BKH 10-K & 10-Q changes, risk factors and insider trading
Black Hills Corp. · NYSE · Electric Services · CIK 1130464 · All filings on SEC.gov
At a glance
What changed in the latest 10-K
Risk Factors
New heading “RISKS RELATED TO MERGER WITH NORTHWESTERN”
New heading “The ability of BHC and NorthWestern to complete the Merger is subject to various closing conditions, including the receipt of approval of BHC and NorthWestern shareholders and the receipt of consents and approvals from various governmental authorities, which may impose conditions that could adversely affect BHC or NorthWestern or cause the Merger to be abandoned. Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of BHC common stock or other securities and the future business and financial results of BHC.”
New heading “The Merger Agreement contains provisions that limit BHC's ability to pursue alternatives to the Merger, could discourage a potential acquirer of BHC from making a favorable alternative transaction proposal and, in certain circumstances, could require BHC to pay a termination fee to NorthWestern.”
New heading “Members of the management and the boards of directors of BHC and NorthWestern have interests in the Merger that are different from, or in addition to, those of other shareholders and that could have influenced their decisions to support or approve the Merger.”
New heading “Uncertainties associated with the Merger may cause a loss of management personnel and other key employees of BHC and NorthWestern, which could adversely affect the future business and operations of the combined company following the Merger.”
New heading “The business relationships of BHC and NorthWestern may be subject to disruption due to uncertainty associated with the Merger, which could have a material effect on the business, financial condition, cash flows and results of operations of BHC or NorthWestern pending the combined company and following the Merger.”
New heading “BHC is subject to risk of the Merger having an adverse impact on its credit rating, both while the Merger is pending and following completion of the Merger.”
New heading “The market prices of BHC common stock and other securities may be subject to fluctuation while the Merger is pending and after the Merger is completed.”
New heading “BHC is subject to contractual restrictions in the Merger Agreement that may hinder its operations while the Merger is pending. The corollary restrictions applicable to NorthWestern may not prevent NorthWestern from taking actions that are adverse to BHC or its shareholders.”
New heading “BHC will incur significant transaction and other costs in connection with the Merger.”
New heading “The Merger may not be accretive to BHC's or NorthWestern’s earnings and may cause dilution to BHC's or NorthWestern’s earnings per share, which may negatively affect the current or future market price of BHC common stock or other securities.”
New heading “BHC and/or NorthWestern may be subject to litigation challenging the Merger while it is pending, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.”
New heading “RISKS RELATING TO THE COMBINED COMPANY FOLLOWING COMPLETION OF THE MERGER”
New heading “Failure to successfully combine the businesses of BHC and NorthWestern in the expected time frame or at all may adversely affect the future results of the combined company, and, consequently, the value of the BHC common stock after the Merger.”
New heading “BHC shareholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over management.”
New heading “The market price of BHC common stock after the completion of the Merger may be affected by factors different from those that historically have affected or currently affect BHC common stock.”
New heading “The failure to integrate the businesses and operations of BHC and NorthWestern successfully in the expected time frame may adversely affect the combined company’s future results.”
New heading “Each of BHC and NorthWestern may have liabilities that are not known to the other party.”
New heading “Each of NorthWestern and BHC and their respective subsidiaries has substantial amounts of indebtedness. Consequently, the combined company will have substantial indebtedness following the Merger. As a result, the rating of the combined company’s indebtedness could be downgraded, and it may be difficult for the combined company to pay or refinance its debts or take other actions, and the combined company may need to divert its cash flow from operations to debt service payments.”
New heading “The combined company may fail to realize all of the anticipated benefits of the Merger.”
New heading “The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.”
New heading “There is no guarantee regarding dividends following the Merger.”
New heading “The combined company is expected to record a significant amount of goodwill as a result of the Merger, and such goodwill could become impaired in the future.”
New heading “BHC's ability to utilize its and/or NorthWestern’s historic net operating loss carryforwards and certain other tax attributes may be limited.”
New heading “Future sales or issuances of BHC common stock could have a negative impact on the BHC common stock price.”
Largest changes
“To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive information including personal information about our customers and employees. Cybersecurity incidents, terrorism, or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or natural gas operations. …”see in full comparison
“To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive information including personal information about our customers and employees. Cybersecurity incidents, terrorism, or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or natural gas operations. …”see in full comparison
“BHC and/or NorthWestern may be subject to litigation challenging the Merger while it is pending, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.”see in full comparison
“Both BHC and NorthWestern may have liabilities that the other party failed, or was unable, to discover in the course of performing its respective due diligence investigations. BHC and NorthWestern may learn additional information about the other party that materially adversely affects it, such as unknown or contingent liabilities and liabilities related to compliance with applicable laws. …”see in full comparison
“Each of NorthWestern and BHC and their respective subsidiaries has substantial amounts of indebtedness. Consequently, the combined company will have substantial indebtedness following the Merger. As a result, the rating of the combined company’s indebtedness could be downgraded, and it may be difficult for the combined company to pay or refinance its debts or take other actions, and the combined company may need to divert its cash flow from operations to debt service payments.”see in full comparison
“BHC will be required to assess goodwill for impairment at least annually. To the extent goodwill becomes impaired, BHC may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on BHC's future operating results and statements of financial position which may, in turn, have a material adverse effect on the trading price or liquidity of BHC securities.”see in full comparison
Full comparison: every changed paragraph (123)
In addition, we have significant capital investment programs planned for the next five years that are key to our strategic business plan, such as: our ReadyLange Wyoming transmissionII project; the acquisition of a renewable generating facility and energybattery storage facility as part of our Colorado Clean Energy Plan; the addition of 99 MWs of natural gas-fired generation in South Dakota; large-scale investments to upgrade existing utility infrastructure; support of customer and community growth needs; and compliance with safety requirements. The successful execution of our capital investment program depends on, or could be affected by, a variety of factors that include, but are not limited to: access to capital markets on reasonable terms to fund projects, weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity prices, impacts of supply chain disruptions on availability and cost of materials, governmental approvals and permitting, regulatory cost recovery, and return on investment.invested capital. Our capacity requirements and applicable reserve margins are a critical component to serving our customers. Delays in construction, increasing reserve margins, and growing demand put additional pressures on meeting resource adequacy requirements. An inability to successfully adapt to changing conditions and execute our strategic plan, including our capital investment program, could materially affect our financial operating results including earnings, cash flow, and liquidity.
Our regulated Utilities are subject to cost-of-service/rate-of-return regulation and earnings oversight from federal and eight state utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our customer rates are regulated based on an analysis of our costs and investments, as reviewed and approved in regulatory proceedings. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that our various regulatory authorities will judge all of our costs to have been prudently incurred or that the regulatory process in which rates are determined will result in full or timely recovery of our costs with a reasonable return on invested capital. In addition, adverse rate decisions, including rate moratoriums, rate refunds, limits on rate increases, lower allowed returns on investments or rate reductions, could be influenced by competitive, economic, political, legislative, public perceptionperception, affordability concerns and regulatory pressures and adversely impact earnings, cash flow, and liquidity.
ThereSubstantial ischanges in federal climate and emissions policies may create long-term uncertainty regardingin ifour resource planning and whencapital newinvestment climatedecisions. legislation,At regulationsthe local or policiesstate will be adopted to reduce or limit GHG and the impact anylevel, such regulationsas wouldin haveColorado, on us. Newnew 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,to the acceleration of capital expenditures, the purchase of additional emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the closure or capacity reductions of coal-fired power generation facilities or conversion to alternative fuels,resources and potential decreased production from our combined cycle natural gas-fired generating units. Additional rules and regulations associated with fossilelectrification fuels and GHG emissionsinitiatives could resultnegatively inimpact thedemand impairment or retirement of some of our existing or future transmission, distribution, generation andfor natural gas storageand facilities orlimit our coalcapital mine.investments Further,in thesenatural rulesgas could create the need to purchase or build clean-energy fuel sources to fulfill obligations to our customers.assets. These actions could also result in increased operating costs which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity. We cannot definitively estimate the effect of GHGclimate and emissions legislation or regulation on our earnings, cash flow and liquidity.
