HALLADOR ENERGY CO (HNRG) Business

ITEM 1. BUSINESS.

Hallador Energy Company (“Hallador” or the “Company”) is a vertically integrated, independent power producer (“IPP”) and fuel company with operations primarily in Indiana. The Company operates across multiple stages of the energy value chain, from accredited capacity and energy to coal. The Company’s electric operations are located within the Midcontinent Independent System Operator’s ("MISO") footprint. Our operations comprise Hallador Power Company, LLC (“Hallador Power”) that provides accredited capacity and energy to utilities and other energy market participants through its MISO interconnection, and Sunrise Coal, LLC (“Sunrise”) that mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States.

Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Company also holds 50% interests in Sunrise Energy, LLC and Oaktown Gas, LLC, which are accounted for using the equity method. Through its operating subsidiaries, the Company delivers three main products to its customers, as described below.

Accredited Capacity. Hallador Power, the Company’s wholly-owned electric subsidiary, owns and operates the Merom Power Plant (“Merom”), a 1,080 MW coal-fired power generating station, consisting of two steam turbine generators. Unit 1 entered commercial operations in 1982 and Unit 2 in 1983. The units are dispatched through its MISO interconnection. In order to purchase energy through the MISO interconnection, an end user must supply or purchase accredited capacity for an equivalent load. As accredited capacity is primarily available in meaningful quantities from dispatchable sources of energy, such as natural gas and coal-fired power plants, Hallador Power sells accredited capacity to utilities and other energy market participants within the MISO system mainly through power purchase agreements (“PPAs”) and other bilateral transactions.

Energy. In addition to accredited capacity, Hallador Power sells wholesale energy to utilities, generation and transmission cooperatives, and other energy market participants within the MISO system through PPAs and other bilateral transactions and sells on a spot basis in the day-ahead and real-time MISO markets.

Fuel. Sunrise, the Company’s wholly-owned mining subsidiary, mines coal from reserves found in the Illinois Basin (“ILB”). Coal mined by Sunrise is used as a primary fuel source for generating electricity at various power plants in the Midwest and Southeast United States. In addition, Sunrise has a developed infrastructure for the transport of coal, which is typically sold free on board from the shipping point, including rail networks and truck loading systems, facilitating the efficient movement of the resource from the mine to its customers. Sunrise’s Oaktown Mining Complex is about twenty miles from Merom, which is located in Sullivan County, Indiana, enabling Merom and Sunrise to take advantage of low-cost fuel on a delivered basis.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our business.

Regulation and Laws

Our electric power generation and coal mining businesses are subject to regulation by federal and state agencies and local authorities on matters such as:

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Federal agencies that exercise regulatory authority over our businesses, include but are not limited to the Federal Energy Regulatory Commission (“FERC”), the Occupational Safety and Health Administration's (“OSHA”), and the Mine Safety and Health Administration (“MSHA”). The following discussion provides an overview of certain key federal regulatory matters applicable to our business.

FERC. Hallador Power is defined as a public utility under the Federal Power Act and is subject to the FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. The FERC has the authority to grant or deny market-based rate authority for wholesale sales of energy, capacity, and ancillary services to ensure that such sales are just and reasonable and not unduly discriminatory and to suspend market-based rate authority and set cost-based rates if it finds that its previous grant of market-based rate authority is no longer just and reasonable. Other matters subject to the FERC’s jurisdiction include, but are not limited to: review of certain public utility dispositions of jurisdictional facilities, mergers, acquisitions of other public utility securities, or acquisitions of existing generation facilities; review of certain holding company acquisitions of securities of, or mergers with, a public utility or other holding company; third-party financings; affiliate transactions; intercompany financings and cash management arrangements; and certain internal corporate reorganizations.

RTOs and ISOs. Regional transmission organizations (“RTOs”) and independent system operators (“ISOs”) are the FERC-regulated entities that exist in several regions to provide transmission services across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE, and SPP as RTOs and CAISO and NYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through the Intercontinental Exchange and the New York Mercantile Exchange, and managing transmission charges across multiple systems and states. Merom participates in the wholesale electricity market administered by MISO.

