plan assets above. Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2022 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Cash and Cash Equivalents Total investments measured at fair value $ $ 7,752 7,752 $ $ - - $ $ - - $ $ 7,752 7,752 Non-pension Defined Benefit Postretirement Healthcare Plan December 31, 2021 Cash and Cash Equivalents Total investments measured at fair value $ $ 7,972 7,972 $ $ - - $ $ - - $ $ 7,972 7,972 Level 1 Level 2 Level 3 Total Investments Measured at Fair Value Total Investments 7,752 $ 7,752 $ Total Investments 7,972 $ 7,972 $ 95 10-KFORM 10-K |Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of these assets, is as follows: Pension Plan Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Pension Plan, which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the valuation dates. The Pension Plan’s investments in common collective trust funds, with the exception of shares of the common collective trust-real estate are categorized as Level 2. The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting guidance: Common Collective Trust-Real Estate Funds: These funds are valued based on various factors of the underlying real estate properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process, properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and rely on these reports for pricing the units of the fund. Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined using net asset value per share based on the fair value of the hedge fund’s underlying investments. 10% of the shares may be redeemed at the end of each month with a 15-day notice and full redemptions are available at the end of each quarter with 60-day notice and is limited to a percentage of the total net assets value of the fund. The net asset values are based on the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds. Non-pension Defined Benefit Postretirement Healthcare Plan Cash and Cash Equivalents: This represents an investment in Northern Institutional Government Assets Portfolio, which is a government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1. Other Plan Information The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan assets, amounts recognized in the Consolidated Balance Sheets, accumulated benefit obligation, and reconciliation of components of the net periodic expense and elements of AOCI (in thousands): Employee Benefit Plan Obligations As of December 31, Change in benefit obligation: Projected benefit obligation at beginning of year Service cost (a) Interest cost Actuarial (gain) loss Amendments Benefits paid Plan participants’ contributions Projected benefit obligation at end of year Defined Benefit Pension Plan Supplemental Non- qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2022 2021 2022 2021 2022 2021 $ $ 478,262 3,927 10,819 (97,960) - (36,663) - $ 514,008 5,038 9,313 (14,037) (561) (35,499) - $ 55,260 (801) 834 (7,007) - (3,061) - $ 55,054 3,149 706 (1,073) - (2,576) - $ 63,484 1,968 1,285 (12,300) - (6,131) 1,419 70,238 2,237 1,058 (5,165) - (6,432) 1,548 $ 358,385 $ 478,262 $ 45,225 $ 55,260 $ 49,725 $ 63,484 96 10-K| FORM 10-KFair Value Employee Benefit Plan Assets Defined Benefit Pension Plan 2022 2021 Supplemental Non- qualified Defined Benefit Plans 2022 2021 Non-pension Defined Benefit Postretirement Healthcare Plan (a) 2021 2022 $ $ 458,387 (98,585) - - (36,661) 323,141 $ $ 473,721 20,165 - - (35,499) 458,387 $ $ - - 3,061 - (3,061) - $ $ - - 2,576 - (2,576) - $ $ 7,972 4 4,488 1,419 (6,131) 7,752 $ $ 8,165 (35) 4,726 1,548 (6,432) 7,972 As of December 31, Change in fair value of plan assets: Beginning fair value of plan assets Investment income (loss) Employer contributions Retiree contributions Benefits paid Ending fair value of plan assets (a) Assets of VEBA trusts. In 2012, we froze our Pension Plan and closed it to new participants. Since then, we have implemented various de-risking strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more liability-hedged portfolio. As a result, capital markets volatility had a limited impact to our unfunded status. Amounts Recognized in the Consolidated Balance Sheets As of December 31, Regulatory assets Current liabilities Non-current assets Non-current liabilities Regulatory liabilities Defined Benefit Pension Plan 2022 2021 Supplemental Non-qualified Defined Benefit Plans 2022 2021 Non-pension Defined Benefit Postretirement Healthcare Plan 2022 2021 $ $ $ $ $ 78,654 - - 35,243 2,804 $ $ $ $ $ 67,403 - - 19,872 3,830 $ $ $ $ $ - 2,231 - 42,994 - $ $ $ $ $ - 2,156 - 53,104 - $ $ $ $ $ 3,788 4,427 959 38,505 6,198 $ $ $ $ $ 11,660 4,584 - 50,949 2,447 Accumulated Benefit Obligation As of December 31, Accumulated Benefit Obligation Defined Benefit Pension Plan 2022 2021 Supplemental Non-qualified Defined Benefit Plans 2022 2021 Non-pension Defined Benefit Postretirement Healthcare Plan 2022 2021 $ 350,187 $ 466,505 $ 45,225 $ 55,260 $ 49,725 $ 63,484 Components of Net Periodic Expense Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan For the years ended December 31, Service cost Interest cost Expected return on assets Net amortization of prior service cost Recognized net actuarial loss (gain) Net periodic expense $ 2022 3,927 10,819 2021 $ 5,038 9,313 $ 2020 5,411 13,426 2022 2021 2020 2022 2021 2020 $ (801) $ 834 3,149 706 $ 1,579 1,099 $ 1,968 1,285 $ 2,237 1,058 $ 2,056 1,649 (18,523) (20,876) (22,591) (68) - - - - - - - 2 (125) (289) (136) (434) (182) (546) 6,092 2,247 $ $ 7,315 790 $ 8,372 4,618 $ 276 309 $ 1,754 5,609 $ 1,702 4,382 $ 64 2,903 $ 466 3,191 $ 20 2,997 Service costs are recorded in Operations and maintenance expense while nonservice costs were recorded in Other expense on the Consolidated Statements of Income. 