Our Electric Utilities and non-regulated power generation entities own and operate renewable energy generating facilities. These facilities produce PTCs and ITCs used to reduce our federal tax obligations. The amount of tax credits we earn depends on the date the qualifying generating facilities are placed in service and various operating and economic factors, including facility generation, transmission constraints, unfavorable trends in pricing for wind or solar energy, adverse weather conditions, the breakdown or failure of equipment, and the applicable tax credit rate. These factors could significantly reduce the PTCs and ITCs produced by our wind farms, resulting in increased federal income tax expense. The IRA of 2022 allows for the sale or transfer of renewable tax credits to other taxpayers. The OBBBA, enacted in July 2025, does not repeal tax credit transferability provisions enacted under the IRA and continues to permit the execution of our transferability agreements as originally agreed upon, but restricts credit transfers to prohibited foreign entities. We have sold and plan to continue to sell tax credits if market conditions are favorable. Our inability to generate, transfer, or sell these credits could have a material impact on our financial condition, results of operations and cash flows.
To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive information including personal information about our customers and employees. Cybersecurity incidents, terrorism, or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or natural gas operations. Attacks targeting other key technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other nation state actors and individuals. Additionally, artificial intelligence, including generative artificial intelligence, may be used to facilitate or perpetrate these cybersecurity threats, and our use of generative artificial intelligence (and use by our vendors and agents) may subject us to data privacy, legal, and security risks. Any disruption of our electric and/or natural gas operations could result in a loss of service to customers and associated revenues, as well as significant expense to repair damages and remedy security breaches. In addition, any theft, loss, and/or fraudulent use of customer, shareowner, employee, or proprietary data could subject us to significant litigation, liability, and costs, as well as adversely impact our reputation with customers and regulators, among others. We maintain cyber risk insurance to mitigate a portion, but not all, of these risks and losses.
Environmental factors including precipitation, temperature, humidity and wind speeds have the potential to increase the likelihood and impact of a wildfire event. We invest resources on initiatives designed to mitigate wildfire risks and also established our Emergency PSPS program in 2025. Recent legislation by the states of Wyoming and Montana provide material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. However, the potential for a wildfire event exists even when effective mitigation procedures are followed. Despite our wildfire mitigation initiatives, we could ignite a wildfire, which could spread and cause damages and would subject us to significant liability. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, uninsured losses or losses in excess of current insurance coverage, increased costs of insurance, damage to our reputation, regulatory recovery risk, litigation risk, the potential for a credit downgrade or the inability to access capital markets on reasonable terms.
Environmental factors including precipitation, temperature, humidity and wind speeds have the potential to increase the likelihood and impact of a wildfire event. We invest resources on initiatives designed to mitigate wildfire risks and also intend to implement a PSPS framework in 2025. The potential for a wildfire event exists even when effective mitigation procedures are followed. Despite our wildfire mitigation initiatives, a wildfire could be ignited, spread and cause damages, which would subject us to significant liability. Other potential risks associated with wildfires include the inability to secure sufficient insurance coverage, uninsured losses or losses in excess of current insurance coverage, increased costs of insurance, damage to our reputation, regulatory recovery risk, litigation risk, the potential for a credit downgrade or the inability to access capital markets on reasonable terms.
Unanticipated price increases due to recent macroeconomic factors, such as imposition of tariffs, inflation, including wage inflation, imposition of new tariffs, or rising demand for rawkey materials associatedsuch as transformers, generation units and equipment to meet the rapid pace of expansion with theprospective Energyand Transitionexisting data center customers; and Supply restrictions beyond our control or the control of our suppliers such as disruption of the freight system (e.g. labor union strikes, disruptions of trade routes), new or increased tariffs or quotas, increased environmental threats from weather-related disasters, rising demand for rawkey materials associated with the Energy Transition,materials, and/or geopolitical unrest.
To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive information including personal information about our customers and employees. Cybersecurity incidents, terrorism, or other malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or natural gas operations. Attacks targeting other key technology systems, including our third-party vendors’ information systems, could further add to a full or partial disruption of our operations. The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist organizations, other nation state actors and individuals. In addition, the advancement of AI has given rise to additional vulnerabilities and potential entry points for cyberattacks. Any disruption of our electric and/or natural gas operations could result in a loss of service to customers and associated revenues, as well as significant expense to repair damages and remedy security breaches. In addition, any theft, loss, and/or fraudulent use of customer, shareowner, employee, or proprietary data could subject us to significant litigation, liability, and costs, as well as adversely impact our reputation with customers and regulators, among others. We maintain cyber risk insurance to mitigate a portion, but not all, of these risks and losses.
The risks associated with managing these operations include the following:
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.confidence;
Inherent dangers. Electricity and natural gas can be dangerous to employees and the general public. Failures of or contact with power lines, natural gas pipelines, or service facilities and equipment may result in fires (discussed above), explosions, property damage, and personal injuries, including death. While we maintain liability and property insurance coverage, such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully covered by our insurance.insurance;
Weather, natural conditions, and disasters including impacts from climate change (discussed below).;
Acts of sabotage, terrorism, or other malicious physical attacks. Damage to our facilities due to deliberate acts could lead to outages or other adverse effects.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.efficiency;
Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those operated by unaffiliated parties, to deliver the electricity and natural gas that we sell to our retail and wholesale customers. If transmission is interrupted physically, mechanically or with cyber means, our ability to sell or deliver utility services and satisfy our contractual obligations may be hindered.hindered;
Natural gas supply for generation and distribution. Our regulated Utilities and non-regulated entities purchase natural gas from a number of suppliers for our generating facilities and for distribution to our customers. Our operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations, weather, sabotage, cyber-attacks, and environmental regulations.regulations;
Replacement power. We may incur increased cost of supplying or securing replacement power during scheduled and unscheduled outages of generation facilities.facilities;
Governmental permits. The inability to obtain required governmental permits and approvals along with the cost of complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate.operate;
Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and contractual agreements, including those that restrict the timing of generation plant scheduled outages.outages;
Increased costs. Increased capital and operating costs to comply with increasingly stringent laws and regulations, unexpected engineering, environmental and geological problems, and unanticipated cost overruns.overruns;
Supply chain challenges (discussed above).;
Workforce capabilities and labor relations (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.
Transition risks of climate change include changes to the energy systems as a result of new technologies, changing customer demand, and/or expectations and voluntary GHG reduction goals, as well as local, state, or federal regulatory requirements (discussed above). Policies such as a carbon or methane tax could increase costs associated with fossil fuel usage, resulting in higher operating costs including costs of energy generation, construction, and transportation. Risks of the transition to a low-carbon economy could result in shrinking customer demand for fossil fuel-based energy sources. This could come from increased use of behind the meter technology, such as residential solar and storage. Risk of investor pressure over climate risk and/or ESGsustainability standards, activist campaigns against coal producers, employee preferences to work for companies with certain sustainability goals, and consumers preference for renewable energy could impact our reputation, ability to attract and retain an appropriately trained workforce, and overall access to capital and/or adequate insurance policies.
Demand for electricity and natural gas can vary greatly based upon the following:
Fluctuations in customer growth and general economic conditions in our service territories. Customer growth and energy use can be negatively impacted by population declines or the loss of large-load industrial customers (including data center facilities) as well as adverse economic factors in our service territories, including recession, inflation, workforce reductions, stagnant wage growth, changing levels of support from state and local government for economic development, business closings, and reductions in the level of business investment. 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.bills;
Weather conditions. Our Utilities are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our Utilities have historically generated lower revenues, income and cash flows when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation.
Weather conditions. Our Utilities are seasonal businesses and weather conditions and patterns can have a material impact on our operating performance. Demand for electricity is typically greater in the summer and winter months associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first and fourth quarters related to the heating season. Accordingly, our Utilities have historically generated lower revenues, income and cash flows when weather conditions are cooler than normal in the summer and warmer than normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation; and Our customers' focus on energy conservation which may be assisted by emerging technologies. Customer growth and usage may be impacted by the voluntary reduction in consumption of electricity and natural gas by our customers in response to increases in prices and affordability concerns, energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas, economic conditions (i.e., inflation, recession) impacting customers’ disposable income and the use of distributed generation resources or other emerging technologies. Continued technological improvements may make customer and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines, solar cells, and batteries, more cost effective and feasible for our customers. If more customers utilize their own generation, demand for energy from us could decline. Such developments could affect the price and/or delivery of energy, require further improvements to our distribution systems to address changing load demands and could make portions of our electric system's power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives.
