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Item 1. Business

2026-03-12 compared with 2025-03-17 · 238 added, 295 removed, 180 unchanged (75% of the section changed)

Hallador Energy Company is a vertically integrated power and coal company with operations primarily in Indiana.

The Company operates across multiple stages of the energy supply chain, from coal extraction to electricity generation and mines coal from the rich, high-quality, lower sulfur reserves found in the Illinois Basin (“ILB”).

Once the coal is mined by Sunrise Coal, LLC (“Sunrise”), the Company’s wholly-owned mining subsidiary, the Company processes and transports it to power plants, where it is used as a primary fuel source for generating electricity.

Through its wholly-owned subsidiary Hallador Power, LLC (“Hallador Power”), the Company owns and operates the Merom Power Plant (“Merom”), a 1,080 MW net coal fired power generating station, consisting of two 590 MW sub-critical water tube drum type steam turbine generators.

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 to the Midcontinental Independent System Operator (“MISO”) interconnection.

Hallador Power sells wholesale energy and accredited capacity to utilities within the MISO system through power purchase agreements (“PPA”) and other bilateral transactions.

Merom is located in Sullivan County, Indiana, about twenty miles from Sunrise’s Oaktown Mining Complex.

Sunrise also sells coal to other utilities in Indiana and throughout the southeast United States.

In addition, it has a developed infrastructure for the transport of coal, including rail networks and truck loading systems, facilitating the efficient movement of the resource from the mine to its customers.

The vertically integrated structure allows the Company to control the entire process, from mining to power production, providing cost efficiencies, greater operational flexibility, and the ability to manage supply and demand within the energy market.

Hallador Power has invested in technologies to reduce emissions and improve the environmental performance of coal-fired generation, particularly in response to regulatory pressures.

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.

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.

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.

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Regulation and Laws

The electric power generation and coal mining industries are subject to extensive regulation by federal, state, and local authorities on matters such as:

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

● employee health and safety;

● mine permits and other licensing requirements;

● air quality standards and greenhouse gas emissions;

● air quality standards, including greenhouse gas emissions;

● water quality standards;

● storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could reach waterways, wetlands, or groundwater;

● plant and wildlife protection, and historic and archeological site and cultural resource protection, that could limit or prohibit electric power generation, mining or exploration;

● restricting the types, quantities, and concentration of materials that can be released into the environment in the performance of electric power generation, mining, exploration or production activities;

● discharge of materials;

● hazardous substances;

● solid waste management;

● plant and wildlife protection and historic and archeological site and cultural resource protection;

● storage and handling of explosives;

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● the effects, if any, that electric power generation or mining activities, including coal combustion residuals, have on groundwater quality and availability.

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, joint and several 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.

The regulatory burden on fossil fuel industries increases the cost of doing business and consequently affects profitability.

The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any 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.

In addition, the electric power industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has also adversely affected demand for coal.

It is possible that new legislation or regulations may be adopted, that existing laws or regulations may be interpreted differently or more stringently enforced, that existing regulations may be repealed or that the authority of current regulators may be reduced or revoked, any of which could have a significant impact on our mining or electric power generating operations or our customers’ ability to use coal.

For more information, please see “Recent Regulatory Developments from the Presidential Transition” in this section, below, and the risk factors described in “Item 1A.

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.

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.

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.

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 electric power generating and mining operations in compliance with applicable federal, state, and local laws and regulations.

However, because of the extensive and detailed nature of these regulatory requirements, including the regulatory system of the Mine Safety and Health Administration (“MSHA”), where citations can be issued without regard to fault and many of the standards include subjective elements, it is not reasonable to expect any electric power generating company or coal mining company to be free of citations.

When we receive a citation, we attempt to remediate any identified condition 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.

Compliance with these laws and regulations has substantially increased the cost of electric power generation and the cost of coal mining for domestic coal producers.

Expenditures for environmental matters have not been material in recent years.

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.

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Electric Power Generation Permits and Approvals

Numerous governmental permits or approvals are also required for electric power generation operations, including coal-fired power plants such as Merom Generating Station.