OSHA/MSHA. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require us to maintain information about hazardous materials used or produced in our operations, and this information is required to be provided to employees, state and local government authorities, and citizens. The Federal Mine Safety and Health Act of 1977 (“FMSHA”) and regulations adopted thereunder, impose extensive and detailed safety and health standards on numerous aspects of our coal mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations and implements new regulations from time to time. The states where we operate also have state programs for mine safety and health regulation and enforcement. Some of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to our customers. Although we have not quantified the full impact, implementing and complying with these new federal and state safety laws and regulations have had, and are expected to continue to have, a significant effect on our operating costs and an adverse impact on our results of operations and financial position. In addition, because MSHA regulations permit citations to be issued without regard to fault, it is not reasonable to expect any coal mining company to be free of citations, and we are issued citations from MSHA inspectors from time to time.

Other Regulation. In addition to federal regulation, our operations are subject to various state and local laws and regulations. These include oversight of siting, permitting, and environmental compliance for our facilities. Our operations are also subject to compliance with reliability standards developed and enforced by the North American Electric Reliability Corporation (“NERC”) and its regional entities. Compliance with these standards is critical to maintaining the reliability of the bulk electric system and avoiding penalties for violations. See “—Environmental Regulation” below for additional information on environmental regulation of our business.

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Environmental Regulation. Our business is subject to extensive federal, state, and local environmental laws, regulations, and requirements, including but not limited to those related to air emissions, water discharges, hazardous substances, and solid waste management. These requirements have become more stringent over time and impose, among other things: (i) permitting requirements for regulated activities; (ii) costs to limit or prevent pollution or other contamination; and (iii) substantial liabilities and remedial obligations for pollution or contamination. Accordingly, in the ordinary course of our business, we may: (1) incur significant costs to comply with environmental requirements; (2) be required to modify, curtail, replace, or cease certain operations for environmental reasons; (3) be required to perform environmental remediation work; or (4) become involved in other environmental matters, including government enforcement actions and citizen’s suit litigation. In addition, environmental requirements are rapidly evolving, and we may become subject to new or revised environmental laws, regulations, or requirements. Executive orders directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including existing regulations, that are unduly burdensome on the identification, development, or use of domestic energy resources add to the uncertainty. In addition, on February 12, 2026, the U.S. Environmental Protection Agency (“EPA”) rescinded the agency’s prior finding in 2009 that GHG from motor vehicles threaten public health and welfare (the “Endangerment Finding”). While the EPA’s repeal of the Endangerment Finding invalidates GHG emission standards for motor vehicles, it could impact GHG regulations applied to electric generation facilities that were supported by the Endangerment Finding. Legal challenges to environmental regulations, rules, and requirements, including leading to the rescission of the Endangerment Finding, add to the uncertainty of estimating future compliance and remedial costs. Future implementation and enforcement of these rules remain uncertain at this time.

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict liability, investigatory and remedial obligations, capital expenditures, interruptions, changes in operations, and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. Changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly obligations could increase our costs and adversely affect our performance. For more information, please see “Air Emissions”, “GHG Emissions” and “Water Discharge” in this section, below, and the risk factors described in “Item 1A. Risk Factors” below.

We are committed to conducting our electric power generating and mining operations in compliance with applicable federal, state, and local laws and regulations. When we identify a failure to comply, we attempt to remediate any such failure immediately. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant and have substantially increased the cost of electric power generation and the cost of coal mining for domestic coal producers.

We have accrued for the present value of the estimated cost of asset retirement obligations, power plant closing, and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations, power plant closing and mine closing costs are based upon permit requirements and the estimated costs and timing of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.

