EDGAR 10-K Filing

Company CIK: 788965
Filing Year: 2025
Filename: 788965_10-K_2025_0001558370-25-003141.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS.
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. 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.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our business.
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:
● employee health and safety;
● mine permits and other licensing requirements;
● air quality standards and 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;
● storage and handling of explosives;
● wetlands protection;
● surface subsidence from underground mining; and
● 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. 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 have accrued for the present value of the estimated cost of asset retirement obligations, power plant closing, and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations, power plant closing and mine closing costs are based upon permit requirements and the estimated costs and timing of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.
Electric Power Generation Permits and Approvals
Numerous governmental permits or approvals are also required for electric power generation operations, including coal-fired power plants such as Merom Generating Station. 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. Meeting all requirements imposed to address these matters may be costly and may delay or prevent commencement or continuation of power generation operations.
The permitting process for electric power generation operations can extend over many years as a result of necessary permit renewals and those permitting decisions can be subject to administrative and judicial challenge, including by the public. We cannot assure you that we will not experience difficulty or delays in obtaining electric power generation permits in the future or that a current permit will not be revoked.
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. 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.
Mining Permits and Approvals
Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health, and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use, and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and may delay or prevent commencement or continuation of mining operations.
The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.
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. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. 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; and
● 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.
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 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. 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. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis.
Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the third-party violator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and having any permits revoked that were issued after the time of the violations or after the time civil penalties or reclamation fees became due. We are not aware of any currently pending or asserted claims against us relating to the “ownership” or “control” theories discussed above. However, we cannot assure you that such claims will not be asserted in the future.
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. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for our competitors and us to secure new surety bonds without posting collateral, and in some cases, it is unclear what level of collateral will be required. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain or inability to acquire surety bonds that are required by federal and state laws would have a material adverse effect on our ability to produce coal and conduct electric power generating operations, which could affect our profitability and cash flow.
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 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. 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 EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric power generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. 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”). 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. The U.S. 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. 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.
● The EPA’s regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas, and international parks. Under the program, states are required to develop SIPs to improve visibility. 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”). 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.
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 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. The rule divides coal-fired power plants into three categories. Those that will cease operation by 2032 are exempt from the rule. Those operating between 2032 and 2039 will be required to achieve emissions reductions equivalent to co-firing 40 percent by volume natural gas. 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.
Future, additional regulation of GHG emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA. 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”). 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. 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. 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.
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.
Water Discharge
The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting. 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. 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. 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.
In order for us to conduct certain activities, we may need to obtain a permit for the discharge of fill material from the U.S. Army Corps of Engineers (“Corps of Engineers”) and/or a discharge permit from the state regulatory authority under the state counterpart to the CWA. Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments. The CWA authorizes the EPA to review 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. 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. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDL-related allocations or any changes to antidegradation policies for streams near our coal mines or electric power generating operations could require more costly water treatment and could adversely affect our coal production or electric power generation operations.
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. 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.
On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source, such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases relevant to determination of “functional equivalent” are ongoing in various jurisdictions. It is too early to determine whether the Supreme Court decision or the result of litigation to “functional equivalent” may have a material impact on our business, financial condition, or results of operations.
In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant selenium in fresh water. NPDES permits may be updated to include selenium water quality-based effluent limits based on a site-specific evaluation process, which includes determining if there is a reasonable potential to exceed the revised final selenium water quality standards for the specific receiving water body utilizing actual and/or project discharge information for the generating facilities. As a result, it is not yet possible to predict the total impacts of this final rule at this time, including any challenges to 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. 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.
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. If additional capital expenditures became necessary in the future, they could be material.
Hazardous Substances and Wastes
The Federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), otherwise known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages. Some products used in coal mining operations and electric power generating operations generate waste containing hazardous substances. We are currently unaware of any material liability under CERCLA or analogous state laws associated with the release or disposal of hazardous substances from our past or present mine sites or electric power generating operations.
The Federal Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous and non-hazardous wastes. 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. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.
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. 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.
Endangered Species Act
The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related activities. 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.”
If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered, or to re-designate a species from threatened to endangered, we could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.
Other Environmental, Health and Safety Regulation
In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground storage tanks in which we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulations. In addition, our use of explosives is subject to the Federal Safe Explosives Act. We are also required to comply with the Federal Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition, or results of operations.
Climate Change Issues
Physical Climate Risks. Increased frequency of severe and extreme weather events associated with climate change could materially impact our facilities, energy sales, and results of operations. 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.
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.
Suppliers
The main types of goods we purchase for our mining operations are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, electricity, fuel, and tires. For our electric operations, we purchase coal, limestone, fuel oil, anhydrous ammonia, and other chemicals and items necessary to operate Merom Station. Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of electricity. The supplier base providing mining materials has been relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop.
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.
U.S. 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”). CAPP includes eastern Kentucky, Tennessee, Virginia, and southern West Virginia. NAPP includes Maryland, Ohio, Pennsylvania, and northern West Virginia. The PRB is located in northeastern Wyoming and southeastern Montana. The WB includes western Colorado, eastern Utah, and southern Wyoming. Hallador Energy Company (“Hallador”), through its wholly-owned subsidiary Sunrise Coal, LLC (“Sunrise Coal”), mines coal exclusively in the ILB.
Coal type varies by basin. Heat value and sulfur content are important quality characteristics and determine the end-use for each coal type.
Coal in the U.S. is mined through surface and underground mining methods. The primary underground mining techniques are longwall mining and continuous (room-and-pillar) mining. The geological conditions dictate which technique to use. Our mines utilize the continuous mining technique. In continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment cuts the coal from the mining face. Generally, openings are driven 20’ wide, and the pillars are rectangular in shape measuring 40’x 40’. As mining advances, a grid-like pattern of entries and pillars is formed. Roof bolts are used to secure the roof of the mine. Battery cars move the coal to the conveyor belt for transport to the surface. The pillars can constitute up to 50% of the total coal in a seam.
The U.S. coal industry is highly competitive, with numerous producers selling into all markets that use coal. We compete against large producers such as Peabody Energy Corporation (NYSE: BTU), Alliance Resource Partners (Nasdaq: ARLP), and other private producers.
Human Capital
As of December 31, 2024, Hallador and its subsidiaries employed 615 full-time employees and temporary miners, 582 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. 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. 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. 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 2021 we were at or below the national averages in all three categories. For more information about citations or orders for violations of standards under the FMSHA, as amended by the Miner Act, please see our Exhibit 95 to this Annual Report on Form 10-K.