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 greenhouse gas emissions, the management and disposal of coal combustion residuals and other wastes or materials, and wastewater effluent treatment and discharge, among others.

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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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.

We are required to post bonds to secure performance under our coal combustion residuals landfill permit.

Under some circumstances, substantial fines and penalties, including revocation of electric power generating permits, may be imposed under the laws and regulations described above and below.

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.

Although, like other power generating companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

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

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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.

We are required to post bonds to secure performance under our permits.

Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above.

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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.

Although, like other coal companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Mine Health and Safety Laws

The Federal Mine Safety and Health Act of 1977 (“FMSHA”) and regulations adopted pursuant thereto, imposes extensive and detailed safety and health standards on numerous aspects of 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.

In addition, the states where we operate have state programs for mine safety and health regulation and enforcement.

Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the United States (the “U.S.”) for the protection of employee safety and have a significant effect on our operating costs.

Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.

FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability or liability without fault, and FMSHA requires the imposition of a civil penalty for each cited violation.

Negligence and gravity assessments, along with other factors, can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties.

FMSHA also contains criminal liability provisions.

For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order, or carry out violations of the FMSHA or its mandatory health and safety standards.

The Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities.

Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:

● sealing off abandoned areas of underground coal mines;

● mine safety equipment, training, and emergency reporting requirements;

● substantially increased civil penalties for regulatory violations;

● training and availability of mine rescue teams;

● underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;

● flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry;

● post-accident two-way communications and electronic tracking systems.

MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.

In 2014, MSHA began implementation of a finalized new regulation titled “Lowering Miners’ Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.” The final rule implemented a reduction in the allowable respirable coal mine dust exposure limits, requires the use of sampling data taken from a single sample rather than an average of samples, and increases oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine, all of which increase mining costs.

The second phase of the rule began in February 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor technology, which provides real-time dust exposure information to the miner.

Phase three of the rule began in August 2016 and resulted in lowering the current respirable dust level of 2.0 milligrams per cubic meter to 1.5 milligrams per cubic meter of air.

Compliance with these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations.

MSHA published a request for information regarding engineering controls and best practices to lower miners’ exposure to respirable coal mine dust, and the comment period closed in July 2022.

It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period.

MSHA has also published, and may continue to publish, various proposed and final rules or requests for information, which may result in additional rulemakings.

For example, in June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust.

Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA’s request for information.

The comment period for the request for information closed in September 2020.

In August 2019, MSHA published a request for information regarding exposure to respirable crystalline silica, most commonly found in the mining environment through quartz.

The request solicited information regarding best practices to protect miners’ health from exposure to quartz, including examination of a new reduced permissible exposure limit, potential new or developing protective technologies, and/or technical and educational assistance.

The comment period for the request for information closed in October 2019.

On December 10, 2024, MSHA published a final rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments.

On December 20, 2023, MSHA published a final rule requiring that all mine operators develop and implement a written safety program for mobile and powered haulage equipment at surface mines and surface areas of underground mines (Safety Program for Surface Mobile Equipment).

It is uncertain whether MSHA will engage in further rulemaking regarding the above issues or any of the other various proposed rules or requests for information or whether any such rules would have material impacts on our operations or our costs of operation.

Subsequent to the passage of the MINER Act, Illinois, Kentucky, Pennsylvania, and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight.

Additionally, state administrative agencies can promulgate administrative rules and regulations affecting our operations.

Other states may pass similar legislation or administrative regulations in the future.

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, an adverse impact on our results of operations and financial position.

Black Lung Benefits Act

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 current 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 January 1, 2022, the trust fund was funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price.

The Inflation Reduction Act of 2022 raised the excise tax, effective October 1, 2022, 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.

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.

We also provide for these 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.

The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria.

These regulations 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.

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.

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.

Currently, 100% of our production involves underground room and pillar mining (no surface subsidence).

We do not engage in either mountain top removal or long-wall mining.

SMCRA nevertheless requires that comprehensive

environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.

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, a consequence of longwall mining and possibly other mining operations.

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 fee expired on September 30, 2021, and was reauthorized through September 30, 2034, under the Infrastructure Investment and Jobs Act which was signed on November 15, 2021.