97 10-KFORM 10-K |Actuarial gains and losses are amortized using a straight-line method over the average remaining service period of active plan participants or over the average remaining lifetime of the remaining plan participants if the plan is viewed as “all or almost all” inactive participants. AOCI Amounts (After-Tax) As of December 31, Net (gain) loss Prior service cost (gain) Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans 2022 $ 5,179 (39) 2021 $ 4,398 (46) 2022 $ 1,565 - 2021 $ 7,159 - Non-pension Defined Benefit Postretirement Healthcare Plan 2021 2022 $ (667) $ 74 (308) (27) $ 5,140 $ 4,352 $ 1,565 $ 7,159 $ (593) $ (335) Assumptions Weighted-average assumptions used to determine benefit obligations: Discount rate Rate of increase in compensation levels Weighted-average assumptions used to determine net periodic benefit cost for plan year: Discount rate (a) Expected long-term rate of return on assets (b) Rate of increase in compensation levels Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2022 2021 2020 2022 2021 2020 2022 2021 2020 5.17% 2.88% 2.56% 5.13% 2.77% 2.41% 5.14% 2.79% 2.41% 3.06% 3.08% 3.34% — 5.00% 5.00% N/A N/A N/A Defined Benefit Pension Plan Supplemental Non-qualified Defined Benefit Plans Non-pension Defined Benefit Postretirement Healthcare Plan 2022 2021 2020 2022 2021 2020 2022 2021 2020 2.88% 2.56% 3.27% 2.77% 2.41% 3.14% 2.79% 2.41% 3.15% 4.25% 4.50% 5.25% 3.08% 3.34% 3.49% N/A — N/A N/A 1.70% 1.80% 2.35% 5.00% 5.00% N/A N/A N/A (a) (b) The estimated discount rate for the Defined Benefit Pension Plan is 5.2% for the calculation of the 2023 net periodic pension costs. The expected rate of return on plan assets for the Defined Benefit Pension Plan is 6.0% for the calculation of the 2023 net periodic pension cost. The healthcare benefit obligation at December 31 was determined as follows: Trend Rate - Medical Pre-65 for next year - All Plans Pre-65 Ultimate trend rate - Black Hills Corp Trend Year Post-65 for next year - All Plans Post-65 Ultimate trend rate - Black Hills Corp Trend Year 2022 2021 7.00% 4.50% 2031 6.00% 4.50% 2031 6.05% 4.50% 2030 5.10% 4.50% 2030 98 10-K| FORM 10-KThe following benefit payments to employees, which reflect future service, are expected to be paid (in thousands): 2023 2024 2025 2026 2027 2028 -2032 Defined Benefit Pension Plan $ $ $ $ $ $ 26,889 26,882 27,870 28,182 28,166 140,416 Supplemental Non-qualified Defined Benefit Plans 2,231 $ 2,417 $ 2,764 $ 2,790 $ 2,727 $ 12,184 $ Non-pension Defined Benefit Postretirement Healthcare Plan 5,600 $ 5,313 $ 5,022 $ 4,883 $ 4,769 $ 21,147 $ (14) SHARE-BASED COMPENSATION PLANS On April 26, 2022, our shareholders approved the Amended and Restated 2015 Omnibus Incentive Plan (the "Amended Plan"), which was adopted by our Board of Directors and became effective on February 24, 2022. The Amended Plan increased the number of shares available for issuance under the 2015 Plan from 1,200,000 to a total of 2,900,000. The Amended Plan allows for the granting of stock, restricted stock, restricted stock units, stock options, performance shares and performance share units. We had 2,213,716 shares available to grant at December 31, 2022. Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2022, total unrecognized compensation expense related to non-vested stock awards was approximately $12 million and is expected to be recognized over a weighted-average period of 1.7 years. Stock-based compensation expense, which is included in Operations and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31 (in thousands): Stock-based compensation expense Restricted Stock 2022 2021 2020 $ 8,551 $ 9,655 $ 5,373 The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant. The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over three years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period. A summary of the status of the restricted stock and restricted stock units at December 31, 2022, was as follows: Balance at January 1, 2022 Granted Vested Forfeited Balance at December 31, 2022 Weighted-Average Grant Date Fair Value Restricted Stock (in thousands) 219 70 (94) (16) 179 $ $ 67.64 69.03 69.64 66.03 67.23 The weighted-average grant-date fair value of restricted stock granted, and the total fair value of shares vested during the years ended December 31, were as follows: 2022 2021 2020 Weighted-Average Grant Date Fair Value Total Fair Value of Shares Vested (in thousands) $ $ $ 69.03 65.64 69.49 $ $ $ 6,436 5,400 6,722 As of December 31, 2022, there was $7.5 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 1.7 years. 