While other companies have moved to high deductible health plans, Hallador is committed to providing comprehensive affordable health insurance with low-cost deductibles and co-pays to take care of our employees and their families. We believe in decreasing the barriers to healthcare, so employees and their dependents do not have to delay care. Our employees and their families also have access to a private full-time health and wellness clinic, with free medications, no cost diagnostics, and a wellness coach.
Beyond investing in the safety and health of its employees, Hallador invests in educational opportunities for its employees. All continuing education requirements and training are completely paid for by the company and tuition reimbursement programs are available to every employee companywide.
Recent Regulatory Developments from the Presidential Transition
On January 20, 2025, Donald J. Trump was inaugurated as the 47th 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.
Other
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. 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.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
Risks Related to our Business
Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets could have material adverse impacts on our business and financial condition that we currently cannot predict.
Weakness in global economic conditions or economic conditions in any of the industries we serve or in the financial markets could materially adversely affect our business and financial condition. For example:
● the demand for electricity in the U.S. and globally may decline if economic conditions deteriorate, which may negatively impact the revenues, margins, and profitability of our business;
● any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and
● our future ability to access the capital markets may be restricted as a result of future economic conditions, which could materially impact our ability to grow our business, including development of our coal reserves.
The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing contracts or enter into new long-term contracts for electric power, capacity or coal.
In 2024, a significant portion of our electric power, capacity and coal sales were under contracts having a term greater than one year, which we refer to as long-term contracts. These contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts. From time to time, industry conditions could make it more difficult for us to enter into long-term contracts with our customers, and if supply exceeds demand in the electric power, capacity and coal industries, our customers may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject an increasing portion of our revenue stream to the increased volatility of the spot market.
Our financial performance may be impacted by price fluctuations in the electric power markets, as well as fluctuations in coal markets and other market factors that are beyond the Company’s control.
Market prices for power, capacity, coal and other ancillary services are unpredictable and tend to fluctuate substantially. Electric power generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. While we currently sell a significant portion of our electric power pursuant to long-term contracts (where we may be less susceptible to day-to-day fluctuations), we also sell a material amount of power in the competitive wholesale market including through MISO. A significant portion of the electricity we sell is used by residential and commercial customers for heating and air conditioning Long and short-term power prices may fluctuate substantially due to factors outside of the Company’s control, including:
● changes in generation capacity in the Company’s markets, including the addition of new supplies of power as a result of the development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to state subsidies, retirement of existing plants or addition of new transmission capacity;
● electric supply disruptions, including plant outages and transmission disruptions;
● changes in power transmission infrastructure;
● transportation capacity constraints or inefficiencies;
● weather conditions, including extreme weather conditions and seasonal fluctuations, including the effects of climate change;
● changes in commodity prices and the supply and available inventory of commodities, including but not limited to natural gas, coal and oil;
● changes in the demand for power, or in patterns of power usage, including the potential development of demand-side management tools and practices, distributed generation, and more efficient end-use technologies;
● development of new fuels, new technologies and new forms of competition for the production of power;
● economic and political conditions;
● changes in law, including judicial decisions, environmental regulations and environmental legislation; and
● federal, state and provincial power regulations and legislation, and regulations and actions of the ISO and RTOs.
Such factors and the associated fluctuations in power prices have affected the Company’s profitability in the past and are expected to continue to do so in the future.
Some of our long-term sales contracts contain provisions allowing for the termination of the contract or the suspension of purchases by customers or, in certain cases, the renegotiation of prices.
Several of our long-term electric power, capacity and coal contracts contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain events that are beyond the customer’s reasonable control. Such events could include force majeure, labor disputes, mechanical malfunctions and changes in government regulations, including, in the case of our coal contracts, changes in environmental regulations rendering use of our coal inconsistent with the customer’s environmental compliance strategies. Additionally, most of our long-term coal contracts contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments or termination of the contracts. In the event of early termination of any of our long-term contracts, if we are unable to enter into new contracts or similar terms, our business, financial condition and results of operations could be adversely affected.
Further, long-term coal sales contracts may contain provisions that allow for the purchase price to be renegotiated at periodic intervals, however, we had no coal contracts with price reopeners at December 31, 2024. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term contracts may provide only limited protection during adverse market conditions. In some circumstances, failure of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.
We depend on a few customers for a significant portion of our revenues, and the loss of one or more significant customers could affect our ability to maintain the sales volume and price of our products.
In our Electric Operations, a material portion of our 2024 revenue was derived from a power purchase agreement with Hoosier (“PPA”), which we entered into as part of our acquisition of Hoosier Energy’s Merom Generation Station (“Merom”) in 2022. The PPA (as amended in August 2023) expires at the end of 2028. While we have subsequently added additional electric power customers and purchasers of accredited capacity, the loss of one or more of these material customers could have a material adverse effect on our business, financial condition and results of operations.
During 2024, we derived 89% of our delivered energy and 88% of our capacity sales revenue from three and four customers, respectively, each of which representing at least 10% of sales revenue. Additionally, we derived 96% of our third-party coal sales from four customers, each representing at least 10% of coal sales. If in the future we lose any of these customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition and results of operations.
Our recent efforts to sell our accredited capacity to long-term customers may not be successful.
In light of the fact that the Company believes it holds a considerable portion of the remaining unsold accredited capacity in MISO Zone 6, covering Indiana and parts of western Kentucky, the Company has recently focused its efforts on entering into one or more long-term contracts for the sale of its energy and capacity to large load end user(s) through a utility or cooperative, including through a data center targeted Request for Proposal (RFP) undertaken in 2024. This RFP resulted in a wholly owned subsidiary, Hallador Power Company, LLC, executing a Conversion Transaction Commitment Agreement with a leading global data center developer on January 2, 2025. The transaction contemplated thereby remains subject to a number of conditions, including negotiation of definitive documentation and the selection of a utility partner and there can be no assurance that definitive agreements will be entered into or that the proposed transaction will be consummated on the terms or timeframe currently contemplated, or at all. Failure to consummate the transaction contemplated by the Conversion Transaction Commitment Agreement and/or any other similar agreement(s) contemplated by the Company’s recent RFP efforts may have a material adverse effect on our business, financial condition and results of operations.
Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.