The fee, as reauthorized, 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 discharge when necessary.

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

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.

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However, we cannot assure you that such claims will not be asserted in the future.

Coal Combustion Residuals

In April 2015, the United States Environmental Protection Agency (“EPA”) finalized rules on coal combustion residuals (“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 Station 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.

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.

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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.

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.

Air Emissions

The Clean Air Act (“CAA”) and similar state and local laws and regulations regulate emissions into the air and affect coal mining and electric power generation operations.

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.

Installation of 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 and, depending on the requirements of individual state implementation plans (“SIPs”), could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future.

A significant reduction in fossil fuels’ share of power generating capacity could have a material adverse effect on our business, financial condition, and results of operations.

In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:

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:

● The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric power generating facilities.

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Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions.

In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electric generating levels.

● The Cross-State Air Pollution Rule (“CSAPR”) addresses the “good neighbor” provision in the Clean Air Act, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment of, or interference with maintenance of, any National Ambient Air Quality Standards (“NAAQS”).

In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization (“FGD”) systems, or “scrubbers,” or by reducing electric generating levels.

● The Cross-State Air Pollution Rule (“CSAPR”) addresses the “good neighbor” provision in the CAA, which prohibits sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s nonattainment of, or interference with maintenance of, any National Ambient Air Quality Standards (“NAAQS”).

CSAPR requires power plants in certain states to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the Acid Rain Program.

In October 2016, the EPA published a final rule to update the CSAPR to address the 2008 ozone NAAQS ("CSAPR Update Rule").

Following legal challenges related to the CSAPR Update Rule, on April 30, 2021, the EPA issued the Revised CSAPR Update Rule.

The Revised CSAPR Update Rule required affected electric generating units ("EGUs") within certain states (including Indiana) to participate in a new trading program.

On June 5, 2023, the EPA published a final Federal Implementation Plan to address air quality impacts with respect to the 2015 Ozone NAAQS called the “Good Neighbor Plan.” However, on June 27, 2024, the United States Supreme Court granted emergency applications seeking a stay of the Good Neighbor Plan pending judicial review.

In response, on November 6, 2024, EPA issued an interim final rule, which effectively reinstated the Revised CSAPR Update Rule during the stay.

While our CSAPR compliance costs to date have not been material, the future availability of and cost to purchase allowances to meet the emission reduction requirements is uncertain at this time, but it could be material.

● In February 2012, the EPA adopted the Mercury and Air Toxic Standards (“MATS”), which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants.

In March 2013, the EPA finalized a reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies.

In subsequent litigation, the U.S.

Supreme Court struck down the MATS rule based on the EPA’s failure to take costs into consideration.

Court of Appeals for the District of Columbia Circuit (the “D.C.

Circuit Court”) allowed the current rule to stay in place until the EPA issued a new finding.

In April 2016, the EPA issued a final supplemental finding upholding the rule and concluding that a cost analysis supports the MATS rule.

In April 2017, the D.C.

Circuit Court of Appeals granted the EPA’s request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the supplemental finding.

In December 2018, the EPA

issued a proposed Supplemental Cost Finding, as well as the CAA required “risk and technology review.” In May 2020, EPA issued a final rule that reverses the Agency’s prior determination from 2000 and 2016 that it was “appropriate and necessary” to regulate hazardous air pollutants (“HAP”) from coal-fueled Electric Generating Units (“EGUs”) under the MATS rule.

However, in March 2023, EPA published a final rule revoking the May 2020 finding, and in May 2024, EPA issued a final rule amending MATS and increasing the stringency of certain requirements.

The MATS rule has forced electric power generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units.

The announced and possible additional retirements are likely to reduce the demand for coal.

● The Mercury and Air Toxic Standards (“MATS”) issued by the EPA regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants.

The MATS rule has forced electric power generators to make capital investments to retrofit power plants.

Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed.

Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal.

We continue to evaluate the possible scenarios associated with CSAPR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.

● The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the National Ambient Air Quality Standards (“NAAQS”) should be revised.

Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter (“PM”), ozone, nitrogen oxide, and sulfur dioxide.