Electric Power Generation Permits and Approvals

Numerous governmental permits or approvals are required for electric power generation operations, including coal-fired power plants such as Merom. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health, and safety matters associated with electric power generation. These matters include air emissions, including GHG emissions, the management and disposal of coal combustion residuals and other wastes or materials, and wastewater effluent treatment and discharge, among others. Meeting all requirements imposed to address these matters may be costly and may delay or prevent commencement or continuation of power generation operations.

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The permitting process for electric power generation operations can extend over many years as a result of necessary permit renewals and those permitting decisions can be subject to administrative and judicial challenge, including by the public. We cannot assure you that we will not experience difficulty or delays in obtaining electric power generation permits in the future or that a current permit will not be revoked.

Under some circumstances, substantial fines and penalties, including revocation of electric power generating permits, may be imposed under applicable laws and regulations. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Like other power generating companies, we have been cited for violations in the ordinary course of our business, but we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health, and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use, and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and may delay or prevent commencement or continuation of mining operations.

The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. Like other coal companies, we have been cited for violations in the ordinary course of our business, but we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Surface Mining Control and Reclamation Act

The Federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes establish operational, reclamation, and closure standards for all aspects of surface mining as well as many aspects of underground mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.

SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence. Currently, 100% of our production involves underground room and pillar mining. We do not engage in either mountain top removal or long-wall mining. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a reclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The current reclamation fee for surface-mined and underground-mined coal is $0.224 per ton and $0.096 per ton, respectively, through September 30, 2034. We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water

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discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis.

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the third-party violator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and having any permits revoked that were issued after the time of the violations or after the time civil penalties or reclamation fees became due. We are not aware of any currently pending or asserted claims against us relating to the “ownership” or “control” theories discussed above. However, we cannot assure you that such claims will not be asserted in the future.

Bonding Requirements

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, for closure and post-closure landfill care, and to satisfy other miscellaneous obligations. We are also required to post bonds to secure performance under our coal combustion residuals landfill permit. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for our competitors and us to secure new surety bonds without posting collateral, and in some cases, it is unclear what level of collateral will be required. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain or inability to acquire surety bonds that are required by federal and state laws would have a material adverse effect on our ability to produce coal and conduct electric power generating operations, which could affect our profitability and cash flow.

Workers’ Compensation and Black Lung

We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers’ compensation laws also compensate survivors of workers who suffer employment-related deaths. We generally self-insure this potential expense using our actuarial estimates of the cost of present and future claims.

In addition, coal mining companies are subject to federal legislation and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal workers’ pneumoconiosis or black lung. The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 (“BLBA”), requires businesses that conduct coal mining operations to make payments of black lung benefits to current and former coal miners with black lung disease, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical expenses where no responsible coal mine operator has been identified for claims. As of October 1, 2022, the trust fund was funded by an excise tax on production of up to $1.10 per ton of coal from underground mines and up to $0.55 per ton of coal from surface mines, neither amount to exceed 4.4% of the gross sales price.

The BLBA relaxed the stringent award criteria established under previous regulations and thus potentially allows new federal claims to be awarded and previously denied claimants to re-file under the revised criteria. The BLBA may also increase black lung-related medical costs by broadening the scope of conditions for which medical costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.

In addition, the Patient Protection and Affordable Care Act enacted in 2010 includes significant changes to the federal black lung program retroactive to 2005, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program. We also provide for black lung claims through self-insurance programs. Our actuarial calculations are based on numerous assumptions, including disability incidence, medical costs, mortality, death benefits, dependents, and discount rates.

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Air Emissions

The Clean Air Act (“CAA”) and similar state and local laws and regulations regulate emissions into the air and affect both our coal mining and electric power generation operations. The CAA directly impacts our coal mining and processing and electric power generation operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, obtain emissions allowances, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities.