As part of our planning process, we estimate the fluctuations in customer growth and general economic conditions, weather, and customer energy conservation efforts, but risks still remain. The rapid growth of data centers may make it more difficult to accurately forecast load demand or to recover additional costs. Any of these matters, as well as any regulatory delay in adjusting rates as a result of reduced customer usage from effective conservation measures or the adoption of new technologies, could adversely impact our results of operations and financial condition. In addition, elimination or reduced financial support of programs that provide energy assistance to our customers, could impact the demand for energy.
In recent years, securing adequate insurance coverage has become more difficult and the cost of insurance has increased substantially. We believe that these trends are likely to continue. Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance industry and the financial condition of insurers. Additionally, insurance providers could deny coverage or decline to extend coverage under the same or similar terms that are presently available to us. Through our captive insurance cell, we take certain insurance risk on our businesses including certain transmission and employment practice liabilities. A loss for which we are not adequately insured could materially affect our financial results. The coverage we currently have in place may not apply to a particular loss, or it may not be sufficient to cover all liabilities to which we may be subject, including liability and losses associated with wildfires, natural gas and storage field explosions, cyber-security breaches, environmental hazards, and natural disasters. Further, the proceeds of any such insurance may not be received in a timely manner.
RISKS RELATED TO MERGER WITH NORTHWESTERN
The ability of BHC and NorthWestern to complete the Merger is subject to various closing conditions, including the receipt of approval of BHC and NorthWestern shareholders and the receipt of consents and approvals from various governmental authorities, which may impose conditions that could adversely affect BHC or NorthWestern or cause the Merger to be abandoned. Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of BHC common stock or other securities and the future business and financial results of BHC.
To complete the Merger, BHC and NorthWestern shareholders must vote to approve a number of proposals related to the Merger and the Merger Agreement. Further, the Merger is subject to the satisfaction or waiver of certain closing conditions, including, (1) the effectiveness of the registration statement on Form S-4 relating to the Merger (which registration statement was filed on January 30, 2026, and was declared effective on February 6, 2026); (2) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the HSR Act, and approval from the FERC and certain state regulatory commissions, in each case on such terms and conditions that would not result in a material adverse effect on the combined company; (3) the absence of any court order or regulatory injunction prohibiting completion of the Merger; (4) the authorization for listing of shares of BHC Common Stock to be issued in connection with the Merger on the NYSE or other mutually-agreed stock exchange; (5) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (6) compliance by each party in all material respects with its covenants under the Merger Agreement; (7) the absence of a material adverse effect on each party; and (8) receipt by each party of an opinion relating to the anticipated tax-free treatment of the Merger. If the foregoing conditions are not satisfied or waived, one or both of BHC or NorthWestern would not be required to complete the Merger.
BHC and NorthWestern have not yet obtained shareholder approval or all of the regulatory consents and approvals required to complete the Merger. Governmental or regulatory agencies could seek to block or challenge the Merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the Merger. BHC and NorthWestern will be unable to complete the Merger until the waiting period under the HSR Act has expired or been terminated and the required governmental approvals have been received. Regulatory authorities may impose certain requirements or obligations as conditions for their approval. The Merger Agreement may require BHC and/or NorthWestern to accept conditions from these regulators that could adversely impact the combined company. If the required governmental approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then neither BHC nor NorthWestern will be obligated to complete the Merger.
There can be no assurance that a challenge to the Merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.
Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the Merger, governmental authorities could seek to block or challenge the Merger as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a private party could initiate an action under the antitrust laws challenging or seeking to enjoin the Merger, before or after they are completed. BHC or NorthWestern may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.
The special meetings at which the BHC shareholders and the NorthWestern shareholders will vote on the transactions contemplated by the Merger Agreement may take place before all regulatory approvals have been obtained and, in cases where they have not been obtained, before the terms of any conditions to obtain such regulatory approvals that may be imposed are known. As a result, if shareholder approval of the transactions contemplated by the Merger Agreement is obtained at such meetings, BHC and NorthWestern may make decisions after the meetings to waive a condition or approve certain actions required to obtain the necessary approvals without seeking further shareholder approval. Such actions could have an adverse effect on the combined company.
If BHC and NorthWestern are unable to complete the Merger, or there is a significant delay in completing the Merger, BHC would be subject to a number of risks, including the following:
BHC would not realize the anticipated benefits of the Merger, including, among other things, increased operating efficiencies and future cost savings;
the attention of management of BHC may have been diverted to the Merger rather than to its own operations and the pursuit of other opportunities that could have been beneficial to BHC;
the potential loss of key personnel during the pendency of the Merger as employees may experience uncertainty about their future roles with the combined company;
BHC will have been subject to certain restrictions on the conduct of its business, which may prevent BHC from making certain acquisitions or dispositions or pursuing certain business opportunities while the Merger is pending;
the trading price of BHC common stock or other securities may decline to the extent that the current market prices reflect a market assumption that the Merger will be completed; and the parties may be liable for damages to one another, or have to pay a termination fee, under the Merger Agreement.
BHC can provide no assurance that the various closing conditions will be satisfied and that the required governmental approvals and other approvals will be obtained, or that any required conditions will not materially adversely affect the combined company following the Merger. In addition, BHC can provide no assurance that these conditions will not result in the abandonment or delay of the Merger. The occurrence of these events individually or in combination could have a material adverse effect on BHC's results of operations and the trading price of BHC common stock or other securities.
The Merger Agreement contains provisions that limit BHC's ability to pursue alternatives to the Merger, could discourage a potential acquirer of BHC from making a favorable alternative transaction proposal and, in certain circumstances, could require BHC to pay a termination fee to NorthWestern.
Under the Merger Agreement, BHC and NorthWestern have agreed, subject to certain exceptions with respect to unsolicited proposals, not to directly or indirectly solicit competing acquisition proposals or to enter into discussions concerning, or provide confidential information in connection with, any unsolicited alternative acquisition proposals. Additionally, the BHC board of directors and the NorthWestern board of directors are each required to recommend the approval of the applicable transaction-related proposals to its respective shareholders, subject to certain exceptions. Prior to the approval of the transaction-related proposals by their respective shareholders, the BHC board of directors or the NorthWestern board of directors may change its recommendation in response to an unsolicited proposal for an alternative transaction, if such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that the proposal constitutes or would reasonably be expected to lead to a “Superior NorthWestern Proposal” or “Superior BHC Proposal”, as applicable (as such terms are defined in the Merger Agreement), and that failure to take such action would be inconsistent with their fiduciary duties under applicable law to the applicable company and its shareholders under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. Prior to the approval of the transaction-related proposals by their respective shareholders, the BHC board of directors and the NorthWestern board of directors may also change its recommendation upon the occurrence of a “NorthWestern Intervening Event” or “BHC Intervening Event”, as applicable (as such terms are defined in the Merger Agreement), and such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that failing to change its recommendation would be inconsistent with its fiduciary duties under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. The Merger Agreement is subject to a “force-the-vote” provision, which means neither BHC nor NorthWestern would have an independent right to terminate the Merger Agreement to accept a superior proposal. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of BHC from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher market value than the market value proposed to be received or realized in the merger, or might result in a potential acquirer proposing to pay a lower price than it would otherwise have proposed to pay. As a result of these restrictions, BHC may not be able to enter into an agreement with respect to a more favorable alternative transaction, or may be able to do so only by incurring potentially significant liability to NorthWestern.
The Merger Agreement contains certain customary termination rights for each of BHC and NorthWestern; provided, that, either party would be required to pay to the other a termination fee equal to $100 million upon termination of the Merger Agreement in certain circumstances involving (i) a change in recommendation by such party’s board of directors (including, in certain circumstances, the failure of such party to publicly reaffirm its recommendation upon request) or (ii) a party entering into a definitive agreement in respect of a competing transaction within twelve months of termination of the Merger Agreement in certain circumstances involving a potential competing acquisition proposal.
Members of the management and the boards of directors of BHC and NorthWestern have interests in the Merger that are different from, or in addition to, those of other shareholders and that could have influenced their decisions to support or approve the Merger.