Our ability to receive payment for electric power, capacity and coal sold and delivered depends on the continued creditworthiness of our customers. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease, and we may have to reduce production at our mines until our customer’s contractual obligations are honored.
Contractors that we use to provide employees at our power plant may experience work stoppages, slowdowns, lockouts or other labor disputes.
At Merom, our operator, Consolidated Asset Management Services (“CAMS”), employs represented workers. While these workers are not Hallador Power employees, work stoppages, slowdowns, lockouts or other labor disputes within the CAMS workforce could adversely affect and disrupt our productivity and operations at the plant.
In our Coal Operations, although none of our coal employees are members of unions, our workforce may not remain union-free in the future.
None of our employees are represented under collective bargaining agreements. However, all of our workforce may not remain union-free in the future, and legislative, regulatory or other governmental action could make it more difficult to remain union-free. If some or all of our currently union-free operations were to become unionized, it could adversely
affect our productivity and increase the risk of work stoppages at our mining complexes. In addition, even if we remain union-free, our operations could still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.
The operation and maintenance of the Merom facilities or future investment in the Merom facilities are subject to operational risks that could adversely affect our financial position, results of operations and cash flows.
In October 2022, the Company, through its subsidiary Hallador Power, completed its acquisition of Merom, our one Gigawatt Generating Station located in Sullivan County, Indiana pursuant to an Asset Purchase Agreement (“APA”) with Hoosier Energy. The operation and maintenance of generating facilities like Merom involves many risks, including the performance by key contracted suppliers and maintenance providers; increases in the costs for or limited availability of key supplies, labor and services; breakdown or failure of facilities; curtailment of facilities by counterparties; or the impact of unusual, adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. The Merom facilities contain older generating equipment, which even if maintained in accordance with good engineering practices, may require additional capital expenditures to continue operating at peak efficiency. From time to time, the Merom facilities may experience transformer failures that may cause one or more of its units to be offline for an extended period of time. We may also be subject to costs associated with any unexpected failure to produce and deliver power, including failure caused by breakdown or forced outage, as well as the repair of damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events. Additionally, supply chain shortages or delays on key operating components, including but not limited to, transformers, boiler equipment and chemicals or catalysts could materially and adversely impact our operations and reduce revenues or expose the company to significant cover damages related to longer term contracts. In connection with the APA, the Company assumed certain decommissioning costs and environmental responsibilities. In the event these assumed costs and responsibilities exceed the Company’s estimates, the Company may incur additional liabilities that could have an adverse effect on the Company’s business, financial results and prospects.
Completion of growth projects and future expansion could require significant amounts of financing that may not be available to us on acceptable terms, or at all.
We plan to fund capital expenditures for our current growth projects with existing cash balances, future cash flows from operations, borrowings under credit facilities and cash provided from the issuance of debt or equity. Under our outstanding Form S-3 “universal shelf” registration statement, we have the ability, subject to market conditions, to access the debt and equity capital markets as needed, including through the use of our outstanding At-the -Market (“ATM”) offering program. If we raise additional funds by issuing equity securities under our ATM program or otherwise, our stockholders may experience dilution. At times, weakness in the energy sector in general and coal, in particular, has significantly impacted access to the debt and equity capital markets. Accordingly, our funding plans may be negatively impacted by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, we may be unable to refinance our current debt obligations when they expire or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet their funding obligations. Furthermore, additional growth projects and expansion opportunities may develop in the future that could also require significant amounts of financing that may not be available to us on acceptable terms or in the amounts we expect, or at all.
Various factors could adversely impact the debt and equity capital markets as well as our credit ratings or our ability to remain in compliance with the financial covenants under our then current debt agreements, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth and future expansions as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.
Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.
Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, could be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third-parties, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we could be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.
We may not recover our investments in our power, mining, and other assets, which may require us to recognize impairment charges related to those assets.
The value of our assets has from time to time been adversely affected by numerous uncertain factors, some of which are beyond our control, including, but not limited to unfavorable changes in the economic environments in which we operate, lower-than-expected coal pricing, technical and geological operating difficulties, an inability to economically extract our coal reserves and unanticipated increases in operating costs. During the fourth quarter of 2024, we completed our annual impairment analysis, which was based upon the finalized operating plans of the Company, market driven pricing and cost trends. As part of that analysis, the Company determined the carrying amount of its long-lived assets were not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in the fourth quarter of 2024. See “Note 19 - Impairment of Coal Properties” to the Consolidated Finance Statements in this Form 10-K for further information on the impairment analysis. The factors noted above may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of coal operations.
In the future, as investments in Merom become more significant, the value of those assets could be adversely affected by numerous uncertain factors, some of which are beyond our control, including, but not limited to unfavorable changes in the economic environments in which we operate, environmental, litigation, weather, and regulatory and/or legal changes. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of power operations.
If we are unable to comply with the covenants contained in our credit agreement, the lenders could declare all amounts outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and operations.
As disclosed in “Note 4 - Bank Debt” to our consolidated financial statements, on September 27, 2024, we executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), in which we adjusted existing covenants and added new ones: (i) waived the Company’s Leverage Ratio requirement for the third and fourth quarters of 2024, increased the threshold to 5.50 to 1.00 for the first quarter of 2025, and decreased the threshold back to 2.25 to 1.00 for each fiscal quarter thereafter, (ii) the Debt Service Coverage Ratio requirement (1.25 to 1.00) was waived from third quarter of 2024 through the first quarter of 2025, (iii) added a maximum First Lien Leverage Ratio for the first quarter of 2025, calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 3.50 to 1.00; (iv) added a minimum liquidity requirement of $10.0 million, beginning on the First Amendment execution date and ending when the second quarter of 2025 compliance certificate is received, and (v) added a minimum quarterly EBITDA requirement, as defined in the First Amendment, of $5.0 million for the third quarter of 2024 through the first quarter of 2025.
As of December 31, 2024, our liquidity of $37.8 million and quarterly EBITDA of $6.2 million were in compliance with the requirements of the Credit Agreement.
Our ability to comply with the covenants in our credit agreement may be affected by changes in economic or business conditions or other events that are beyond our control. If we fail to comply with these covenants, we may be in default under our credit agreement, which may entitle the lenders to accelerate the debt obligations. In order to avoid defaulting on our indebtedness, we may be required to take actions such as reducing or delaying capital expenditures, reducing or eliminating dividends or share repurchases, selling assets, restructuring or refinancing all or part of our existing debt, or seeking additional equity capital, any of which may not be available on terms that are favorable to us, if at all. In the event of an event of default under our credit agreement, the lenders could declare all amounts outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and operations.