Under the CAA, as well as comparable state and local laws and regulation, Merom is subject to extensive emission control, emission allowance, emission monitoring, and air reporting obligations. Compliance with these requirements impacts the operation of Merom as well as our operating costs. There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. The imposition of requirements to install additional emissions control technology and any additional measures required under applicable federal and state laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal. In addition, regulation of the electric power industry regarding the environmental impact of power generation activities has adversely affected demand for coal, which could have a significant impact on the use of coal by the customers that purchase our coal and could have a material adverse effect on our coal mining operations and our business, financial condition, and results of operations. New or modified obligations could significantly impact how we produce electricity and could impede strategic planning. Key air matters currently affecting our business include, but are not limited to, nitrogen oxides requirements, as well as the revised 2024 Greenhouse Gas Rule, which could significantly impact certain facilities, including Merom. These rules are being legally challenged and are being reconsidered by the EPA, resulting in uncertainty in estimating compliance and remediation costs that we may incur.

In addition to the GHG issues discussed below, the air emissions compliance programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:

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GHG Emissions

Combustion of fossil fuels, such as the coal we produce and the coal that is used at Merom, results in the emission of GHGs, such as carbon dioxide and methane. Combustion of fuel for mining equipment used in coal production also emits GHGs.

In May 2024, the EPA published a final rule that, among other things, established emissions guidelines for GHG emissions for existing coal-fired and new or substantially modified natural gas-fired power plants. The rule divides coal-fired power plants into three categories: those that will cease operation by 2032 are exempt from the rule; those operating between 2032 and 2039 will be required to achieve emissions reductions equivalent to co-firing 40 percent by volume natural gas; and those intending to operate after 2039 will be required to achieve emissions reductions equivalent to 90 percent capture of CO2 through carbon capture and sequestration (“CCS”). The rule has been challenged in court and it is not clear at present how the EPA’s recission of the Endangerment Finding will impact the rule. Depending on the final outcome of legal challenges, implementation of modifications to Merom necessary to meet the emissions reductions requirements of the rule could potentially have a material adverse effect on our business, financial condition, and results of operations.

Future, additional regulation of GHG emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA. The Parties of the UN Framework Convention on Climate Change have met on several occasions, including at the 28th Conference to the Parties on the UN Framework Convention on Climate Change (“COP28”). At the COP28, the Parties agreed to non-binding language calling on countries to transition away from fossil fuels in energy systems to achieve net zero emissions by 2050. The impact of these actions remains unclear at this time. Moreover, many states, regions, and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities, and some regional cap and trade programs have been established in the Northeast and the Western U.S. There have also been numerous protests and challenges to the permitting of new fossil fuel infrastructure, including coal-fired power plants and pipelines, by environmental organizations and state regulators for concerns related to GHG emissions. Various state regulatory authorities have rejected the construction of new coal-fired power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future

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laws limiting the emissions of carbon dioxide. In addition, over thirty states have currently adopted “renewable energy standards” or “renewable portfolio standards,” which encourage or require electric utilities to obtain a certain percentage of their electricity from renewable resources by a certain date. Other states may adopt similar requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers, they may reduce the demand for fossil fuel energy and may affect long-term demand for our coal and negatively impact demand for electricity from our coal-fired power plant at Merom, each of which could have an adverse effect on our operations.

Finally, while the U.S. Supreme Court has held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, the Court did not decide whether similar claims can be brought under state common law. As a result, tort claims or actions that may be brought against us could have an adverse impact on our business, financial condition, or results of operations.

It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with fossil fuel production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for fossil fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, which could have a material adverse effect on our business, financial condition, and results of operations. Fossil fuel companies are also facing challenges by activists using other means, including pressuring financing and other institutions into restricting access to capital, bonding and insurance, as well as pursuing tort litigation for various alleged climate-related impacts.

Water Discharge

Various statutes and regulations at the federal, state, regional, and local levels govern water use, discharge, protection, and influence and add challenge and uncertainty to our business. The Federal Water Pollution Control Act, known as the Clean Water Act (“CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants into federal and state waters. The discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. Compliance with existing and future requirements may increase costs, affect operations, and impede strategic planning.