In considering whether to approve the transactions contemplated by the Merger Agreement, BHC shareholders and NorthWestern shareholders should recognize that some of the members of management and the boards of directors of BHC and NorthWestern have interests in the Merger that differ from, or are in addition to, their interests as shareholders of BHC and shareholders of NorthWestern. These interests include (1) their designation as directors or executive officers of the combined company, (2) the fact that completion of the Merger will result in the acceleration of vesting of equity-based awards held by certain members of management and directors and (3) the fact that certain members of management have entered into change of control agreements with NorthWestern or BHC, as applicable, that will entitle them to cash payments and other benefits if the Merger is completed and their employment is terminated or if the executive terminates his or her employment with good reason as defined in the agreements.
Uncertainties associated with the Merger may cause a loss of management personnel and other key employees of BHC and NorthWestern, which could adversely affect the future business and operations of the combined company following the Merger.
Each of BHC and NorthWestern depends on the experience and industry knowledge of its officers and other key employees to execute its business plans. The success of the combined company after the Merger will depend in part on its ability to retain key management personnel and other key employees. Current and prospective employees of BHC and NorthWestern may experience uncertainty about their roles within the combined company following the Merger or other concerns regarding the timing and completion of the Merger or the operations of the combined company following the Merger, any of which may have an adverse effect on the ability of BHC and NorthWestern to retain or attract key management and other key personnel. If BHC or NorthWestern is unable to retain personnel, including BHC's or NorthWestern’s key management, who are critical to the future operations of the companies, BHC and NorthWestern could face disruptions in their operations, loss of existing customers, loss of key information, expertise or know-how and unanticipated additional recruitment and training costs. In addition, the loss of key BHC and NorthWestern personnel could diminish the anticipated benefits of the Merger. No assurance can be given that the combined company, following the Merger, will be able to retain or attract key management personnel and other key employees of BHC and NorthWestern to the same extent that BHC and NorthWestern have previously been able to retain or attract their own employees.
The business relationships of BHC and NorthWestern may be subject to disruption due to uncertainty associated with the Merger, which could have a material effect on the business, financial condition, cash flows and results of operations of BHC or NorthWestern pending the combined company and following the Merger.
Parties with which BHC or NorthWestern do business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with BHC or NorthWestern following the Merger. BHC's and NorthWestern’s business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture participants and other third parties with whom they do business may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than BHC or NorthWestern following the Merger. These disruptions could have a material and adverse effect on the business, financial condition, cash flows and results of operations, of BHC or NorthWestern, regardless of whether the Merger is completed, as well as a material and adverse effect on the combined company’s ability to realize the expected cost savings and other benefits of the Merger. The risk, and adverse effects, of any disruption could be exacerbated by a delay in completion of the Merger or termination of the Merger Agreement.
BHC is subject to risk of the Merger having an adverse impact on its credit rating, both while the Merger is pending and following completion of the Merger.
BHC cannot be assured that its credit ratings will not be lowered as a result of the Merger or for any other reason, including the failure to consummate the Merger. Any reduction in BHC's credit ratings, or the criteria used by rating agencies to determine such ratings, could adversely affect its ability to complete the Merger, its access to capital, its cost of capital and its other operating costs, and its ability to refinance or repay BHC's existing debt and complete new financings, which could have a material adverse effect on BHC's business, financial condition, results of operations or the trading price of its common stock or other securities.
The market prices of BHC common stock and other securities may be subject to fluctuation while the Merger is pending and after the Merger is completed.
The market price of BHC common stock and other securities may fluctuate significantly while the Merger is pending, or after it is completed, and any adverse developments related to the Merger or otherwise could result in holders of BHC common stock or other securities losing some or all of the value of their investment. In addition, if the stock market experiences significant price and volume fluctuations, such fluctuations could be exacerbated by the pendency of the Merger, which could adversely affect the market for, or liquidity of, BHC common stock or other securities, regardless of BHC's or the combined company’s actual operating performance.
Because the Merger Agreement contemplates that BHC will issue shares of BHC common stock to NorthWestern’s shareholders based upon a fixed exchange ratio, developments with respect to NorthWestern and its shares of common stock may affect BHC common stock irrespective of their relevance to standalone BHC and even though BHC may have no control over, or knowledge of, such developments. As a result, the market price of BHC common stock during the pendency of the Merger may not accurately reflect the value of BHC absent the Merger.
BHC is subject to contractual restrictions in the Merger Agreement that may hinder its operations while the Merger is pending. The corollary restrictions applicable to NorthWestern may not prevent NorthWestern from taking actions that are adverse to BHC or its shareholders.
Management's Discussion & Analysis (MD&A)
New heading “Pending Merger with NorthWestern”
New heading “One Big Beautiful Bill Act”
New heading “Business Segment Recent Developments”
Removed heading “Key Elements of our Business Strategy”
Removed heading “Inflation Reduction Act”
Largest changes
“In 2025, Wyoming Electric continued to grow its large-load demand from existing data center customers, Microsoft and Meta, under its LPCS Tariff. In July 2024, Wyoming Electric announced it would partner with Meta to provide power for its AI data center. Meta's new AI data center plans to transition from construction power to permanent service later in the first quarter of 2026. …”see in full comparison
“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. …”see in full comparison
“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 in full comparison
“Announced Partnership with Meta. On July 11, 2024, Wyoming Electric announced it will partner with Meta to provide power for its newest AI data center to be constructed in Cheyenne, Wyoming. Wyoming Electric plans to procure market energy under its LPCS Tariff with customized energy resources essential to Meta's operations and sustainability objectives.”see in full comparison
“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.”see in full comparison
Full comparison: every changed paragraph (130)
We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for 1.351.37 million customers and 800+ communities we serve. Our aspiration is to be the trusted energy partner across our growing eight-state footprint, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming. Our strategy is centered on four priorities: People & Culture—build a team that wins together, Operational Excellence—relentlessly deliver on our commitment to serve our customers, Transformation—betransform to a simple and connected company and Growth—grow to be a dominant long-term energy provider.
We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We consider ourselfourselves a domestic electric and natural gas utility company.
Key Elements of our Business Strategy
Explore opportunities as an energy solutions provider. A key strategic initiative is to grow our business through innovative energy solutions with new customers and partnerships. We see value creation by recruiting new customers and expanding existing partnerships with data centers and blockchain customers; exploring energy markets; and expanding our transmission capabilities. A few recent examples of our initiatives to grow our business as an energy solutions provider include:
Announced Partnership with Meta. On July 11, 2024, Wyoming Electric announced it will partner with Meta to provide power for its newest AI data center to be constructed in Cheyenne, Wyoming. Wyoming Electric plans to procure market energy under its LPCS Tariff with customized energy resources essential to Meta's operations and sustainability objectives.
Innovatively served LPCS load: In 2022, Wyoming Electric entered into two new PPAs with third parties to purchase up to 106 MWs of wind energy and up to 150 MWs of solar energy, upon construction of new renewable generation facilities (owned by third parties). The new wind generation facility was placed in service in December 2023 and the solar facility was placed in service in March 2024. The renewable energy from these PPAs is used to serve our expanding partnerships with LPCS customers.
Expanded BCIS Load: We have supported enabling legislation in Wyoming for the growing blockchain businesses while implementing our own BCIS Tariff to serve these customers. We currently have agreements with two customers to provide up to 130 MWs in Cheyenne, Wyoming under this Tariff. Energy is sourced through the electric energy market and delivered through our Electric Utilities’ infrastructure. Under these agreements, the customers are responsible for costs of service, and the load is interruptible to prioritize the needs of Wyoming Electric’s existing retail customers.
Modernize and operate utility infrastructure to provide customers with safe, reliable, cost-effective electric and natural gas service. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that spans nearly 1,600 miles. Our Electric Utilities own and operate 1,394 MWs of generation capacity and 9,196 miles of transmission and distribution lines and our Gas Utilities own and operate approximately 49,000 miles of natural gas transmission and distribution pipelines.
A key strategic focus is to modernize and harden our utility infrastructure to meet customers’ and communities’ varied energy needs, ensure the continued delivery of safe, reliable and cost-effective energy and reduce GHG emissions intensity. In addition, we invest in the expansion, capacity, and integrity of our systems to meet customer growth.