As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in “attainment” but do not attain the new standards.

In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants.

In March 2019, the EPA published a final rule that retained the current primary NAAQS for sulfur oxide.

In December 2020, EPA published a final rule to retain the current NAAQS for both PM and ozone;

however, various entities have filed litigation against one or both of these rulemakings, and the Biden Administration announced that it would reconsider and potentially revise the NAAQS.

On February 7, 2024, the EPA issued a new final rule regarding the Reconsideration of the NAAQS for PM, and as part of that rule, EPA revised the level of the primary (health-based) annual PM2.5 standard from 12.0 to 9.0 micrograms per cubic meter.

With respect to ozone, in August 2023, EPA announced that it is also conducting a new review of the ozone NAAQS.

New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers.

Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our electric power generating operations and our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal or electricity from coal-fired power plants.

We continue to evaluate the possible scenarios associated with MATS and the effects it may have on our business and our results of operations, financial condition or cash flows.

● The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the NAAQS should be revised.

Pursuant to this process, the EPA has adopted more stringent

NAAQS for fine particulate matter (“PM”), ozone, nitrogen oxide, and sulfur dioxide.

As a result, some states will be required to amend their existing state implementation plans (“SIPs”) to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in “attainment” but do not attain the new standards.

New or revised standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers.

Because coal mining operations and coal-fired electric generating facilities emit PM and sulfur dioxide, our electric power generating operations and our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal or electricity from coal-fired power plants.

● The EPA’s regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas, and international parks.

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Typically, these plans call for reductions in sulfur dioxide and nitrogen oxide emissions from coal-fired power plants.

In prior cases, the EPA has decided to negate the SIPs and impose stringent requirements through Federal Implementation Plans (“FIPs”).

In some cases, the EPA has negated the SIPs and imposed more stringent requirements through Federal Implementation Plans (“FIPs”).

The regional haze program, including particularly the EPA’s FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions.

These requirements could limit the demand for coal in some locations.

In September 2018, the EPA issued a memorandum that detailed plans to assist states as they develop their SIPs, which was followed by a supplemental memorandum in July 2021 for SIPs for the second implementation period.

● The EPA’s new source review (“NSR”) program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment.

The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the NSR program.

The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the program.

Several of these lawsuits have been settled, but others remain pending.

In October 2020, the EPA finalized a rule to clarify the process for evaluating whether the NSR permitting program would apply to a proposed modification of a source of air emissions.

The EPA has announced that it will review the NSR program.

Depending on the ultimate resolution of the EPA’s litigation and review, demand for coal could be affected as well as the process by which EPA evaluates modifications to power plants that trigger NSR.

● The EPA’s new source review (“NSR”) program under the CAA may require existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment.

During 2025, the EPA announced policies related to the withdrawal of the 2024 project emissions accounting rule, reinstatement of the “no-second-guessing” policy, retirement of the NSR Reactivation policy and planned rulemaking to revise “begin actual construction”.

The EPA plans to propose and finalize revisions to NSR regulations in 2026.

GHG Emissions

Combustion of fossil fuels, such as the coal we produce and the coal that is used at Merom Station, results in the emission of GHGs, such as carbon dioxide and methane.

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.

The EPA has begun to regulate GHG emissions under the CAA based on the U.S.

Supreme Court’s 2007 decision that the EPA has authority to regulate GHG emissions.

Although the U.S.

Supreme Court’s holding did not expressly involve the EPA’s authority to regulate GHG emissions from stationary sources, such as coal-fired power plants, the EPA has determined on its own that it has the authority to regulate GHG emissions from power plants and issued a final rule which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare.

Several rulemakings have been issued under the EPA’s New Source Performance Standards (“NSPS”) that constrain the GHG emissions of fossil-fuel-fired power plants.

In August 2015, the EPA issued its final Clean Power Plan (“CPP”) rules that establish carbon pollution standards for power plants, called CO2 emission performance rates.

Judicial challenges led the U.S.

Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the United States Court of Appeals for the District of Columbia (“Circuit Court”) even issued a decision.

Then, in October 2017 the EPA proposed to repeal the CPP.