Our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.
As of December 31, 2024, our funded bank debt was $44.0 million and we held letters of credit totaling $19.4 million. Our leverage may:
● adversely affect our ability to finance future operations and capital needs;
● limit our ability to pursue acquisitions and other business opportunities; and
● make our results of operations more susceptible to adverse economic or operating conditions.
Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions, and capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
If our financial condition deteriorates, certain credit assurance provisions in our power contracts could require additional collateral.
Certain of our power contracts contain credit assurance provisions tied to our financial condition. Should our financial condition deteriorate, these provisions may require substantial collateral that may have a materially adverse effect on our financial condition.
Investor and lender focus on ESG matters may negatively impact our business, financial results, and stock price.
Companies across all industries, including companies in the fossil-fuel industry, have faced increased scrutiny from stakeholders related to their ESG practices. Companies that do not adapt or comply with investor or stakeholder expectations and standards or are perceived to have not responded appropriately to ESG issues, regardless of any legal requirement to do so, may suffer reputational damage and the business, financial condition, and stock price of such companies could be materially and adversely affected. Several advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These activities include increasing attention to and demands for action related to climate change, promoting the use of substitutes to fossil-fuel products, encouraging the divestment of fossil-fuel equities, and pressuring lenders to limit funding to companies engaged in the extraction of fossil-fuel reserves. These activities could increase costs, impact our supply chain, reduce demand for our coal, reduce our profits, increase the potential for investigations and litigation, impair our brand, limit our choices for lenders, insurance providers and business partners, and have negative impacts on our stock price and access to capital markets.
In addition, certain organizations that provide corporate governance and other corporate risk information to investors have developed scores and ratings to evaluate companies and investment funds based upon ESG or “sustainability” metrics. Currently, there are no universal standards for such scores or ratings, but consideration of sustainability evaluations is becoming more broadly accepted by investors. Indeed, many investment funds focus on positive ESG business practices and sustainability scores when making investments, whereas other funds may use certain ESG criteria to “screen” certain sectors, such as coal or fossil fuels more generally, out of their investments. In addition, investors,
particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance or sell their interests in the company, particularly if its ESG performance does not improve. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Companies in the energy industry, and in particular those focused on coal, natural gas, or oil extraction, often do not score as well under ESG assessments compared to companies in other industries. Consequently, a low ESG or sustainability score could result in our securities being excluded from the portfolios of certain investment funds and investors, restricting our access to capital to fund our continuing operations and growth opportunities. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
Public statements with respect to ESG matters, such as emission reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. Certain non-governmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. Similarly, we could be criticized by ESG detractors for the scope and nature of any ESG policies or initiatives we implement. We could also be subjected to negative responses by governmental actors, such as state legislation, retaliatory legislative treatment or litigation by state or federal agencies, or face negative publicity campaigns that could adversely affect our reputation, business, financial performance and growth. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further ESG-related focus and scrutiny.
Enhanced data privacy and data protection laws and regulations or any non-compliance with such laws and regulations, could adversely affect our business and financial results.
Consistent with the trend established by passage of the General Data Protection Regulation (the “GDPR”), the development and evolving nature of domestic and international privacy regulation and enforcement could impact and potentially limit how Hallador processes personal information. For example, California residents have certain privacy rights (including the right to limit the use and disclosure of sensitive personal information, and the right to request that a business delete personal information collected about them, among other rights), established by the California Consumer Privacy Act (“CCPA”) and enforced by a state privacy regulator, resulting in more scrutiny of business practices and disclosures. Additional states including Virginia, Utah, Connecticut, Colorado, and Nevada have similarly adopted enhanced data privacy legislation patterned after the standards set forth by CCPA, including broader data access rights, with some states even requiring businesses to perform data protection assessments for certain processing activities. In 2025, state privacy laws go into effect in a number of states, including Delaware, Maryland, Minnesota, Nebraska, and New Jersey, among others.
As new laws and regulations are enacted by legislators or adopted by regulators, requiring businesses to implement processes to enable customer access to their data and enhanced data protection and management standards, we cannot forecast the impact that they may have on the Company’s business. Any non-compliance with laws may result in proceedings or actions against the Company by as many as 35 governmental entities or individuals. Moreover, any inquiries or investigations, government penalties or sanctions, or civil actions by individuals may be costly to comply with, resulting in negative publicity, increased operating costs, significant management time and attention, and may lead to remedies that harm the business, including fines, demands or orders that existing business practices be modified or terminated.
Risks Related to our Industry
Substantial or extended volatility in coal prices could negatively impact our results of operations in both our Electric Operations and Coal Operations segments.
Our results of operations are primarily dependent upon the price we pay for our coal in the case of our Electric Operations, or the prices we receive for our coal in our Coal Operations, as well as our ability to improve productivity and control costs. These prices depend upon factors beyond our control, including:
● the supply of and demand for domestic and foreign coal;
● weather conditions and patterns that affect demand for or our ability to produce coal;
● the proximity to and capacity of transportation facilities;
● supply chain and cost of raw materials for coal operations;
● competition from other coal suppliers;
● domestic and foreign governmental regulations and taxes;
● the price and availability of alternative fuels;
● the effect of worldwide energy consumption, including the impact of technological advances on energy consumption;
● overall domestic and global economic conditions;
● international developments impacting supply of coal; and
● the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits.
Any adverse change in these factors could result in weaker demand and lower prices for our products. With respect to our Coal Operations, a substantial or extended decline in coal prices could materially and adversely affect us by decreasing our revenues to the extent we are not protected by the terms of existing coal supply agreements (although the adverse impact of a decline in coal prices may in some cases be offset by lower coal prices we pay in our Electric Operations).
Competition within the coal industry could adversely affect our financial results.
In our Coal Operations, we compete with other coal producers for domestic coal sales in various regions of the U.S. The most important factors on which we compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics, contract flexibility (e.g., volume optionality and multiple supply sources) and reliability of supply. In addition, deregulation within the coal industry, including as a result of actions taken by the new Presidential Administration, may encourage new market entrants and could increase the number of competitors we face. Some competitors could have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships with specific transportation providers. The competition among coal producers could impact our ability to retain or attract customers and could adversely impact our revenues and cash from operations. In our Electric Operations, similar risks apply with respect to our ability to purchase coal on attractive terms relative to other competitors in the market.