Section 402 of the CWA governs discharges of pollutants into waters of the United States, primarily through National Pollutant Discharge Elimination System (“NPDES”) permits. Merom is subject to an NPDES permit for its wastewater and stormwater discharges. The definition of “waters of the United States,” which governs federal jurisdiction under the CWA, has been subject to many shifting regulations and litigation in recent years. However, in May 2023, the U.S. Supreme Court issued its decision in Sackett v. EPA, which significantly limited the scope of federal jurisdiction over wetlands under the CWA. In response to the Supreme Court’s decision, in August 2023, EPA issued its final rule amending the definition of “waters of the United States” to conform its regulations to the Supreme Court’s decision in Sackett. While the Sackett decision and the subsequent rule issued by EPA have reduced the scope of federal regulation at this time, it is possible that more stringent permitting requirements may be imposed in the future, and we are not able to accurately predict the impact, if any, of such permitting requirements.

Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of certain wetlands and streams. The CWA and equivalent state legislation, where applicable, affect electric power generation operations and coal mining operations that impact such wetlands and streams. We believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the relevant agencies. However, mitigation requirements under existing and possible future “fill” permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future.

In order for us to conduct certain activities, we may need to obtain a permit for the discharge of fill material from the U.S. Army Corps of Engineers (“Corps of Engineers”) and/or a discharge permit from the state regulatory authority under the state counterpart to the CWA. Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments. The CWA authorizes the EPA to review

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Section 404 permits issued by the Corps of Engineers, and in 2009, the EPA began reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia. The EPA also has statutory “veto” power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.” The EPA has exercised its veto power over Section 404 permits for surface mining operations. Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to our continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal revenues.

Total Maximum Daily Load (“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired waterbody can receive and still meet state water quality standards and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDL-related allocations or any changes to antidegradation policies for streams near our coal mines or electric power generating operations could require more costly water treatment and could adversely affect our coal production or electric power generation operations.

One of the most impactful CWA programs currently affecting our business is the Effluent Limitations Guidelines and Standards (“ELG”) rule. Under the ELG rule, which became effective on January 4, 2016, the EPA established federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. The EPA issued a supplemental rule in May 2024 (the “2024 EPA ELG Rule”), which established more stringent requirements for FGD wastewater, bottom ash transport water, and combustion residual leachate, among other measures. The new rule also established early shutdown alternatives for plants permanently ceasing coal combustion by certain target dates. In the future, new permit conditions could be established to meet the requirements in the 2024 EPA ELG Rule, which will be defined following negotiations with state permitting authorities. Legal challenges to the 2024 EPA ELG Rule have been filed and the EPA has extended the compliance deadlines for the 2024 EPA ELG Rule by five years. This extension has been legally challenged by environmental groups. Until litigation is complete and permit conditions are established, the full impact of the ELG rules on the market for our coal products and our electric power generation operations remain uncertain.

On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source, but are conveyed to navigable waters through a nonpoint source, such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases relevant to determination of “functional equivalent” are ongoing in various jurisdictions. It is too early to determine whether the Supreme Court decision or the result of litigation to “functional equivalent” may have a material impact on our business, financial condition, or results of operations.

In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant selenium in fresh water. NPDES permits may be updated to include selenium water quality-based effluent limits based on a site-specific evaluation process, which includes determining if there is a reasonable potential to exceed the revised final selenium water quality standards for the specific receiving water body utilizing actual and/or project discharge information for the generating facilities. As a result, it is not yet possible to predict the total impacts of this final rule at this time, including any challenges to the rule and the outcome of any such challenges.

Merom is subject to requirements under CWA Section 316(a) for thermal discharges and Section 316(b) for cooling water intake structures. Section 316(a) standards allow thermal dischargers to have less stringent alternate thermal limits if they can demonstrate that the current effluent limitations, based on water quality standards, are more stringent than necessary to protect the aquatic organisms in the receiving water body. Merom currently holds a 316(a) variance and is subject to alternative thermal effluent limits. If Merom’s 316(a) variance were revoked in the future, additional capital expenditures may be required that could be material.