The EPA subsequently proposed the Affordable Clean Energy (“ACE”) rule to replace the CPP with a rule that utilizes heat rate improvement measures as the “best system of emission reduction.” The ACE rule adopted new implementing regulations under the CAA to clarify the roles of the EPA and the states, including an extension of the deadline for state plans and EPA approvals;

and the rule revises the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements.

In June 2019, the EPA published the final repeal of the CPP and promulgation of the ACE rule.

On January 19, 2021, the Circuit Court struck down the ACE rule and found the EPA’s “repeal of the CPP rested critically on a mistaken reading of the CAA.” On June 30, 2022, the Supreme Court of the United States reversed and remanded the Circuit Court’s decision in West Virginia v.

EPA and found that, in the promulgation of the CPP, the EPA had acted outside the bounds of the legal authority granted to the agency by Congress.

On May 9, 2024, the EPA published a final rule that, among other things, repealed the ACE rule and also established emissions guidelines for GHG emissions for existing coal-fired and new or substantially modified gas-fired power plants.

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:

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those operating between 2032 and 2039 will be required to achieve emissions reductions equivalent to co-firing 40 percent by volume natural gas;

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”).

While the rule has been challenged in court, the US Supreme Court declined to stay the rule while those challenges proceed.

Additionally, the new Trump Administration has indicated its intention to revise the rule.

The rule could potentially have a material adverse effect on our business, financial condition, and results of operations.

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.

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treaty commitments, new domestic legislation or regulation by the EPA.

Congress has not currently adopted explicit legislation to restrict carbon dioxide emissions from existing power plants and has not otherwise expanded the legal authority of the EPA following West Virginia v.

EPA , including as it relates to its authority to regulate carbon dioxide emissions from existing and modified power plants.

However, we cannot predict whether such legislation will be signed into law in the future.

Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction targets.

These commitments could further reduce demand and prices for fossil fuels.

Although the U.S.

had withdrawn from the Paris Agreement, President Biden recommitted the U.S.

in February 2021 and, in April 2021, the Biden Administration announced a new, more rigorous nationally determined emissions reduction level of 50- 52% reduction from 2005 levels in economy-wide net GHG emissions by 2030.

However, the new Trump administration has recently announced its intention to withdraw from the Paris Agreement, so these targets from the Biden Administration may change.

Since the 2021 Biden Administration targets were announced, 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”).

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.

Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels.

Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal and electricity from coal-fired power plants, such as Merom Station, could be negatively impacted, which would have an adverse effect on our operations.

There have 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.

For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide.

In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board.

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 electric generation portfolio from renewable resources by a certain date.

Several states have announced their intent to have renewable energy comprise 100% of their electric generation portfolio.

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

laws limiting the emissions of carbon dioxide.

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.

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, despite this favorable ruling, tort-type liabilities remain a concern.

In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act (“NEPA”).

These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects.

In April 2022, the White House Council on Environmental Quality (“CEQ”) issued a final rule revoking some of the modifications made to the NEPA regulations under the previous administration and reincorporated the consideration of direct, indirect and cumulative effects of major federal actions, including GHG emissions.

And, in January 2023, the CEQ released guidance, effective immediately, to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under NEPA.

However, in November 2024, the U.S.

Court of Appeals for the D.C.

Circuit held that CEQ has no authority to issue regulations implementing NEPA and that CEQ’s NEPA regulations are, therefore, invalid and of no effect.

Many states and regions have adopted GHG initiatives, and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric power generating facilities.

For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement (“RGGI”), calling for the implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states.

The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program.

Auctions for carbon dioxide allowances under the program began in September 2008.

Since its inception, several additional states and Canadian provinces have joined RGGI as participants or observers, while Virginia has withdrawn from RGGI via executive order by its governor.

Similar to RGGI, five western states launched the Western Regional Climate Initiative, although only California and certain Canadian provinces are currently active participants.

We cannot predict what other regional greenhouse gas reduction initiatives may arise in the future.

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.

Finally, activists may try to hamper fossil fuel companies by 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.

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

The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting.

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.