To meet our electric customers’ continued expectations of high levels of reliability, a key strength of the Company, our Electric Utilities utilize an integrity program to ensure the timely repair and replacement of aging infrastructure. Recent examples of our efforts within our integrity program include:
Continued Construction on Ready Wyoming Project: In November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. Construction of the 260-mile, multi-phase transmission expansion project commenced in late 2023 and the first phase was placed in service in December 2024. The project is expected to be completed in multiple segments through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission systems. The project will provide customers long-term price stability and greater flexibility as power markets develop in the Western States. This project is also expected to attract data center and blockchain customers, enable economic growth in Wyoming, expand access to renewable resources and facilitate additional renewable development across wind- and sun-rich resource areas.
Advanced South Dakota IRP: In June 2021, South Dakota Electric submitted an IRP to the SDPUC and WPSC. The IRP outlines a range of options over a 20-year planning horizon to meet long-term forecasted energy needs while strengthening reliability and resiliency of the grid. The analysis focused on the least-cost resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving the Company’s generation emissions reduction goals. South Dakota Electric's resource plan in the near-term planning period through 2026 includes the conversion of Neil Simpson II to dual fuel (natural gas and coal) in 2025, and addition of 99 MWs of utility-owned, dispatchable natural gas generation by the second half of 2026. Regarding the addition of 99 MWs of generation, South Dakota Electric expects to request a CPCN from the WPSC in the first quarter of 2025.
Published Wildfire Mitigation Plan: In 2024, we published our first formal WMP, which is an overview of our three-layered approach to manage wildfire risks driven by asset-based risk assessments that include asset programs, integrity programs and operational response. Additionally, we continue to engage stakeholders including community and local agencies regulators, legislative bodies and our industry peers to define, review and advance our wildfire management and mitigation plans, including our PSPS, which we expect to formalize by mid-2025.
As of December 31, 2024, we estimate our five-year capital investment to be approximately $4.7 billion, with most of that investment targeted toward upgrading existing utility infrastructure, supporting customer and community growth needs, and complying with safety requirements. Our actual 2024 and forecasted capital expenditures for the next five years from 2025 through 2029 are as follows:
Projects are being evaluated by our segments for timing, cost and other factors.
Efficiently plan, construct and operate power generation facilities to serve our Electric Utilities. We best serve customers and communities when generation is vertically integrated into our Electric Utilities and we retain control of the fuel source. This business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to supply cost-effective electricity to our customers. These generation assets can be rate-based or non-regulated assets within our Electric Utilities segment. However, we believe that generation assets that are rate-based provide the most effective long-term benefits to customers.
Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low power production costs result from a variety of factors including low fuel costs (operations located near energy hubs), efficiency in converting fuel into energy, and low per-unit operating and maintenance costs. In addition, we operate our plants with high levels of Availability as compared to industry benchmarks.
Rate-Based Generation: Rate-based generation assets offer several advantages for customers and shareholders, including:
When generating assets are included in the utility rate base and reviewed and approved by government authorities, customer rates are more stable and predictable, and typically less expensive in the long run; especially when compared to power otherwise purchased from the open market through wholesale contracts or PPAs that are periodically re-priced to reflect current and varying market conditions;
Regulators participate in a planning process where long-term investments are designed to match long-term energy demand;
The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit both customers and investors by lowering the cost of capital;
The value of controlling load to most effectively serve our customer demand; and Investors are provided a long-term and stable return on their investment.
Integrated Generation: Our Electric Utilities segment also includes a power generation business that owns non-regulated generating facilities that are contracted through long-term power purchase agreements with our electric utilities. Our power generation business has an experienced staff with significant expertise in planning, building and operating power plants. This team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the Company’s generation assets. Our power generation business competitively bids for energy and capacity through requests for proposals by our Electric Utilities for energy resources necessary to serve customers. This business can bid competitively due to construction expertise, fuel supply advantages and by co-locating new plants at our existing Electric Utilities’ energy complexes, reducing infrastructure and operating costs. All power plants within this business are contracted to our Electric Utilities under long-term contracts, located at our utility-generating complexes and physically integrated into our Electric Utilities’ operations.
Generation Fuel Supply: Our generating facilities are strategically located close to energy hubs that help reduce fuel supply costs. Our Colorado and Wyoming gas-fired generating facilities are located close to major natural gas energy hubs that provide trading liquidity and transparent pricing. Due to their location in the resource rich areas of Colorado and Wyoming, natural gas supply to fuel our gas-fired generation can be sourced at competitive prices. Our coal-fired power plants, all located at the Gillette Energy Complex in northeastern Wyoming, are supplied by our adjacent WRDC coal mine. WRDC provides approximately 3.7 million tons of low-sulfur coal directly to these power plants via a conveyor belt system, minimizing transportation costs. The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.19 per MMBtu for year ended December 31, 2024) when compared to alternatives. Nearly all the mine’s production is sold to these on-site generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus contracts with affiliates.
Reducing our carbon footprint by proactively integrating alternative and renewable energy into our utility energy supply while mitigating customer rate impacts. A critical component of our strategy involves sustainable operations and reducing emissions. We are committed to cleaner energy and a low carbon future, integrating the Energy Transition and more renewable energy into our overall strategy and decision making. We strongly believe that multiple energy sources, working together, will provide the solutions for a cleaner and resilient energy future.
Many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting GHG emission reduction targets. Federal legislation for renewable energy standards and GHG emission reductions has been considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions will likely drive the need for significant investment in our Electric Utilities and Gas Utilities segments. These mandates will also likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility, we are responsible for providing safe, reliable and cost-effective sources of energy to our customers. Accordingly, we employ a customer-focused strategy for complying with standards and regulations that balances our customers’ rate concerns with environmental considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate increases for our utility customers.
In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities by 40% by 2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are compared to a 2005 baseline. Electric Utility goals include Scope 1 emissions from electric utility generating units and Scope 3 emissions from purchased power for sales. Our Gas Utilities goal initially included only Scope 1 emissions from distribution system main and service lines. In August 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubled the previous target of a 50% reduction by 2035 and expanded the scope of the goal to all Scope 1 sources of methane emissions on our distribution system. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-party damage reduction, expanding the use of RNG and hydrogen, and utilizing carbon credit offsets.
During the second quarter of 2024, we published our 2023 Corporate Sustainability Report, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals. We reported a 27% reduction in GHG emissions from our natural gas distribution system since 2022 and are on track to achieve our goal of net zero emissions by 2035. Additionally, we have reduced our electric utility GHG emissions by nearly one-third since 2005 and are on track to achieve our goals to reduce electric emissions intensity by 40% by 2030 and 70% by 2040 compared to 2005.
Our goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This keeps our customers at the forefront of our decision-making, which is central to our values. More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other alternative energy sources. Recent efforts to support this interest include:
Advanced Colorado Clean Energy Plan: Colorado Electric's Clean Energy Plan supports its voluntary election to reduce carbon emissions 80% from 2005 levels by 2030. On April 17, 2024, Colorado Electric filed its 120-Day report with the CPUC, recommending the addition of renewable energy resources to advance its Clean Energy Plan. In December 2024, the CPUC approved a preferred portfolio of 100 MWs of utility-owned solar generation, 50 MWs of utility-owned battery storage and a 200 MWs solar PPA. Colorado Electric plans to file a CPCN for utility-owned resources by mid-2025. New resources are expected to be placed in service in 2027-2028.
Established Green Forward and Expanded RNG Interconnect Projects: In 2022 and 2023, we filed regulatory applications to launch Green Forward, a voluntary RNG and carbon offset program, to eligible residential and small business natural gas customers to offset up to 100% or more of the emissions from their natural gas usage. Our teams continue to evaluate attractive RNG investment opportunities across our agriculture-rich service territories and explore value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with 10 projects actively injecting RNG into our natural gas system.