Changes in taxes or tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.
We pay certain taxes and fees related to our operations. Congress or state legislatures may seek to increase these taxes and fees that relate specifically to the coal industry. We cannot predict further developments, and such increases could have a material adverse effect on our results of operations, financial position, and cash flows.
Further, there is uncertainty surrounding tariffs and international trade relations, and it is difficult for us to predict future trade measures and the impact they will have on our business and operations. In early 2025, the new U.S. Presidential
Administration threatened and imposed tariffs on imports from various countries. In response, some of these countries threatened or imposed tariffs on imports from the U.S. How long current tariffs will remain in place, and whether the new Administration will enact the threatened tariffs or impose entirely new ones is uncertain.
These newly enacted tariffs, additional new tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows. In response to the tariffs imposed by the U.S., the European Union, Canada, Mexico and China have imposed tariffs on U.S. goods and services. The new tariffs, along with any additional tariffs or trade restrictions that may be implemented by the U.S. or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal coal, limits on trade with the U.S. or other potentially adverse economic outcomes. While tariffs and other retaliatory trade measures imposed by other countries on U.S. goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position and cash flows and could reduce our revenues and cash available for distribution.
Changes in consumption patterns by utilities regarding the use of coal, including plans by utilities to shut down or move away from coal-fired generation, have affected our ability to sell the coal we produce.
The domestic electric utility industry accounts for the vast majority of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled generation has the potential to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators.
Future environmental regulation of GHG emissions also could accelerate the use by utilities of fuels other than coal. In addition, federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the U.S. A decrease in coal consumption by the domestic electric utility industry could adversely affect the demand for or the price of coal, which could negatively impact our results of operations and reduce our cash from operations.
Other factors, such as efficiency improvements associated with technologies powered by electricity have slowed electricity demand growth and could contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions or a prolonged economic recession, could have a material adverse effect on the demand for coal and our business over the long term.
Extensive environmental laws and regulations affect coal consumers and have corresponding effects on the demand for coal as a fuel source.
Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air and pollutants in wastewater from coal-fired electric power plants, which are the ultimate consumers of much of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations could require further emission reductions and associated emission control expenditures. These laws and regulations could affect demand and prices for coal. There is also continuing pressure on federal and state regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as CSAPR, MATS, 316(a) and (b) rules, CCR rules, and ELGs have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the U.S. These rules could also lead to material capital expenditures for our electric generating operations.
Our operations are subject to a series of risks resulting from climate change.
Combustion of fossil fuels, such as the coal we produce in our mining operations and the energy we produce in our electric operations, results in the emission of carbon dioxide into the atmosphere. Concerns about the environmental impacts of such emissions have resulted in a series of regulatory, political, litigation, and financial risks for our business. Global climate issues continue to attract public and scientific attention. Many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere could produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods, and other climatic events. Increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions due to fossil fuels.
Following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain sources in the U.S., or constrain the emissions of power plants (though such emissions restraints have been subject to challenge).
Separately, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. 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, the U.S. rejoined the Agreement in 2021 and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below levels 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”). 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. Although no legally binding commitment or timeline to phase out or phase down all fossil fuels was made, there can be no guarantees that countries will not seek to implement such a binding phase out in the future. The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon us and our operators’ operations.
Governmental, scientific, and public concern over climate change has also resulted in increased political risks. For example, in January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. While the Biden executive order has now been rescinded by the new Trump Administration, the political dynamic could change yet again in the future. Other actions that may be pursued include restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities or the promulgation of a carbon tax or cap and trade program. Further, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories, regional GHG cap and trade programs, or the establishment of renewable energy requirements for utilities. Depending on the particular program, we or our customers could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Litigation risks are also increasing.
Additionally, on March 6, 2024, the SEC adopted new rules relating to the disclosure of a range of climate-related data risks and opportunities, including financial impacts, physical and transition risks, related governance and strategy and GHG emissions, for certain public companies. We are currently assessing this rule but at this time we cannot predict the ultimate impact of the rule on our business or those of our customers. As a result of these final rules, we or our customers could incur increased costs related to the assessment and disclosure of climate-related risks and certain emissions metrics. In addition, enhanced climate disclosure requirements could accelerate the trend of certain
stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.
Apart from governmental regulation, there are also increasing financial risks for fossil-fuel producers as stakeholders of fossil-fuel energy companies may elect in the future to shift some or all of their support into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil-fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil-fuel sector. In late 2020, the Federal Reserve announced it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. However, in January 2025 the Board of Governors of the US Federal Reserve System and Federal Deposit Insurance Corporation announced plans to withdrawing as members of the NGFS. Although we cannot predict the effects of these actions, such limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect our coal mining operations.
The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from fossil-fuel companies could result in increased costs of compliance or costs of consuming, and thereby reduce demand for coal, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks could result in either us restricting or canceling mining activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-fossil-fuel sources, including alternative energy sources, could cause prices and sales of our coal to materially decline and could cause our costs to increase and adversely affect our revenues and results of operations.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our operations. Such physical risks may result in damage to our facilities or otherwise adversely impact operations which could decrease our production. We may not have insurance to cover these risks and the consequences for our operations could have a negative impact on the costs and revenues from operations.
We or our customers could be subject to risks related to the alleged effects of climate change.
Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by state and local governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, and oil & gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Separately, litigation has been brought against certain fossil-fuel companies alleging that they have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or consumers. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in liabilities to us. In addition, government inspectors, under certain circumstances, have the ability to order our operations to be shut down based on environmental considerations.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine drainage.” Additionally, our electric power generating operations result in air emissions, wastewater effluent, and the generation of coal combustion residuals. We could become subject to claims for toxic torts, natural resource damages and other damages, as well as for the investigation and clean-up of soil, surface water, groundwater and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or for the entire share. In addition, government inspectors, under certain circumstances, may have the ability to order our operations to be shut down based on a perceived or actual violation of regulations concerning hazardous substances and other matters related to environmental protection.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.
Litigation resulting from disputes with our customers could result in substantial costs, liabilities, and loss of revenues.
From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract. Disputes could occur in the future, and we may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition and results of operations.
Our profitability in our Coal Operations could decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.