Hallador’s Merom Generating Station is subject to an NPDES permit for its wastewater and stormwater discharges.

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 such equivalent state legislation exists, 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 responsible 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.

The definition of “waters of the United States,” which governs federal jurisdiction under the Clean Water Act, has been subject to many shifting regulations and litigation in recent years.

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 Clean Water Act.

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.

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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 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.

Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

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.” In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a previously issued permit for Spruce No.

1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia.

This action was the first time that such power was exercised with regard to a previously permitted coal mining project which veto was subsequently upheld by the D.C.

Circuit Court in 2013.

The CWA authorizes the EPA to review

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.

In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on a fictitious mine scenario.

The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning.

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.

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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.

On November 3, 2015, the EPA published the final Effluent Limitations Guidelines and Standards (“ELG”) rule, revising the regulations for the Steam Electric Power Generating category, which became effective on January 4, 2016.

The rule sets the first 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 combined effect of the CCR rule and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal-burning power plants that cannot comply with the new standards.

In November 2019, the EPA proposed revisions to the 2015 ELG rule and announced proposed changes to regulations for the disposal of coal ash in order to reduce compliance costs.

In October 2020, the EPA published a final rule.

In August 2021, the EPA initiated supplemental rulemaking indicating that it intended to strengthen certain discharge limits.

The EPA issued a final rule for in May 2024, which established more stringent requirements for flue gas desulfurization (“FGD”) wastewater, bottom ash transport water, and combustion residual leachate, among other measures.

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.

These regulations may impact the market for our coal products and our electric power generating operations.

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.

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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 such final rule and the outcome of any such challenges.

The Merom Generating Station is subject to requirements under CWA Section 316(a) for thermal discharges and Section 316(b) for cooling water intake structures.

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 Station is currently subject to a 316(a) variance and alternative thermal effluent limits.

If Merom Station’s 316(a) variance were revoked in the future, additional capital expenditures may be required that could be material.

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 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 Station meet the BTA requirements.

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.

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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.

Many mining wastes as well as CCR 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 also allows the EPA to require corrective action at sites where there is a release of hazardous substances.

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While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

Coal Combustion Residuals

RCRA impacts the coal industry and electric power generation industry in particular because it regulates the management and disposal of certain coal combustion residuals (“CCR”).

On April 17, 2015, the EPA finalized regulations under RCRA for the management and disposal of CCR.

Under the finalized regulations, CCR is regulated as “non-hazardous” waste and avoids the stricter, more costly, regulations under RCRA’s hazardous waste rules.

While classification of CCR as a hazardous waste would have led to more stringent restrictions and higher costs, 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.

The CCR rule was subject to legal challenge and ultimately remanded to the EPA.

On August 28, 2020, the EPA published a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site specific circumstances.

Certain provisions of the revised CCR rule were vacated by the D.C.

Circuit Court in 2018.

Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCR facilities who sought approval to continue disposal of CCR and non-CCR waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule.

While the EPA issued one conditional approval, the EPA is requiring the remaining facilities to cease receipt of waste within 135 days of completion of public comment or around July 2022.

And, in January 2023, the EPA issued six proposed determinations to deny facilities’ requests to continue disposal into unlined surface impoundments.

The current determinations, future determinations of the same nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers.

Further, in May 2024, EPA finalized changed 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.

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.

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 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 Generating Station.

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

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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.

In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration and, in June 2022, the USFWS and the National Marine Fisheries Service published a final rule rescinding the 2020 regulatory definition of “habitat.”

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.

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Increased frequency of severe and extreme weather events associated with climate change could materially impact our facilities, energy sales, and results of operations.

We are unable to predict these events.

However, we perform ongoing assessments of physical risk, including physical climate risk, to our business.

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 and/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.

Regarding federal policies, we continue to monitor the implementation of any final and proposed climate change-related legislation and regulations, including the Infrastructure Investment and Jobs Act, signed into law in November 2021;

the development of the Enhancement and Standardization of Climate-Related Disclosures, proposed by the SEC in March 2022;

the Inflation Reduction Act (“IRA”), signed into law in August 2022;

and the EPA’s methane regulations for the oil and natural gas industry, but we cannot predict their impact on our business at this time.