Acquired RNG Production Facility: In January 2024, Black Hills Energy Renewable Resources acquired a RNG production facility at a landfill in Dubuque, Iowa. The facility currently injects RNG into the natural gas distribution system serving Dubuque, which is owned and operated by Iowa Gas. This acquisition represents our entry into the production of RNG as a nonregulated business while leveraging our expertise in owning and operating regulated natural gas pipeline systems, including RNG interconnections. The RNG produced from the landfill facility captures methane that would otherwise vent into the atmosphere. It is delivered under long-term contracts to a third party that purchases the RNG and its related environmental attributes, in conformity with the EPA's Renewable Fuel Standard Program.
Inflation Reduction Act
The IRA, enacted in August 2022, features spending and tax incentives on clean energy provisions. Most notably, the IRA includes provisions that extend and expand the production and investment tax credits for wind and solar; includes energy storage, EVs, RNG, and carbon capture and sequestration; and contains a tax credit transferability provision that allows us to transfer (e.g. sell) PTCs produced after December 31, 2022, to third parties. In June 2024, under this transferability provision, we entered into an agreement with a third party to sell $16.9 million of our 2023 generated PTCs. In January 2025, we entered into a similar agreement with a third party to sell $17.0 million of our 2024 generated PTCs. We expect to continue to explore the ability to efficiently monetize our tax credits through third party transferability agreements. See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Deliver a competitive total return to investors and maintain an investment grade credit rating. We are proud of our track record of annual dividend increases for shareholders. 2024 represented our 54th consecutive year of increasing dividends. In January 2025, our Board of Directors declared a quarterly dividend of $0.676 per share, equivalent to an annual dividend of $2.704 per share. We anticipate growing our dividend in line with our targeted dividend payout ratio of 55% to 65% of net income. A dependable and increasing dividend is an important component of our strategy for delivering long-term value for our shareholders.
We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent and earnings-accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity markets, while maintaining our investment-grade issuer credit rating.
Pending Merger with NorthWestern
On August 18, 2025, we entered into the Merger Agreement with NorthWestern and Merger Sub. See Note 17 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further discussion about the pending Merger.
One Big Beautiful Bill Act
See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for discussion surrounding the OBBBA.
Trade Tariffs
Trade tariffs have been enacted over the last several months through presidential executive orders affecting products exported by several U.S. trading partners, and retaliatory tariffs have been imposed by some of these trading partners. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect with the possibility of additional tariffs being imposed. We are currently unable to predict the impact that recently imposed and possible future tariffs may have on our business. Trade tariffs have not had a material impact on our operations of financial performance to date. We are closely monitoring the impacts of trade tariffs and the potential effect they may have on our financial positions, results of operations, or cash flows.
Business Segment Recent Developments
In December 2025, the Ready Wyoming project was fully completed and placed in service and now interconnects South Dakota Electric’s and Wyoming Electric’s transmission systems. Ready Wyoming was originally announced in November 2021 and construction commenced in late 2023. The project provides customers long-term price stability and greater flexibility as power markets develop in the western United States. This project is also expected to enable economic growth in Wyoming, expand access to renewable resources and facilitate additional renewable development across wind- and sun-rich resource areas.
In 2025, Wyoming Electric continued to grow its large-load demand from existing data center customers, Microsoft and Meta, under its LPCS Tariff. In July 2024, Wyoming Electric announced it would partner with Meta to provide power for its AI data center. Meta's new AI data center plans to transition from construction power to permanent service later in the first quarter of 2026. We are also actively negotiating with prospective new data center customers that would further grow our load pipeline under Wyoming Electric's LPCS Tariff and also through strategic investments in new transmission and generation.
In 2025, Wyoming Electric set multiple all-time and winter records for System Peak Demand. The most recent all-time peak of 379 MW was set on June 20, 2025 and the most recent winter peak of 375 MW was set on November 30, 2025. Prior to 2025, the previous all-time and winter peak was 314 MW set on January 11, 2024.
On March 28, 2025, South Dakota Electric filed a CPCN with the WPSC for the Lange II project, which was approved in June 2025. The new facility began construction in the third quarter of 2025 and is anticipated to be in service in the fourth quarter of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements.
In 2025, Colorado Electric received CPUC approval for the addition of 250 MW of new renewable generation resources in support of its Clean Energy Plan, which included a 50-MW utility-owned battery storage project and a 200-MW solar PPA. On November 3, the CPUC approved the CPCN for the 50-MW battery storage project. During the first quarter of 2026, Colorado Electric expects to execute the 200-MW solar PPA.
In 2024, we published our first formal WMP, which is an overview of our three-layered approach to manage wildfire risks driven by asset-based risk assessments that include asset programs, integrity programs and operational response. On June 30, 2025, we established our Emergency PSPS program across all three of our electric utilities to promote customer safety and mitigate wildfire risk. In establishing the Emergency PSPS program, we engaged with wildfire experts and key stakeholders including customers, community and local agencies, regulators and community leaders.
On March 6, 2025, the state of Wyoming enacted comprehensive wildfire liability mitigation legislation (HB0192), effective July 1, 2025. The legislation provides material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. In November 2025, we filed our WMP with the WPSC and anticipate approval in March 2026.
See Key Elements of our Business Strategy section above for discussion of recent developments related to our partnership with Meta, construction progress on our Ready Wyoming project, Colorado Electric's Clean Energy Plan, South Dakota Electric's IRP and the addition of 99 MWs of new generation, and publishing of our first formal WMP and plans to formalize our PSPS.
In 2024, Wygen I and Pueblo Airport Generation #4-5 experienced unplanned generation outages that had a $8.3 million negative impact to Operating income. We are currently assessing insurance recovery opportunities.
On January 20, 2025, Wyoming Electric set a new all-time and winter peak load of 318 MWs, surpassing the previous all-time and winter peak load of 314 MWs set on January 11, 2024. Prior to 2024, the previous winter peak was 301 megawatts in December 2023 and the all-time peak was 312 megawatts in July 2023.
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate review activity for Arkansas Gas, Colorado Gas, Iowa Gas, Kansas GasGas, and WyomingNebraska Gas.
See Key Elements of our Business Strategy section above for discussion of recent developments related to BHERR's purchase of a RNG production facility in Iowa.
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding our recentcorporate Revolving Credit Facility, October 2, 2025 debt offering and ATM program activity and our May 16, 2024, debt offering.activity.
On May 31, 2024, we amended and restated our corporate Revolving Credit Facility. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Electric Utilities’ operating income decreased $15.8$10.5 million primarily due to unfavorablehigher impactsoperating fromexpenses, unplanned generation outages in 2024,outages, lower off-systemtransmission excessservices energy sales, higher insurance expense,revenues and one-time benefits in 2023 from a gain on the sale of Northern Iowa Windpower assets, a gain on sale of land to support data center growth, and a recovery from our business interruption insurance. These unfavorable variances wereweather partially offset by new rates and rider recovery and retail customer growth and usage.;
Gas Utilities’ operating income increased $42.5$49.5 million primarily due to new rates and rider recovery driven by the ColoradoArkansas Gas, Iowa Gas, RMNGKansas Gas, and WyomingNebraska Gas rate reviews, retail customer growthreviews and usage, favorable mark-to-market on commodity contracts, and lower employee-related expensesweather partially offset by $15.9 million of unfavorable weatherretail customer usage and higher depreciationoperating driven by capital expendituresexpenses;
Corporate and otherOther operating (loss) decreasedincreased $3.7by $4.6 million primarily due to lowercosts unallocatedrelated operatingto expensesthe pending Merger partially offset by a one-time favorable true-up from the consolidation of our Captive;
What changed in the latest 10-Q
Risk Factors
There have been no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2025 Annual Report on Form 10-K.
No wording changes found in this section.