Section 316(b) standards require affected facilities to choose among seven best technology available (“BTA”) options to reduce fish impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is

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possible that this process, which includes permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology, although the Indiana Department of Environmental Management has previously determined that the systems in place currently at Merom meet the BTA requirements. If additional capital expenditures became necessary in the future, they could be material.

Hazardous Substances and Wastes

The Federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), otherwise known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages. Some products used in coal mining operations and electric power generating operations generate waste containing hazardous substances. We are currently unaware of any material liability under CERCLA or analogous state laws associated with the release or disposal of hazardous substances from our past or present mine sites or electric power generating operations.

The Federal Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

Many mining wastes as well as coal combustion residuals (“CCRs”) generated from our electric power generating operations are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA nonetheless impacts the coal industry and electric power generation industry in particular because it regulates the management and disposal of certain CCR. CCR is regulated as “non-hazardous” waste which avoids the stricter, more costly, regulations under RCRA’s hazardous waste rules, but this regulation may still increase our customers’ operating costs and potentially reduce their ability to purchase coal as well as increase the operating cost of our electric power generation operations. In April 2015, the EPA finalized rules on CCRs. The rule established nationally applicable minimum criteria for the disposal of CCRs in new and currently operating landfills and surface impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure requirements, and post-closure care. CCRs are generated at Merom and the facility is subject to the CCR rule. The EPA has indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. The CCR rule, current or proposed amendments to the federal CCR rule or state CCR regulations, the results of groundwater monitoring data, or the outcome of CCR-related litigation could have a material impact on our business, financial condition and results of operations. The EPA has mandated closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site specific circumstances. Continuing legal challenges to EPA rulemaking regarding CCRs are creating uncertainty in estimating compliance and remediation costs that we may incur, and future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. Further, in May 2024, the EPA finalized changes to the CCR regulations for inactive surface impoundments at inactive electric utilities, referred to as “legacy CCR surface impoundments,” and also established certain requirements for a new subcategory of CCR areas called “CCR management units,” among other actions. The combined effect of the CCR rules and ELG regulations (discussed above) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal, and the CCR rule requirements and any revisions affect our CCR landfill at Merom.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related activities.

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We are not currently materially impacted by these requirements. If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered, or to re-designate a species from threatened to endangered, we could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.

Other Environmental, Health and Safety Regulation

In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground storage tanks in which we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulations. In addition, our use of explosives is subject to the Federal Safe Explosives Act. We are also required to comply with the Federal Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition, or results of operations.

Climate Change Issues

Physical Climate Risks. Increased frequency of severe and extreme weather events associated with climate change could materially impact our facilities, energy sales, and results of operations. More extreme and volatile temperatures, increased storm intensity and flooding, and more volatile precipitation leading to changes in lake and river levels are among the weather events that are most likely to impact our business. While we perform ongoing assessments of physical risk, including physical climate risk, to our business, we are unable to predict these events.

Transition Climate Risks. Future legislative and regulatory programs, at both the federal and state levels, could significantly limit allowed GHG emissions or impose a cost or tax on GHG emissions. Revised or additional future GHG legislation or regulation related to the generation of electricity or the extraction, production, distribution, transmission, storage and end use of natural gas could materially impact our gas supply, financial position, financial results and cash flows.

We continue to monitor the implementation of any final and proposed climate change-related legislation and regulations, but we cannot predict their impact on our business at this time. We are also reviewing such legislation and regulations for potential opportunities that may align with our strategy going forward.

Suppliers

The main types of goods we purchase for our mining operations are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, electricity, fuel, and tires. For our electric operations, we purchase coal, limestone, fuel oil, anhydrous ammonia, and other chemicals and items necessary to operate Merom. Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of electricity. The supplier base providing mining materials has been relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop.