Our mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability. These conditions and events include, among others:
● mining and processing equipment failures and unexpected maintenance problems;
● unavailability of required equipment;
● prices for fuel, steel, explosives and other supplies;
● fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;
● variations in thickness of the layer, or seam, of coal;
● amounts of overburden, partings, rock and other natural materials;
● weather conditions, such as heavy rains, flooding, ice and other natural events affecting operations, transportation or customers;
● accidental mine water discharges and other geological conditions;
● seismic activities, ground failures, rock bursts or structural cave-ins or slides;
● fires;
● employee injuries or fatalities;
● labor-related interruptions;
● increased reclamation costs;
● inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;
● fluctuations in transportation costs and the availability or reliability of transportation; and
● unexpected operational interruptions due to other factors.
These conditions have the potential to significantly impact our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.
Our inability to obtain commercial insurance at acceptable rates or our failure to adequately reserve for self-insured exposures could increase our expenses and have a negative impact on our business.
We believe that commercial insurance coverage is prudent in certain areas of our business for risk management. Insurance costs could increase substantially in the future and could be affected by natural disasters, fear of terrorism, financial irregularities, cybersecurity breaches and other fraud at publicly traded companies, intervention by the government, an increase in the number of claims received by the carriers, and a decrease in the number of insurance carriers. In addition, the carriers with which we hold our policies could go out of business or be otherwise unable to fulfill their contractual obligations or could disagree with our interpretation of the coverage or the amounts owed. In addition, for certain types or levels of risk, such as risks associated with certain natural disasters or terrorist attacks, we may determine that we cannot obtain commercial insurance at acceptable rates, if at all. Therefore, we may choose to forego or limit our purchase of relevant commercial insurance, choosing instead to self-insure one or more types or levels of risks. If we suffer a substantial loss that is not covered by commercial insurance or our self-insurance reserves, the loss and related expenses could harm our business and operating results. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, environmental activists could try to hamper fossil-fuel companies by other means including pressuring insurance and surety companies into restricting access to certain needed coverages.
Our Electric and Coal Operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.
We are subject to numerous federal, state and local laws and regulations affecting the coal mining industry and the electric generation industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Many of these same risks apply to our electric operations and the operation of a coal-fired generating facility, including impacts on air, surface water, groundwater and the environment. Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations. Complying with these laws and regulations could be costly and time-consuming and could delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations could occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining and electric operations, or indirect impacts that discourage or limit our customers’ use of coal or purchase of coal-fired electricity. Federal and state laws addressing safety practices impose stringent reporting requirements and civil and criminal penalties for violations. Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards. Implementing and complying with these laws and regulations has increased and will continue to increase our operational expense and have an adverse effect on our results of operation and financial position.
Anticipated changes in the U.S. political environment, including those resulting from the change in Presidential Administration and control of Congress, and to regulatory agencies, may result in significant changes to regulatory framework and enforcements.
As a result of the 2024 presidential election, changes in the Presidency and both houses of Congress may result in significant changes in, and have resulted in uncertainty with respect to, legislation, regulation, implementation or repeal of laws and rules related to our industry, our coal products, and our electric power operations. The new Presidential Administration has rescinded various prior Executive Orders and has issued new Executive Orders and taken other related executive actions. Many of these policy changes 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.
Changes to existing policies and rules regarding our industry, including those recently instituted, in addition to anticipated new rule proposals, may result in significant regulatory changes, increased penalties for non-compliance, increased competition, or increased private litigation. We also anticipate that there may be changes in legislative control and legislative priorities. As a result, future legislation may be proposed or passed that may adversely affect our business, operating results and financial condition.
We continually monitor these developments in order to respond to the changing regulatory environment impacting our business. While it is not possible to predict whether and when any such changes will occur, specific proposals discussed during and after the election, including the U.S. withdrawal from the Paris Agreement, could harm our business, operating results and financial condition. If we are slow or unable to adapt to any such changes, our business, operating results and financial condition could be adversely affected.
We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash flow and profitability.
Mining and electricity generation companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with our operations. The permitting rules are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct our operations may not be issued, maintained, or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability.
The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA previously exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia. The EPA’s action was ultimately upheld by a federal court. As a result of these developments, we may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position.
In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process, or even an inability to obtain permits, permit modifications or permit renewals necessary for our operations.
Inflation could result in higher costs and decreased profitability.
The U.S., European Union and other large economies have recently experienced inflation at a rate significantly higher than recent years. Current and future inflationary effects may be driven by, among other things, governmental stimulus and monetary policies, supply chain disruptions and geopolitical instability, including the ongoing military conflict between Ukraine and Russia, and conflicts in the Middle East. This recent inflation has resulted in rising prices, including increases in freight rates, prices for energy and other costs, and has adversely impacted us and may further impact us negatively in the future. Sustained inflation could result in higher costs for transportation, energy, materials, supplies and labor. Our efforts to recover inflation-based cost increases from our customers may be hampered as a result of the structure of our contracts and competitive pressures. Accordingly, substantial inflation may have an adverse
impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the U.S., which could increase our cost of debt borrowing in the future.
Increases in interest rates could adversely affect our business.
Although the Federal Reserve decreased the federal interest rate multiple times in 2024, the rate continues to be elevated and there can be no assurance that the rates will continue to decrease or that it will not be increased in 2025 or beyond. We have exposure to past increases in interest rates and may be affected further in the future. Based on our current variable debt level of $44.0 million as of December 31, 2024, comprised of funds drawn on our outstanding bank debt, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of slightly more than $0.4 million. Any indebtedness we incur in the future may also expose us to increased interest rates, whether as a result of higher fixed rates at the time such a new facility is entered into or because such new indebtedness accrues interest at a variable rate. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or by impairing our ability to supply coal to our customers.
Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers. Our transportation providers could face difficulties in the future that could impair our ability to supply coal to our customers, resulting in decreased revenues. If there are disruptions of the transportation services provided by our primary rail carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.
Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S. Historically, high coal transportation rates from the western coal-producing areas into certain eastern markets limited the use of western coal in those markets. Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers. In the event of further reductions in transportation costs from western coal-producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on our business, financial condition, and results of operations.
States in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.
Political or financial instability, currency fluctuations, the outbreak of pandemics or other illnesses (such as the COVID- 19 pandemic), labor unrest, transport capacity and costs, port security, weather conditions, natural disasters, or other events that could alter or suspend our operations, slow or disrupt port activities, or affect foreign trade are beyond our control and could materially disrupt our ability to participate in the export market for coal sales, which could adversely affect our sales and our results of operations.