Full comparison: every changed paragraph (0)
Management's Discussion & Analysis (MD&A)
Largest changes
“On April 22, 2026, Wyoming Electric entered into a generation reservation agreement with a prospective new customer seeking to construct a 1.8 GW data center under Wyoming Electric's LPCS Tariff. In July 2026, the parties amended this generation reservation agreement to increase the total refundable advances and extended the maturity date to August 31, 2026. This agreement is a bridge agreement to support long lead-time items while Wyoming Electric continues to negotiate definitive agreements with the prospective customer. …”see in full comparison
“On June 30, 2026, Wyoming Electric submitted an IRP to the WPSC. The IRP, which is based on 20-year planning period including a near-term planning period through 2033, identified a near-term capacity shortfall of 95 MW beginning in 2027. Based on its forecasts and analysis, Wyoming Electric recommends the addition of natural gas-fired generation and battery storage assets to meet the identified resource need. Wyoming Electric's IRP does not address any LPCS Tariff capacity needs, which are handled separately under customer-specific agreements.”see in full comparison
“On June 19, 2026, Wyoming Electric filed a request with the WPSC to establish an LCTCAM tariff. The LCTCAM tariff provides a framework to directly recover transmission investment costs from LPCS customers who are served by, and benefit from, the transmission facility. The proposed mechanism is designed to ensure that customers not directly served by those facilities are protected from bearing those costs. The filing requests WPSC approval of the LCTCAM tariff by September 1, 2026, with an effective date of January 1, 2027.”see in full comparison
“On April 22, 2026, Wyoming Electric entered into a generation reservation agreement with a prospective new customer seeking to construct a 1.8 GW data center under Wyoming Electric's LPCS Tariff. See Note 3 of the Condensed Notes to Consolidated Financial Statements for additional information.”see in full comparison
“During the second quarter of 2026, we published our 2025 Corporate Sustainability Report, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals. We reported a 43% reduction in electric utility emissions intensity compared to 2005, driven by the addition of renewable and natural gas resources and the retirement of aging power plants. …”see in full comparison
As discussed in footnote (see in full comparisonba) in the Quantities Generated and Purchased by Fuel Type table above, the increase in Wyoming Electric's purchases for the three and six months ended June 30, 2026, compared to the same periods in 2025, is primarily driven by increased demand from large-load customers under the LPCS and BCISTariff customers.Tariffs.
Full comparison: every changed paragraph (56)
See Note 2 of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for South Dakota Electric and Colorado Electric.
On April 22, 2026, Wyoming Electric entered into a generation reservation agreement with a prospective new customer seeking to construct a 1.8 GW data center under Wyoming Electric's LPCS Tariff. See Note 3 of the Condensed Notes to Consolidated Financial Statements for additional information.
On March 12, 2026, the state of South Dakota enacted comprehensive wildfire liability mitigation legislation (SB36), effective July 1, 2026. The legislation provides material liability protections for a utility that complies with its published wildfire mitigation plan. South Dakota Electric plans to file its WMP with the SDPUC in the second half of 2026. In 2025, the state of Wyoming enacted similar legislation. In November 2025, Wyoming Electric filed its WMP with the WPSC and anticipates approval by mid-2026.
During the firstsecond quarter of 2026, South Dakota Electric continued with construction of its Lange II project which is anticipated to be in service in the fourth quarter of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements. On August 4, 2026, South Dakota Electric filed an application with the SDPUC for a PIRP rider which requests recovery of $320 million of Lange II project costs outside of a general rate review. If approved by the SDPUC, the rider is anticipated to be effective on December 1, 2026.
On March 12, 2026, the state of South Dakota enacted comprehensive wildfire liability mitigation legislation (Senate Bill 36), effective July 1, 2026. The legislation provides material liability protections for a utility that complies with its published wildfire mitigation plan. On July 2, 2026, South Dakota Electric filed its WMP with the SDPUC. Under Senate Bill 36, a utility's WMP is valid and current if it is on file and all annual reports are timely filed with the SDPUC. In 2025, the state of Wyoming enacted similar legislation. In November 2025, Wyoming Electric filed its WMP with the WPSC, which was approved on July 9, 2026.
On April 22, 2026, Wyoming Electric entered into a generation reservation agreement with a prospective new customer seeking to construct a 1.8 GW data center under Wyoming Electric's LPCS Tariff. In July 2026, the parties amended this generation reservation agreement to increase the total refundable advances and extended the maturity date to August 31, 2026. This agreement is a bridge agreement to support long lead-time items while Wyoming Electric continues to negotiate definitive agreements with the prospective customer. See Note 5 of the Condensed Notes to Consolidated Financial Statements for additional information.
On June 30, 2026, Wyoming Electric submitted an IRP to the WPSC. The IRP, which is based on 20-year planning period including a near-term planning period through 2033, identified a near-term capacity shortfall of 95 MW beginning in 2027. Based on its forecasts and analysis, Wyoming Electric recommends the addition of natural gas-fired generation and battery storage assets to meet the identified resource need. Wyoming Electric's IRP does not address any LPCS Tariff capacity needs, which are handled separately under customer-specific agreements.
On June 19, 2026, Wyoming Electric filed a request with the WPSC to establish an LCTCAM tariff. The LCTCAM tariff provides a framework to directly recover transmission investment costs from LPCS customers who are served by, and benefit from, the transmission facility. The proposed mechanism is designed to ensure that customers not directly served by those facilities are protected from bearing those costs. The filing requests WPSC approval of the LCTCAM tariff by September 1, 2026, with an effective date of January 1, 2027.
In 2026, Wyoming Electric has set multiple all-time records for System Peak Demand. The most recent all-time peak of 439 MW was set on July 20, 2026. Prior to 2026, the previous all-time peak was 379 MW set on June 20, 2025.
In January 2026, Wyoming Electric set a new all-time peak load of 393 MW, surpassing the previous peak of 379 MW set on June 20, 2025.
During the second quarter of 2026, we published our 2025 Corporate Sustainability Report, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals. We reported a 43% reduction in electric utility emissions intensity compared to 2005, driven by the addition of renewable and natural gas resources and the retirement of aging power plants. We also reduced natural gas utility emissions by 25% since 2022, including a 53% reduction from transfer stations, reflecting progress toward our net-zero by 2035 goal through expanded leak detection and repair efforts.
Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended MarchJune 31,30, 2026, and 2025, and our financial condition as of MarchJune 31,30, 2026, and December 31, 2025, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.
Electric Utilities’Utilities' operating income increased $5.6$12.1 million primarily due to new rates and rider recovery driven by the Colorado Electric rate review and Wyoming Electric's recently completed Ready Wyoming project partially offset by unfavorable weather and lower residential and commercial customer usage;
Gas Utilities’Utilities' operating income decreasedincreased $5.0$7.6 million primarily due to unfavorable weather partially offset by new rates and rider recovery driven by the KansasNebraska Gas and NebraskaKansas Gas rate reviews andpartially loweroffset by higher operating expenses; and Corporate and Other operating loss increased $3.7 million primarily due to costs related to the pending merger with NorthWestern.
Corporate and Other operating loss increased $5.2 million primarily due to costs related to the pending merger with NorthWestern; and Net interest expense increased $2.7 million primarily due to higher rates on increased debt.
Electric Utilities’ operating income increased $16.9 million primarily due to new rates and rider recovery driven by the Colorado Electric rate review and Wyoming Electric's recently completed Ready Wyoming project partially offset by lower residential and commercial customer usage and unfavorable weather;
Gas Utilities’ operating income increased $1.0 million primarily due to new rates and rider recovery driven by the Nebraska Gas, Kansas Gas, and Arkansas Gas rate reviews partially offset by unfavorable weather and higher operating expenses;
Corporate and Other operating loss increased $6.3 million primarily due to costs related to the pending merger with NorthWestern; and Net interest expense increased $3.2 million primarily due to higher rates on increased debt partially offset by higher AFUDC debt.
Operations and maintenance expenses which are deemed to be directly attributable to revenue-producing activities include plant operations and maintenance expenses at our electric generation facilities, operations and maintenance expenses at our WRDC coal mine, and electric and gas transmission and distribution expenses. These amounts are included in the table above to calculate gross margin in accordance with GAAP. These amounts excluded operations and maintenance expenses not directly attributable to revenue-producing activities of $25.9$23.9 millionmillion, $25.4 million, $50.7 million, and $26.9$52.3 million for the three and six months ended MarchJune 31,30, 2026, and 2025, respectively, for the Electric Utilities and $41.2$38.9 millionmillion, $39.4 million, $81.6 million, and $41.7$81.2 million for the three and six months ended MarchJune 31,30, 2026, and 2025, respectively, for the Gas Utilities.
Operations and maintenance expense decreased primarily due to $2.4$3.2 million of lower expenses driven by prior year unplanned generation outages and $1.2 million of lower outside services expenses.