Electric Operations

Our electric operations employ third party service providers for the day-to-day operations and maintenance of Merom as well as managing market transactions and optimizing plant dispatch. We contract with Consolidated Asset Management Services (“CAMS”) to manage ongoing operations, maintenance and asset management functions at Merom. CAMS provides an operations and maintenance program which includes daily management of plant performance, safety protocols and workforce management, and develops and implements predictive and preventative maintenance schedules designed to maximize plant availability and maintain compliance with environmental and regulatory standards. In coordination with our engineering teams, CAMS identifies and manages capital projects that aim to improve operational efficiency and reduce long-term costs. CAMS also provides performance monitoring and reporting. We maintain

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oversight of CAMS through regular audits and performance reviews, confirming all procedures align with our Company policies and best practices.

We contract with Alliance for Cooperative Energy Services Power Marketing, LLC (“ACES”), as our agent to manage our wholesale power market activities and risk management strategies related to electric operations. Through this relationship, ACES manages the dispatch and scheduling on the real-time and day-ahead markets. ACES manages bidding strategies, scheduling our generation in the relevant RTOs or ISOs. To optimize our sales portfolio, ACES analyzes energy market dynamics, identifies opportunities to optimize plant dispatch, and recommends operational adjustments to capture favorable margins. ACES also assists in risk management by executing short-term trades on our behalf to mitigate price volatility and lock in predictable revenues, as well as ensuring that our participation in the energy markets adheres to relevant market rules and regulations. We receive regular risk reports and settlement statements, which our internal teams review to confirm accuracy and compliance with our company policies.

We regularly review the performance and controls of CAMS and ACES. Our formal review processes include monthly performance reviews through joint meetings with CAMS and ACES to evaluate KPI trends, discuss operational challenges, and plan market strategies. Periodic internal and external audits examine environmental, safety, and financial compliance, ensuring third-party activities align with regulatory standards and Company objectives. We also have a risk management committee that evaluates all marketing activities and exposures. Volatility in wholesale power prices can impact revenue. Equipment failures or unexpected downtime at coal plants can lead to missed market opportunities or contractual liabilities. Our teams, in conjunction with CAMS and ACES, monitor emerging industry policies to proactively plan operational or strategic adjustments.

Significant third-party customers in 2025 include Hoosier Energy Rural Electric Cooperative, Inc., Citadel Energy Marketing, LLC and MISO.

U.S. Coal Industry

The major coal production basins in the U.S. include Central Appalachia (“CAPP”), Northern Appalachia (“NAPP”), the ILB, Powder River Basin (“PRB”), and the Western Bituminous region (“WB”). CAPP includes eastern Kentucky, Tennessee, Virginia, and southern West Virginia. NAPP includes Maryland, Ohio, Pennsylvania, and northern West Virginia. The PRB is located in northeastern Wyoming and southeastern Montana. The WB includes western Colorado, eastern Utah, and southern Wyoming. The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana, and western Kentucky.

Through our wholly-owned subsidiary, Sunrise, we mine coal exclusively in the ILB. The ILB is centrally located between four of the largest NERC regions that consume coal as fuel for electricity generation (East North Central, West South Central, West North Central, and East South Central). The region also has access to sufficient rail and water transportation routes that service coal-fired power plants in these regions as well as other significant coal consuming regions of the South Atlantic and Middle Atlantic.

Coal type varies by basin. Heat value and sulfur content are important quality characteristics and determine the end-use for each coal type. ILB coal is typically high sulfur coal and coal-fired plants that burn high sulfur coals are typically required to install scrubbers to comply with regulations limiting the release of sulfur dioxide in power plant emissions.

Coal in the U.S. is mined through surface and underground mining methods. The primary underground mining techniques are longwall mining and continuous (room-and-pillar) mining. The geological conditions dictate which technique to use. Our mines utilize the continuous mining technique. In continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment cuts the coal from the mining face. Generally, openings are driven 20’ wide, and the pillars are rectangular in shape measuring 40’x 40’. As mining advances, a grid-like pattern of entries and pillars is formed. Roof bolts are used to secure the roof of the mine. Battery cars move the coal to the conveyor belt for transport to the surface. The pillars can constitute up to 50% of the total coal in a seam.