We may not be able to successfully grow through future acquisitions.
Our future growth could be limited if we are unable to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses, or properties we acquire. We may not be successful in consummating any
acquisitions and the consequences of undertaking these acquisitions are unknown. Moreover, any acquisition could be dilutive to earnings. Our ability to make acquisitions in the future could require significant amounts of financing that may not be available to us under acceptable terms and may be limited by restrictions under our existing or future debt agreements, competition from other companies for attractive opportunities or the lack of suitable acquisition candidates.
Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.
If we are unable to successfully integrate the companies, businesses, or properties we acquire, our profitability may decline, and we could experience a material adverse effect on our business, financial condition, or results of operations. Expansion and acquisition transactions involve various inherent risks, including:
● uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or safety liabilities) of, expansion and acquisition opportunities;
● the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;
● problems that could arise from the integration of the new operations; and
● unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.
Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.
The estimates of our coal reserves could prove inaccurate and could result in decreased profitability in our Coal Operations.
The estimates of our coal reserves could vary substantially from actual amounts of coal we are able to recover economically. All of the reserves presented in this Annual Report on Form 10-K constitute proven and probable reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which could vary considerably from actual results. These factors and assumptions relate to:
● geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;
● the percentage of coal in the ground ultimately recoverable;
● historical production from the area compared with production from other producing areas;
● the assumed effects of regulation and taxes by governmental agencies;
● future improvements in mining technology; and
● assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs.
For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Any inaccuracy in the estimates of our reserves could result in higher-than-expected costs and decreased profitability in our Coal Operations.
Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the U.S., which could affect the mining operations and cost structures of these areas.
The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those characteristics of the depleting mines. In addition, permitting, licensing and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines.
Unexpected increases in raw material costs could significantly impair our operating profitability.
Our operations are affected by commodity prices. In our Coal Operations, we use significant amounts of steel, petroleum products, and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room-and-pillar method of mining. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and could change unexpectedly. Our Electric Operations are also affected by many of these same commodity prices, including chemicals and catalysts necessary to operate the plant in accordance with environmental and other regulations, fuel oil, limestone, and raw materials used in the manufacture and maintenance of equipment throughout the plant. Inflationary pressures have and could continue to lead to price increases affecting many of the components of our operating expenses such as fuel, steel, other materials and maintenance expense.
There could be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.
Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.
In past years, members of Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. Elimination of those provisions would negatively impact our financial statements and results of operations.
Disruptions in supply chains could significantly impair our operating profitability.
We are dependent upon vendors to supply equipment within our power plant, mining equipment, safety equipment, supplies, and materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demands for their services, we could experience reductions in our production or increased production costs, which could lead to reduced profitability and adversely affect our results of operations.
Inflationary pressures could significantly impair our operating profitability.
Any future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense, healthcare and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduce demand for our electric power, capacity or coal and could adversely affect our results of operations.
The Russian-Ukrainian conflict, and sanctions brought against Russia, as well as other disruptions throughout Europe and the Middle East have caused significant market disruptions that may lead to increased volatility in the price of commodities.
The extent and duration of the military conflict involving Russia and Ukraine, resulting sanctions and future market or supply disruptions in the region are impossible to predict, but could be significant and may have a severe adverse effect on the region. Globally, various governments have banned imports from Russia including commodities such as coal. Additionally, the ongoing conflict between Israel and Hamas, as well as the increasing instability throughout the Middle East, could result in additional disruptions in the commodities markets, supply chain and the global economy. These events have caused volatility in the aforementioned commodity markets. Although we have not experienced any material adverse effect on our results of operations, financial condition or cash flows as a result of the war or conflict or the resulting volatility from such events, such volatility, may significantly affect prices for our coal or the cost of supplies and equipment, as well as the prices of competing sources of energy for our electric power plant customers.
These events, along with trade and monetary sanctions, as well as any escalation of the conflicts and future developments, could significantly affect worldwide market prices and demand for our coal and cause turmoil in the capital markets and generally in the global financial system. Additionally, the geopolitical and macroeconomic consequences of these events and associated sanctions cannot be predicted, but could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for products, causing a reduction in our revenues or an increase in our costs and thereby materially and adversely affecting our results of operations.
The integration of any expansions or acquisitions that we complete will be subject to substantial risks.
Even if we make expansions or acquisitions that we believe will increase our revenue, any expansion acquisition involves potential risks, including, among other things:
● the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, and operating expenses;
● a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
● a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
● the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive is inadequate;
● mistaken assumptions about the overall cost of equity or debt;
● our ability to obtain satisfactory title to the assets we acquire;
● an inability to hire, train or retain qualified personnel to manage and operate the acquired assets; and
● the occurrence of other significant changes, such as impairment of properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.
Natural disasters and other events beyond our control could materially adversely affect us.
Natural disasters or other events outside of our control may cause damage or disruption to our operations, and thus could have a negative effect on us. Our business operations are subject to interruption by natural disasters, fire, power shortages, pandemics and other events beyond our control. This may result in delivery delays, malfunctioning of
facilities or shutdown of logistic points. Such events could make it difficult or impossible for us to deliver our products and services to our customers and could decrease demand for our services. We could not assure you that the production facilities and logistic points will always operate normally in the future.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS. None.

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ITEM 2. PROPERTIES
ITEM 2. PROPERTIES.
See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of the Merom Power Plant and our mines.

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS.
The Company is subject to various legal proceedings and claims that arise in the ordinary course of business, including, but not limited to, environmental matters, contractual disputes, regulatory issues, personal injury, and employment claims. As of the filing date of this report, the Company does not have any active lawsuits or claims which are deemed material, but should facts or circumstances change, some or all of these alleged claims could have a material impact on the Company’s financial results, results of operations and/or cash flows.
The Company accrues liabilities for legal matters when it is probable that a liability has been incurred and the amount can be reasonably estimated. While the Company believes that it has made appropriate provisions for all known legal matters, the outcome of legal proceedings is inherently uncertain, and there can be no assurance that the resolution of such matters will not have a material adverse effect on the Company's financial position, results of operations, or cash flows.
Subsequent to the end of the fourth quarter, the Company reached an agreement in principle to resolve a putative class action related to certain of its employment practices for an amount not material to its financial results. The liability related to this settlement was accrued during the fourth quarter, when settlement negotiations began. The resolution has not yet been finalized, but the Company expects the matter to be closed during the first half of 2025. See “Note 22 - Contingencies” to our Consolidated Financial Statements.