Electric Utility margin increased as a result of the following:
Operations and maintenance expense decreased primarily due to $4.5 million of lower outside services expenses and $3.2 million of lower expenses driven by prior year unplanned generation outages.
Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.
Taxes other than income taxes was comparable to the same period in the prior year.
The increase in industrial quantities sold for the three and six months ended MarchJune 31,30, 2026, compared to the same periodperiods in 2025, was primarily driven by Wyoming Electric's large-load customers under the LPSC and BCIS Tariff customers.Tariffs.
The decrease in coal generation for the three months ended March 31, 2026, compared to the same period in 2025, is primarily due to generation outages at Wygen III (returned to service in mid-March 2026).
The increase in total purchases for the threesix months ended MarchJune 31,30, 2026, compared to the same period in 2025, was primarily driven by generation outages and increased demand from Wyoming Electric's BCIS Tarifflarge-load customers under the LPCS and generationBCIS outages at Wygen III as discussed in (a) above.Tariffs.
The shift in South Dakota Electric's generated and purchased GWh for the three months ended March 31, 2026, compared to the same period in 2025, is primarily driven by generation outages at Wygen III (returned to service in mid-March 2026).
As discussed in footnote (ba) in the Quantities Generated and Purchased by Fuel Type table above, the increase in Wyoming Electric's purchases for the three and six months ended June 30, 2026, compared to the same periods in 2025, is primarily driven by increased demand from large-load customers under the LPCS and BCIS Tariff customers.Tariffs.
Gas Utility margin decreasedincreased as a result of the following:
Operations and maintenance expense decreasedincreased primarily due to $4.4higher millionoutside ofservices expenses and office and facilities expenses partially offset by lower employee costs.related expenses.
Gas Utility margin increased as a result of the following:
Operations and maintenance expense decreased primarily due to $5.1 million of lower employee related expenses partially offset by $3.2 million of higher outside services expenses.
Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.
Taxes other than income taxes was comparable to the same period in the prior year.
Operating loss increased primarily due to $8.6 million of costs related to the pending merger with NorthWestern.
Interest expense, net, wasincreased comparablecompared to the same period in the prior year as higher interest expense primarily driven by higher debt balances was mostly offset by higher interest income driven by higher cash and cash equivalents balances.
Income tax (expense) was comparable to the same period in the prior year. For the three months ended MarchJune 31,30, 2026, the effective tax rate was 11.7%,11.4%, which was comparable to 11.7%13.3% for the same period in 2025.
Interest expense, net, increased compared to the same period in the prior year due to higher interest expense primarily driven by higher debt balances partially offset by higher AFUDC debt driven by construction work-in-progress balances.
Other income, net, was comparable to the same period in the prior year.
Income tax (expense) was comparable to the same period in the prior year. For the six months ended June 30, 2026, the effective tax rate was 11.6%, which was comparable to 12.0% for the same period in 2025.
We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, and the issuance of common stock under our ATM or in a secondary offering. Our current shelf registration statement expires in the second quarter of 2026offering and werefundable expectadvances tofrom filecustomers. a new shelf registration statement to replace it. Additionally, weWe plan to re-finance our $400 million, 3.15%, senior unsecured notes due January 2027, at or before the maturity date.
Wyoming Electric entered into a generation reservation agreement with a prospective data center customer who will provide refundable advances totaling $377 million under the agreement maturing August 31, 2026. In the absence of an extension of this agreement, we will evaluate a range of financing alternatives to address repayment of the refundable advances, including available capacity under our Revolving Credit Facility, potential short-term loan arrangements, and issuances under our ATM.
The following tables summarize our cash flows for the threesix months ended MarchJune 31,30, 2026:
Total earnings (net income plus non-cash adjustments) were comparable$11.1 tomillion higher than the same period in the prior year,year primarily as a result of increased Electric and Gas Utility margins due to new rates and rider recovery werepartially offset by unfavorablehigher weatherfinancing and lower retail customer usage.costs.
Net outflowsinflows from changes in certain operating assets and liabilities were $48.2$42.7 million higher,lower, primarily attributable to:
o
o
Cash outflows increased by $63.3$52.1 million as a result of changes in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, payment of a legal liability from settlement in Colorado and changes in other working capital requirements; and o Cash inflows decreased by $47.2$39.9 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of gas and fuel cost adjustments driven by fluctuations in commodity prices, and lower recoveries of our Winter Storm Uri regulatory asset as recovery is now complete in mostnearly of ourall jurisdictions.
Cash outflows from other operating activities increased by $2.5$13.5 million primarily driven by settlement of contractor retainage balances from Wyoming Electric's recently completed Ready Wyoming project and higher costs from cloud computing licensing costs.arrangements.
Cash outflows from capital expenditures (which are net of non-refundable CIACs) increased $114.5$113.7 million primarily driven by the Lange II project and Wyoming Electric’s milestone payments for long lead-time generation equipment. See Note 3 of the Condensed Notes to Consolidated Financial Statements for additional information.
Net cash outflows decreasedincreased $26.1$199.9 million primarily as a result of net borrowing activity under our CP Program partially offset by the repayment of $300 million, 3.95% senior unsecured notes on their January 15, 2026 maturity date.date partially offset by net borrowing activity under our CP Program.
Distributions to non-controlling interests wereincreased comparabledue to thehigher samenet periodincome infrom theBlack Hills Colorado IPP primarily driven by prior year.year unplanned generation outages.
Cash inflows increased due to $285.0 million of refundable advances from a prospective customer for long lead-time generation equipment. See Note 5 of the Condensed Notes to Consolidated Financial Statements for additional information.
Dividends paid on our common stock totaled $53.1$106.6 million for the threesix months ended MarchJune 31,30, 2026, or $0.703 per share. On AprilJuly 28, 2026, our board of directors declared a quarterly dividend of $0.703 per share payable JuneSeptember 1, 2026, equivalent to an annual dividend of $2.812 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility, and our future business prospects.
A summary of our critical accounting estimates is included in our 2025 Annual Report on Form 10-K. There were no material changes made as of MarchJune 31,30, 2026.
BKH insider buying and selling (Form 4)
Since 2026-04-11, insiders reported open-market purchases in 0 Form 4 filings and open-market sales in 1 filing (1 insider, 1 trade date, 4,109 shares, about $305.0K). Net open-market shares: -4,109 (purchases minus sales); net value about -$305.0K.Totals add up every open-market (code P and S) line in those filings, using the prices reported in the filings. Awards, option exercises, tax withholding and gifts are listed below but not counted.
| Trade date | Insider | Transaction | Shares | Price | Value |
|---|---|---|---|---|---|
| 2026-05-27 | Otto Robert P |
Open-market sale | 4,109 | $74.22 | $305.0K |
| 2026-05-01 | Waleski Anne G |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Taylor Teresa |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Prochazka Scott M |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Otto Robert P |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Mills Steven Richard |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Mcallister Kathleen S |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Jensen Tony A |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Granger Barry M |
Grant/award | 1,921 | — | — |
| 2026-05-01 | Beard Robert F. |
Grant/award | 1,921 | — | — |
Well-known investors holding BKH (13F)
| Investor | Quarter | Shares | Reported value | % of their 13F | Change vs prior quarter |
|---|---|---|---|---|---|
| AQR Capital Management (Cliff Asness) | 2026-06-30 | 2,232,003 | $166.1M | 0.06% | Added 40% |
| Point72 Asset Management (Steve Cohen) | 2026-06-30 | 2,161,197 | $160.8M | 0.25% | Added 11% |
| Two Sigma Investments | 2026-06-30 | 1,663,178 | $123.7M | 0.09% | Reduced 25% |
| Citadel Advisors (Ken Griffin) | 2026-06-30 | 1,259,693 | $93.7M | 0.05% | Added 39% |
| D. E. Shaw & Co. | 2026-06-30 | 335,535 | $25.0M | 0.02% | Reduced 3% |
| Renaissance Technologies | 2026-06-30 | 247,800 | $18.4M | 0.03% | Added 213% |
| First Eagle Investment Management | 2026-06-30 | 177,990 | $13.2M | 0.02% | Added 38% |
| Millennium Management (Israel Englander) | 2026-06-30 | 59,809 | $4.4M | 0.0% | Added 64% |