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Significant third-party customers in 2025 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC), and Duke Energy Corporation (NYSE: DUK).

Of our 2025 sales, on a segment basis 56%, excluding Merom, were derived to locations in the State of Indiana.

As of December 31, 2025, we are committed to supplying third-party customers a base amount of 5.7 million tons of coal through 2028. We are committed to supplying coal to Merom a base amount of 7.8 million tons of coal through 2028.

Based on the contracted tons described above, we anticipate our mines will need to produce at a 3.7 million ton annualized pace for the foreseeable future to meet Merom and third-party market demand. We also have contracts in place to purchase coal through December of 2027, and anticipate similar contracts in the future.

We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers.

Some utility customers have proposed shuttering certain plant units or entire plants in the coming years. It remains to be seen whether these plans will be implemented.

The U.S. coal industry is highly competitive, with numerous producers selling into all markets that use coal. We compete against large producers such as Peabody Energy Corporation (NYSE: BTU), Alliance Resource Partners (Nasdaq: ARLP), and other private producers.

Human Capital

As of December 31, 2025, Hallador and its subsidiaries employed 633 full-time employees and temporary miners, 599 of those employees and temporary miners are directly involved in the coal mining or coal washing process. Our coal workforce is union-free. At our power plant, our operator, CAMS, employs represented workers. While these workers are not Hallador Power employees, labor disruptions within the CAMS workforce could disrupt our operations at the plant. To attract and retain top talent, we provide competitive wages, an annual bonus for all employees, excellent benefits, an employee health clinic and a culture that is committed to health and safety at all levels.

Employee health and safety is a top priority at all of our operations. With a robust safety department and safety standards that exceed mandated guidelines, we make safety the foundation of everything we do. At our Sunrise mine operations, while every precaution is taken to prevent mine emergencies, Sunrise maintains its own private mine rescue team. This team is trained and ready to manage emergency situations at a Sunrise facility, but also ready and available to assist other mine rescue teams. We continuously monitor safety data such as injury severity, violations per inspection day, and significant and substantial citations and compare to the national averages noting that in 2025 we were at or below the national averages in all three categories. For more information about citations or orders for violations of standards under the FMSHA, as amended by the Miner Act, please see our Exhibit 95.1 to this Annual Report on Form 10-K.

While other companies have moved to high-deductible health plans, Hallador is committed to providing comprehensive affordable health insurance with low-cost deductibles and co-pays to take care of our employees and their families. We believe in decreasing the barriers to healthcare, so employees and their dependents do not have to delay care. Our employees and their families also have access to a private full-time health and wellness clinic, with free medications, no cost diagnostics, and a wellness coach.

Beyond investing in the safety and health of its employees, Hallador invests in educational opportunities for its employees. All continuing education requirements and training are completely paid for by the company and tuition reimbursement programs are available to every employee companywide.

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Other

We have no significant patents, trademarks, licenses, franchises, or concessions.

Corporate and Other Available Information

The Company is a Colorado corporation. Our principal executive office, as well as Sunrise’s and Hallador Power’s principal executive office, is located at 1183 East Canvasback Drive, Terre Haute, Indiana, 47802. All offices can be reached at 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis.

We file our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports with the SEC. You may obtain copies of these documents, free of charge, on the SEC's website at www.sec.gov. In addition, as soon as reasonably practicable after such materials are filed or furnished with the SEC, we make copies available free of charge on our website at www.halladorenergy.com under the “Investor Relations” section. We also post important information, including press releases, investor presentations, and notices of upcoming events on our website, and utilize it as a channel for distributions to public investors and for disclosing material non-public information in compliance with Regulation FD. Investors may be notified of postings to our website by signing up for alerts on the “Investor Relations” section of our website.

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