99 10-KFORM 10-K | Performance Share Plan Prior to 2021, certain officers of the Company and its subsidiaries became participants in a market-based performance share award plan. Performance shares are awarded based on our total shareholder return over designated performance periods as measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur. The final value of the performance shares will vary according to the number of shares of common stock that are ultimately granted based upon the actual level of attainment of the performance criteria. These performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $1.4 million at December 31, 2022 would be reclassified as a liability. The outstanding performance periods at December 31, 2022 were as follows (shares in thousands): Grant Date January 1, 2020 Performance Period January 1, 2020 - December 31, 2022 Target Grant of Shares 36 Possible Payout Range of Target Minimum 0% Maximum 200% A summary of the status of the Performance Share Plan at December 31, 2022 was as follows: Equity Portion Liability Portion Weighted- Average Grant Date Fair Value (a) $ $ 68.14 — — 68.72 81.42 Shares (in thousands) 36 — — (18) 18 Shares (in thousands) 36 — — (18) 18 Weighted- Average Fair Value at December 31, 2022 $ 32.74 Performance Shares balance at beginning of period Granted Forfeited Vested Performance Shares balance at end of period (a) The grant date fair values for the performance shares granted in 2020 were determined by Monte Carlo simulation using a blended volatility of 18%, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year United States Treasury security rate in effect as of the grant date. The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended: December 31, 2020 Performance plan payouts have been as follows (in thousands): Weighted Average Grant Date Fair Value $ 81.42 Performance Period January 1, 2019 to December 31, 2021 January 1, 2018 to December 31, 2020 January 1, 2017 to December 31, 2019 Year Paid 2022 2021 2020 Stock Issued Cash Paid 519 $ 1,647 $ 1,100 $ $ $ $ 8 28 14 Total Intrinsic Value 1,038 3,294 2,199 On January 25, 2023, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2020 to December 31, 2022 performance period was at the 26th percentile of its peer group and confirmed a payout equal to 27% of target shares, valued at $0.7 million. The payout was fully accrued at December 31, 2022. 100 10-K| FORM 10-K Performance Share Units Beginning in 2021, certain officers of the Company, and its subsidiaries, were granted performance share units which have a three-year vesting period, do not have voting rights until vested, and are subject to three specified conditions. A market condition of relative total shareholder return, and two equally weighted performance metrics of average earnings per share and the average cost to serve. The units are paid 100% in common stock should conditions be met and can range from 0% to 200% of the target award. Dividend equivalents are accrued during the vesting period and paid out based on the final number of shares awarded. In the event of participant’s death or retirement at age 55 or older, shares awarded vest on a pro-rata basis over the three-year period. Performance Share Units - Market Condition The fair value of each share unit is based on the Company’s closing price at December 31 of the year prior to the award and a Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on the Company’s TSR for a three-year performance period relative to the designated peer group beginning January 1 of the award year. Fair value of share units award Three-year risk-free rate Black Hills Corporation’s common stock volatility Volatility range for the peer group Performance Share Units - Performance Condition 2022 74.48 0.97% 30% 22-67% 2021 64.97 0.17% 33% 25-76% A performance condition share unit vests at the end of the three-year performance period if the specified performance conditions are achieved. The conditions are based on the Company’s average earnings per share and the average cost to serve. The grant-date fair value for an individual outcome of a performance condition is determined by the closing common share price on the grant date. The following table summarizes the performance share unit activity for the year ended December 31, 2022: Nonvested at January 1, 2022 Granted Nonvested at December 31, 2022 Performance Share Units - Market Condition Performance Share Units - Performance Condition Weighted- Average Fair Value per Share Unit Share Units Weighted- Average Fair Value per Share Unit Share Units 32,903 35,571 68,474 $ $ 64.97 74.48 69.91 21,948 23,718 45,666 $ $ 61.45 70.57 66.19 As of December 31, 2022, there was $4.1 million of unrecognized compensation expense related to outstanding performance share/unit plans that is expected to be recognized over a weighted-average period of 1.7 years. 101 10-KFORM 10-K |(15) INCOME TAXES Winter Storm Uri As discussed in Note 2 above, our Utilities received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow full recovery of our $546 million of incremental fuel, purchased power and natural gas costs. We will recover these costs from customers over several years, which will increase our taxable income on our tax returns by the amounts collected for each respective year. The incremental costs from Winter Storm Uri were deductible in our 2021 tax return and created a net deferred tax liability, which had balances as of December 31, 2022 and 2021 of $85 million and $124 million, respectively. The deferred tax liability is reversed with the same timing as the costs are recovered from our customers. The income tax deduction recognized from Winter Storm Uri created a $509 million NOL in our 2021 federal income tax return and a $375 million NOL in our state income tax returns. Our federal NOL carryforwards related to Winter Storm Uri and other recent adjustments no longer expire due to the TCJA; however, our state NOL carryforwards expire at various dates from 2023 to 2041. We do not anticipate material changes to our valuation allowance against the state NOL carryforwards from Winter Storm Uri. Therefore, we did not record an additional valuation allowance against the state NOL carryforwards as of December 31, 2022 and 2021. TCJA On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the federal and state utility commissions, which could