We have identified potential opportunities associated with the Infrastructure Investment and Jobs Act and the IRA and are evaluating how they may align with our strategy going forward.

The energy-related provisions of the Infrastructure Investment and Jobs Act include new federal funding for power grid infrastructure and resiliency investments, new and existing energy efficiency and weatherization programs, electric vehicle infrastructure for public chargers and additional Low Income Home Energy Assistance Program funding over the next five years.

The IRA contains climate and energy provisions, including funding to decarbonize the electric sector.

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.

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 Station.

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.

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however, supplier competition continues to develop.

Illinois Basin (ILB)

The coal industry underwent a significant transformation in the early 1990s, as greater environmental accountability was established in the electric utility industry.

Through the U.S.

CAA, acceptable baseline levels were established for the release of sulfur dioxide in power plant emissions.

In order to comply with the new law, most utilities switched fuel consumption to low-sulfur coal, thereby stripping the ILB of over 50 million tons of annual coal demand.

This strategy continued until mid-2000 when a shortage of low-sulfur coal drove up prices.

This price increase combined with the assurance from the U.S.

government that the utility industry would be able to recoup their costs to install scrubbers caused utilities to begin investing in scrubbers on a large scale.

With scrubbers, the ILB re-opened as a significant fuel source for utilities and has enabled them to burn lower-cost high sulfur coal.

The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana, and western Kentucky.

The ILB is centrally located between four of the largest 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.

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.

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.

Coal Industry

The major coal production basins in the U.S.

include ILB, Central Appalachia (“CAPP”), Northern Appalachia (“NAPP”), Powder River Basin (“PRB”), and the Western Bituminous region (“WB”).

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.

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The WB includes western Colorado, eastern Utah, and southern Wyoming.

Hallador Energy Company (“Hallador”), through its wholly-owned subsidiary Sunrise Coal, LLC (“Sunrise Coal”), mines coal exclusively in the ILB.

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).

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.

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The pillars can constitute up to 50% of the total coal in a seam.

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:

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.

coal industry is highly competitive, with numerous producers selling into all markets that use coal.

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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 entirely union-free.

At our power plant, our operator, Consolidated Asset Management Services (CAMS) employs represented workers.

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 Hallador’s wholly owned subsidiary, Sunrise Coal.

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.

While every precaution is taken to prevent mine emergencies, Sunrise Coal has its own private mine rescue team.

This team is trained and ready to manage emergency situations at a Sunrise Coal facility, but also ready and available to assist other mine rescue teams.

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.

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All continuing education requirements and training are completely paid for by the company and tuition reimbursement programs are available to every employee companywide.

Recent Regulatory Developments from the Presidential Transition

On January 20, 2025, Donald J.

Trump was inaugurated as the 47 th President of the United States of America.

Since President Trump’s inauguration, the new Administration has rescinded various Biden Administration Executive Orders and has issued new Executive Orders and taken other related executive actions, which may impact the market for our coal products or our electric power generating operations.

These new Executive Orders reflect policy objectives such as promoting the development of domestic energy resources, expedited permitting for energy projects, potential withdrawal from international climate change agreements, and the potential reconsideration of US EPA’s 2009 endangerment finding for greenhouse gas emissions under the Clean Air Act, among other issues.

Many of these policy objectives will require further rulemaking actions or other formal steps before they would become law.

In addition, the new Administration has taken actions to reduce the number of federal employees and to eliminate certain federal agencies or reduce their authority.

As a result, there is significant uncertainty regarding whether or how regulations and the agencies that administer and enforce these regulations may change as a result of the actions taken to date and possible future actions by the new Administration.

Additionally, there may be litigation over such regulatory changes, and if public enforcement decreases as a result of such changes, private litigation over environmental matters may increase.

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

Our corporate office, as well as Sunrise Coal and Hallador Power’s corporate office, is located at 1183 East Canvasback Drive, Terre Haute, Indiana, 47802.

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.

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to these reports are available, free of charge, on our website at www.halladorenergy.com under the “Investor Relations” section, as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the SEC at www.sec.gov.

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.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business