have a material impact on the Company’s future results of operations, cash flows or financial position. A majority of the excess deferred taxes are subject to the average rate assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the remaining lives of the related assets. For the years ended December 31, 2022, 2021 and 2020, respectively, the Company has amortized, or provided bill credits for, $11 million, $23 million and $13 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2021 but is awaiting resolution of the treatment of these amounts in future regulatory proceedings has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings. Beginning in 2022, the TJCA modified IRC 174 which changes how taxpayers account for research and development costs. After the IRC 174 modification, taxpayers must amortize specified research and experimental expenditures performed in the United States ratably over five years instead of deducting research and experimental expenditures. This modification did not have a material impact for the year ended December 31, 2022. Income Tax Expense (Benefit) Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands): Current: Federal State Current income tax (benefit) Deferred: Federal State Deferred income tax expense 2022 2021 2020 $ (467) $ 80 (387) $ 574 (666) (92) 23,205 2,387 25,592 2,170 5,091 7,261 (6,020) 847 (5,173) 35,672 2,419 38,091 Income tax expense $ 25,205 $ 7,169 $ 32,918 102 10-K| FORM 10-KEffective Tax Rates The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows: Federal statutory rate State income tax (net of federal tax effect) (a) Non-controlling interest (b) Tax credits Flow-through adjustments (c) Uncertain Tax Benefits Valuation Allowance Other tax differences Amortization of excess deferred income tax expense (d) TCJA bill credits (e) Effective Tax Rate 2022 2021 2020 21.0% 0.5 (0.9) (7.7) (1.4) — — (0.1) (2.5) (0.4) 8.5% 21.0% 1.2 (1.2) (8.4) (3.2) 0.3 — (0.2) (3.1) (3.6) 2.8% 21.0% 2.4 (1.2) (9.2) (1.6) 1.5 0.7 0.6 (2.3) — 11.9% (a) (b) (c) (d) (e) The state effective tax rate contains the tax expense attributable to multiple statutory state rate reductions in the Company's state jurisdictions. The effective tax rate reflects the income attributable to the non-controlling interest in Black Hills Colorado IPP for which a tax provision was not recorded. Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs, certain indirect costs and gain deferral. We recorded a deferred income tax liability in recognition of the temporary difference created between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record tax benefits consistent with the flow-through method. Primarily TCJA - see above. Primarily related to one-time bill credits of TCJA benefits which were delivered to Colorado Electric and Nebraska Gas customers in 2021. These bill credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net income for the year ended December 31, 2021. Deferred Tax Assets and Liabilities The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in thousands): Deferred tax assets: Regulatory liabilities State tax credits Federal NOL State NOL Partnership Credit Carryovers Other deferred tax assets Less: Valuation allowance Total deferred tax assets Deferred tax liabilities: Accelerated depreciation, amortization and other property-related differences Regulatory assets Goodwill State deferred tax liability Other deferred tax liabilities Total deferred tax liabilities Net deferred tax liability $ 2022 2021 $ 74,728 22,817 191,992 23,031 12,755 90,881 45,407 (15,476) 446,135 (645,762) (94,433) (57,884) (98,200) (58,797) (955,076) 77,099 23,342 227,535 33,639 13,395 68,646 31,996 (14,719) 460,933 (597,284) (124,582) (45,471) (109,136) (49,848) (926,321) $ (508,941) $ (465,388) 103 10-KFORM 10-K |Net Operating Loss and Tax Credit Carryforwards At December 31, 2022, we have federal NOL and state NOL and tax credit carryforwards that will expire at various dates as follows (in thousands): Federal NOL Carryforward Federal NOL Carryforward State NOL Carryforward (a) State Tax Credit Carryforward Amounts 330,085 584,161 408,269 22,817 $ $ $ $ Expiration Dates 2023 to 2037 No expiration 2023 to 2041 2023 to 2041 (a) The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes. As of December 31, 2022, we had a $1.1 million valuation allowance against the state NOL carryforwards. Our 2022 analysis of the ability to utilize such NOLs resulted in no increase in the valuation allowance. If the valuation allowance is adjusted due to higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense. As of December 31, 2022, we had a $14 million valuation allowance against the state ITC carryforwards. Our 2022 analysis of the ability to utilize such ITC resulted in a $0.8 million increase in the valuation allowance, which resulted in an increase to tax expense of $0.6 million. The remaining $0.2 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to expiring state ITC credits. Unrecognized Tax Benefits The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in thousands): Changes in Uncertain Tax Positions: Beginning balance Additions for prior year tax positions Reductions for prior year tax positions Additions for current year tax positions Ending balance 2022 2021 2020 $ $ 10,554 7 (773) 2,097 11,885 $ $ 8,383 448 (732) 2,455 10,554 $ $ 4,165 3,788 (1,313) 1,743 8,383 The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $5.7 million. We recognized no interest expense associated with income taxes for the years ended December 31, 2022, 2021 and 2020. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2022 and 2021. The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. As of December 31, 2022, we do not have any tax positions for which it is reasonably possible that the total amount of unrecognized tax benefits will significantly increase or decrease on or before December 31, 2023. 104 10-K| FORM 10-K(16) BUSINESS SEGMENT INFORMATION Our Chief Executive Officer, who is considered to be our CODM, reviews financial information presented on an operating segment basis for purposes of making decisions, allocating resources and assessing financial performance. Our operating segments are based on our method of internal reporting, which is generally segregated by differences in products and services. All of our operations and assets are located within the United States. Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota and Wyoming. We also own and operate non-regulated power generation and mining businesses that are vertically integrated with our Electric Utilities. Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Corporate and Other represents certain unallocated expenses for administrative activities that support our operating segments. Corporate and Other also includes business development activities that are not part of our operating segments. Our CODM assesses the performance of our operating segments based on operating income. Our operating segments are equivalent to our reportable segments. Segment information was as follows (in thousands): Year ended December 31, 2022 Revenue - Contracts with customers Other revenues Inter-company operating revenue - Contracts with customers Other revenues Total revenue Fuel, purchased power and cost of natural gas sold Operations and maintenance, including taxes Depreciation, depletion and amortization Operating income (loss) Interest expense, net Impairment of investment Other income (expense), net Income tax benefit (expense) Net income Net income attributable to non-controlling interest Net income available for common stock Consolidating Income Statement Electric Utilities Gas Utilities Corporate Inter- Company Eliminations Total $ 882,899 5,548 888,447 11,715 — 11,715 900,162 $ $ 1,659,957 3,412 1,663,369 — $ — — — $ — — 2,542,856 8,960 2,551,816 5,292 429 5,721 1,669,090 538 368,201 368,739 368,739 (17,545) (368,630) (386,175) (386,175) — — — 2,551,816 266,284 965,108 (11) (831) 1,230,550 283,654 135,966 214,258 $ $ 345,143 114,679 244,160 $ 309,773 26,964 32,013 $ (323,457) (26,700) (35,187) $ $ 615,113 250,909 455,244 (160,989) — 1,708 (25,205) 270,758 (12,371) 258,387 105 10-KFORM 10-K |Electric Utilities $ 825,404 5,336 830,740 11,518 — 11,518 842,258 Consolidating Income Statement Inter- Company Eliminations Corporate Gas Utilities $ $ 1,105,430 12,932 1,118,362 — $ — — — $ — — 6,110 393 6,503 1,124,865 196 356,151 356,347 356,347 (17,824) (356,544) (374,368) (374,368) Total 1,930,834 18,268 1,949,102 — — — 1,949,102 248,018 494,738 96 (918) 741,934 260,036 131,528 202,676 $ $ 314,810 104,160 211,157 $ 293,265 26,838 36,148 $ (306,325) (26,573) (40,552) $ 561,786 235,953 409,429 (152,404) — 1,404 (7,169) 251,260 (14,516) 236,744 Total 1,680,804 16,137 1,696,941 — — — 1,696,941 Consolidating Income Statement Electric Utilities Gas Utilities Corporate Inter- Company Eliminations $ $ 721,108 6,175 727,283 11,574 — 11,574 738,857 $ 959,696 9,962 969,658 4,724 288 5,012 974,670 — $ — — — $ — — 167 352,976 353,143 353,143 (16,465) (353,264) (369,729) (369,729) 138,572 354,645 83 (896) 492,404 265,679 123,632 210,974 $ 303,577 100,559 215,889 $ 284,501 25,150 43,409 $ (301,980) (24,884) (41,969) $ $ 551,777 224,457 428,303 (143,470) (6,859) (2,293) (32,918) 242,763 (15,155) 227,608 Year ended December 31, 2021 Revenue - Contracts with customers Other revenues Inter-company operating revenue - Contracts with customers Other revenues Total revenue Fuel, purchased power and cost of natural gas sold Operations and maintenance, including taxes Depreciation, depletion and amortization Operating income (loss) Interest expense, net Impairment of investment Other income (expense), net Income tax benefit (expense) Net income Net income attributable to non-controlling interest Net income available for common stock Year ended December 31, 2020 Revenue - Contracts with customers Other revenues $ Inter-company operating revenue - Contracts with customers Other revenues Total revenue Fuel, purchased power and cost of natural gas sold Operations and maintenance, including taxes Depreciation, depletion and amortization Operating income (loss) $ Interest expense, net Impairment of investment Other income (expense), net Income tax benefit (expense) Net income Net income attributable to non-controlling interest Net income available for common stock 106 10-K| FORM 10-K Total Assets (net of intercompany eliminations) as of December 31, Electric Utilities Gas Utilities Corporate and Other Total assets 2022 3,929,721 5,578,282 110,227 9,618,230 $ $ 2021 3,796,662 5,246,370 88,864 9,131,896 $ $ Capital Expenditures (a) for the years ended December 31, 2022 2021 2020 Electric Utilities Gas Utilities Corporate and Other Total capital expenditures $ $ 243,133 349,438 5,097 597,668 $ $ 285,770 383,320 10,500 679,590 $ $ 288,683 449,209 17,500 755,392 (a) Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated Statement of Cash Flows. (17) SUBSEQUENT EVENTS Except as described in Note 2, there have been no events subsequent to December 31, 2022 which would require recognition in the Consolidated Financial Statements or disclosures. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 9A. CONTROLS AND PROCEDURES 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, 2022. 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, 2022, 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 56 of this Annual Report on Form 10-K. ITEM 9B. OTHER INFORMATION None. ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS None. PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3), 407(d)(4) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 2023 Annual Meeting of Shareholders, which is incorporated herein by reference. Information about our Executive Officers is reported in Part 1 of this Annual Report on Form 10-K. 107 10-KFORM 10-K |ITEM 11. EXECUTIVE COMPENSATION Information required under this item is set forth in the Proxy Statement for our 2023 Annual Meeting of Shareholders, which is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 2023 Annual Meeting of Shareholders, which is incorporated herein by reference. EQUITY COMPENSATION PLAN INFORMATION The following table includes information as of December 31, 2022 with respect to our equity compensation plans which includes the Amended and Restated 2015 Omnibus Incentive Plan. Plan category Number of securities to be issued upon exercise of outstanding options, warrants and rights Weighted-average exercise price of outstanding options, warrants and rights (a) (b) Equity compensation plans approved by security holders Equity compensation plans not approved by security holders Total $ $ 255,588 (1) $ --- 255,588 $ Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) - (1) $ - - $ 2,213,716 (2) --- 2,213,716 (1) (2) 255,588 full value awards outstand as of December 31, 2022, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. In addition, 163,387 shares of unvested restricted stock were outstanding as of December 31, 2022, which are not included in the table above because they have already been issued. We do not have any outstanding options, warrant or rights. Shares available for issuance are from the 2015 Amended and Restated Omnibus Incentive Plan. The 2015 Amended and Restated Omnibus Incentive Plan permits grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, cash-based awards and other stock-based awards. 108 10-K| FORM 10-KITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE Information regarding certain relationships and related transactions and director independence is set forth in the Proxy Statement for our 2023 Annual Meeting of Shareholders, which is incorporated herein by reference. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES Information regarding principal accounting fees and services billed to us by our principal accountant, Deloitte & Touche LLP (PCAOB ID No. 34) is set forth in the Proxy Statement for our 2023 Annual Meeting to Shareholders, which is incorporated herein by reference. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES (a) Documents filed as part of this report 1. Consolidated Financial Statements Financial statements required under this item are included in Item 8 of Part II 2. Schedules All other schedules have been omitted because of the absence of the conditions under which they are required or because the required information is included in our consolidated financial statements and notes thereto. Consolidated valuation and qualifying accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K. 3. Exhibits Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting a board of director or management compensatory plan are designated by a cross (†). Exhibit Number Description 2.1 2.2 2.3 3.1 3.2 4.1 4.1.1 4.1.2 4.1.3 4.1.4 Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer, dated as of July 12, 2015 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on July 14, 2015). First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015). Option Agreement, by and among, Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 8-K filed on July 14, 2015). Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 5, 2018). Amended and Restated Bylaws of the Registrant dated April 24, 2017 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on April 28, 2017). Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2003). Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K filed on May 14, 2009). Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010). Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8- K filed on November 18, 2013). 109 10-KFORM 10-K |4.1.5 4.1.6 4.1.7 4.1.8 4.1.9 4.1.10 4.2 4.2.1 4.2.2 4.2.3 4.3 4.3.1 4.3.2 4.4 4.5 10.1† 10.1.1† 10.1.2† Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on January 13, 2016). Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 19, 2016). Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8- K filed on August 17, 2018). Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on October 4, 2019). Ninth Supplemental Indenture dated as of June 17, 2020 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on June 17, 2020). Tenth Supplemental Indenture dated as of August 26, 2021 (filed as Exhibit 4.1 to the Registrant’s Form 8-K filed on August 26, 2021). Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)). Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014). Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014). First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed on October 2, 2014). Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed on October 2, 2014). Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the Registrant’s Form 10-K for 2000). Description of Securities (filed as Exhibit 4.5 to the Registrant's Form 10-K for 2019) Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001). First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002). Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation (filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008). 10.2† Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008). 10.2.1† 10.3† 10.3.1† 10.4*† 10.5† 10.5.1† 10.5.2† First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2 to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011). Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010). First Amendment to the Black Hills Corporation Nonqualified Deferred Compensation Plan as Amended and Restated effective January 1, 2011 (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2018). Black Hills Corporation Post-2018 Nonqualified Deferred Compensation Plan. Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005). First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008). Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010). 110 10-K| FORM 10-K10.6*† 10.7† 10.8† 10.9† 10.10† 10.11† 10.12† 10.13† 10.14† 10.15† 10.16† 10.17*† 10.18*† 10.19† 10.19.1† 10.19.2† 10.19.3† 10.19.4† 10.19.5† 10.19.6† 10.20† 10.21 10.22 10.23 10.24 10.25 Black Hills Corporation Amended and Restated 2015 Omnibus Incentive Plan effective Janaury 24, 2023. Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014 (filed as Exhibit 10.7 to the Registrant’s Form 10-K for 2013). Form of Stock Option Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.8 to Registrant’s Form 10-K for 2015). Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2015). Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on or after January 26, 2021. (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2020) Form of Restricted Stock Unit Award Agreement for 2015 Omnibus Plan effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2015). Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2016 (filed as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016). Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2017 (filed as Exhibit 10.12 to the Registrant's Form 10-K for 2019). Form of Short-term Incentive Plan for Officers Award Agreement effective for awards granted on or after January 1, 2021 (filed as Exhibit 10.16 to the Registrant's Form 10-K for 2020). Form of Performance Unit Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on or after January 1, 2021. (filed as Exhibit 10.17 to the Registrant's Form 10-K for 2020) Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3, 2004). Change in Control Agreement dated November 15, 2022 between Black Hills Corporation and Linden R. Evans. Change in Control Agreements dated November 15, 2022 between Black Hills Corporation and its non-CEO Senior Executive Officers. Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed as Exhibit 10.23 to the Registrant’s Form 10-K for 2008). First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2010). Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013 (filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012). Third Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2015 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2014). Fourth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2017 (filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2016). Fifth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2018 (filed as Exhibit 10.16 to the Registrant’s Form 10-K for 2017). Sixth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2019 (filed as Exhibit 10.18 to the Registrant’s Form 10-K for 2018). Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.8 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016). Equity Distribution Sales Agreement dated August 4, 2020 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on August 4, 2020). Fourth Amended and Restated Credit Agreement dated as of July 19, 2021 (relating to $750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8- K filed on July 19, 2021). Credit Agreement dated as of February 24, 2021 among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks, and U.S. Bank National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8–K filed on February 25, 2021). Non-Employee Director Equity Compensation Plan effective January 1, 2022 (filed as Exhibit 10.25 to the Registrant's Form 10-K filed on Februrary 15, 2022). Form of Restricted Stock Unit Award Agreement (Non-Employee Director) effective for awards granted on or after January 1, 2022 (filed as Exhibit 10.26 to the Registrant's Form 10-K filed on February 15, 2022). 111 10-KFORM 10-K |10.26 10.27 10.28*† 10.29*† 10.30*† 21* 23.1* 31.1* 31.2* 32.1* 32.2* 95* 101.INS* Coal Leases between WRDC and the Federal Government -Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10-K for 1989) -Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10-K for 1989) -Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S-7, File No. 2-60755) -Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10-K for 1989). Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr- McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997). Form of Short-term Incentive Plan Award Agreement for the Amended and Restated 2015 Omnibus Incentive Plan effective for awards granted on or after January 1, 2023. Form of Performance Unit Award Agreement for the Amended and Restated 2015 Omnibus Incentive Plan effective for awards granted on or after January 1, 2023. Form of Restricted Stock Award Agreement for the Amended and Restated 2015 Omnibus Incentive Plan effective for awards granted on or after January 24, 2023. List of Subsidiaries of Black Hills Corporation. Consent of Independent Registered Public Accounting Firm. Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002. Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Mine Safety and Health Administration Safety Data Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document 101.SCH* Inline XBRL Taxonomy Extension Schema Document 101.CAL* Inline XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF* Inline XBRL Taxonomy Extension Definition Linkbase Document 101.LAB* Inline XBRL Taxonomy Extension Label Linkbase Document 101.PRE* Inline XBRL Taxonomy Extension Presentation Linkbase Document 104* Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) ITEM 16. FORM 10-K SUMMARY None. 112 10-K| FORM 10-KPursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. SIGNATURES BLACK HILLS CORPORATION By: /S/ LINDEN R. EVANS Linden R. Evans, President and Chief Executive Officer Dated: February 14, 2023 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. /S/ STEVEN R. MILLS Steven R. Mills /S/ LINDEN R. EVANS Linden R. Evans, President and Chief Executive Officer Director and Chairman Director and Principal Executive Officer February 14, 2023 February 14, 2023 /S/ RICHARD W. KINZLEY Principal Financial and February 14, 2023 Richard W. Kinzley, Senior Vice President Accounting Officer and Chief Financial Officer /S/ BARRY M. GRANGER Barry M. Granger /S/ TONY A. JENSEN Tony A. Jensen Director Director February 14, 2023 February 14, 2023 /S/ KATHLEEN S. MCALLISTER Director February 14, 2023 Kathleen S. McAllister /S/ ROBERT P. OTTO Robert P. Otto Director February 14, 2023 /S/ SCOTT M. PROCHAZKA Director February 14, 2023 Scott M. Prochazka /S/ REBECCA B. ROBERTS Director February 14, 2023 Rebecca B. Roberts /S/ MARK A. SCHOBER Mark A. Schober /S/ TERESA A. TAYLOR Teresa A. Taylor Director Director February 14, 2023 February 14, 2023 113 10-KFORM 10-K |(This page has been left blank intentionally.) 114 10-K| FORM 10-KINVESTOR INFORMATION Common Stock Transfer Agent, Registrar & Dividend Disbursing Agent EQ Shareowner Services P.O. Box 64854 St. Paul, MN 55164-0854 800-468-9716 www.shareowneronline.com Senior Unsecured Notes — Black Hills Corporation Computershare Trust Company, N.A. Corporate Trust WF 8113 P.O. Box 1450 Minneapolis, MN 55485 First Mortgage Bonds — Black Hills Power, Inc. The Bank of New York Mellon Corporate Trust, CF 101 Barclay 7 West New York, NY 10286 First Mortgage Bonds — Cheyenne Light, Fuel & Power Computershare Trust Company, N.A. Corporate Trust WF 8113 P.O. Box 1450 Minneapolis, MN 55485 Industrial Development Revenue Bonds — Cheyenne Light, Fuel & Power Trustee & Paying Agent Corporate Trust Services US Bank National Association EP-MN-WN3L 60 Livingston Avenue St. Paul, MN 55107 Corporate Offices Black Hills Corporation P.O. Box 1400 7001 Mount Rushmore Road Rapid City, SD 57709 605-721-1700 www.blackhillscorp.com 2023 Annual Meeting The Annual Meeting of Shareholders will be held at Horizon Point, the Company’s corporate headquarters at 7001 Mount Rushmore Road, Rapid City, South Dakota, at 9:30 a.m. local time on Tuesday, April 25, 2023. Prior to the meeting, formal notice, proxy statement and proxy will be mailed to shareholders. Market for Equity Securities The Company’s Common Stock ($1 par value) is traded on the New York Stock Exchange. Quotations for the Common Stock are reported under the symbol BKH. The continued interest and support of equity owners are appreciated. The Company has declared Common Stock dividends payable in each year since its incorporation in 1941. Regular quarterly dividends when declared are normally payable on March 1, June 1, September 1 and December 1. Internet Account Access Registered shareholders can access their accounts electronically at www.shareowneronline.com. Shareowner Online allows shareholders to view their account balance, dividend information, reinvestment details and much more. The transfer agent maintains stockholder account access. Direct Deposit of Dividends We encourage you to consider the direct deposit of your dividends. With direct deposit, your quarterly dividend payment can be automatically transferred on the dividend payment date to the bank, savings and loan, or credit union of your choice. Direct deposit assures payments are credited to shareholders’ accounts without delay. A form is attached to your dividend check where you can request information about this method of payment. Questions regarding direct deposit should be directed to EQ Shareowner Services. Dividend Reinvestment and Direct Stock Purchase Plan A Dividend Reinvestment and Direct Stock Purchase Plan provides interested investors the opportunity to purchase shares of the Company’s Common Stock and to reinvest all or a percentage of their dividends. For complete details, including enrollment, contact the transfer agent, EQ Shareowner Services. Plan information is also available at www.shareowneronline.com. Website Access to Reports The reports we file with the Securities and Exchange Commission are available free of charge at our website www. blackhillscorp.com as soon as reasonably practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance Officer, Corporate Governance Guidelines of our Board of Directors, and Policy for Director Independence. 2022 Annual Report | Proxy Statement | Form 10-K | www.blackhillscorp.com

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