The Company will continue to monitor all proceedings and will update shareholders as necessary, in accordance with applicable legal and regulatory requirements.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES.
Safety is a core value for us and our subsidiaries. As such, we have dedicated a great deal of time, energy, and resources to creating a culture of safety.
See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Stock Price Information
Our common stock trades on the NASDAQ Capital Market under the symbol HNRG, and 40.9% is held by our officers, directors, and their affiliates.
On March 10, 2025, we had 193 shareholders of record of our common stock; this number does not include the shareholders holding stock in “street name.” We estimate we have over 5,000 street name holders.
Equity Compensation Plan Information
See “Note 8 - Stock Compensation Plans” to our consolidated financial statements.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. [RESERVED]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Our consolidated financial statements should be read in conjunction with this discussion. The following analysis includes a discussion of metrics on a per mega-watt hour (MWh) and per ton and basis as derived from the consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.
OVERVIEW
Hallador Energy Company (the “Company” or “Hallador”) is an energy company operating in the state of Indiana. Our wholly owned subsidiary Hallador Power, operates our Merom Power Plant ("Merom"), a one gigawatt (“GW”) power plant located in Sullivan County, Indiana. Merom is located in the Midcontinent Independent System Operator’s ("MISO") footprint.
We also mine coal in the State of Indiana through our wholly-owned subsidiary Sunrise Coal, LLC (“Sunrise”), serving the electric power generation industry. During the fourth quarter of 2024, we completed our review of the coal mining facilities and future mining plans. The impairment analysis was based upon our finalized coal mining operating plans, market driven pricing and cost trends. As part of that analysis, we determined the carrying amount of our coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in the fourth quarter of 2024. See “Note 19 - Impairment of Coal Properties” to the Consolidated Financial Statements in this Form 10-K for further information on the impairment analysis.
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments. In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy LLC and Oaktown Gas, LLC, which are accounted for using the equity method.
Throughout 2024, we made progress on transitioning Hallador Energy from a bituminous coal producer to an integrated independent power producer (“IPP”). This strategic transition has been a deliberate response to market signals and what we believe to be the superior economics of the IPP business model. As such, our focus remains on maximizing the value of Merom while actively seeking opportunities to acquire additional dispatchable generators. We have also prioritized building strong relationships with counterparties to secure favorable terms for collateral, enabling us to effectively leverage forward power sales in 2025 to offset pricing volatility in the spot market. This approach enhances our financial flexibility and strengthens our position in the evolving energy market.
In the fall of 2024, we reached a key milestone in our IPP transformation by signing a non-binding term sheet with a leading global data center developer for the supply of a significant portion of Merom's output of capacity and energy for well over a decade. As evidenced by our announcement of an exclusivity agreement with this development partner in January 2025, we are continuing to make progress as we seek to finalize a definitive agreement. As we have previously disclosed, the exclusivity period runs through the beginning of June 2025, in exchange for payments from the developer to Hallador Power of up to $5.0 million, depending on if and when a definitive agreement is finalized. This type of deal is complex and involves multiple parties, which adds time and challenges to negotiations. Despite these challenges, we remain encouraged by our partners and the steady progress that we continue to make. Our pursuit of this agreement further demonstrates our commitment towards forging a strategic partnership that we believe will create significant value for our shareholders for years to come. The completion of this proposed transaction is subject to, among other matters, the negotiation and execution of definitive agreements and there can be no assurance that definitive agreements will be entered into or that the proposed transaction will be consummated on the terms or timeframe currently contemplated, or at all.
We continue to witness the prevalent industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable resources such as wind and solar. We believe this transition from dispatchable to non-dispatchable generation made the attributes of our subsidiary, Hallador Power, much more valuable due to the enhanced reliability that we provide versus non-dispatchable generators. However, we believe the retirement of coal-based generation and lower natural gas prices could reduce the demand for coal supply, potentially lowering the value of Sunrise. During 2024, in response to declining coal demand, we reduced our coal production volume by approximately 40% and idled the higher cost surface mines. This optimization of coal production reduced our operational cash cost structure and better aligned our coal strategy to primarily support our internal electric generation.
Merom can produce up to 6.0 million Mega-Watthours (“MWh”) annually. The forward power price curves indicate that the margins earned on energy produced at Merom and the value of the accredited capacity sales assigned to the plant continues to increase. We are seeing strong indications for both energy and capacity sales in 2025 and beyond, especially considering our negotiations related to supporting data center development within the State of Indiana. In addition, while we largely held to our traditional approach of selling energy through bespoke bi-lateral agreements on a unit or plant contingent basis, during 2024 we sold a limited amount of power on a firm basis. While we continue to limit these types of firm sales to mitigate risk and wait for higher priced contracts to take effect, we will strategically utilize them to smooth our exposure to the spot market. This approach enables us to capture some of the episodic cash generation driven by demand from extreme weather and various other conditions stressing the power grid while limiting our exposure to periods of mild weather and lower demand.
In 2024, the ongoing surplus of natural gas in the market and mild weather patterns continued to moderate energy prices throughout the year and kept spot energy prices weak. We began to see favorable pricing signals at the end of the fourth quarter of 2024 and subsequent to year-end.
The ability to store a commodity is inherently tied to the volatility of that commodity. Coal can be piled up for years, thus its volatility is low. Oil and natural gas face transportation and storage challenges which increase price volatility. The limitations of storing viable energy, coupled with non-dispatchable generation gaining market share in an environment where there is unpredictability in the weather, indicates to us that energy's price volatility is likely to increase over the next decade. This volatility will keep the forward power price premium intact.
We are excited by the opportunity for Hallador Power to capture higher prices and energy volumes in 2025 and beyond compared to what we have historically achieved in our relatively short ownership tenure of Merom. In 2024, we sold 4.2 million MWh at an average sales price of approximately $48.62 per MWh. At the start of the year, we had 1.9 million MWh contracted, leaving us with significant exposure to the spot electricity market. Heading into 2025, we have contracted approximately 4.3 million MWh at an average price of $37.24 per MWh, which should help to smooth our exposure to the spot market. For 2026, we have already contracted 3.4 million MWh at $44.43 per MWh. Following 2026, we are optimistic that we can sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a higher forward curve. The tables included below highlight some of the revenue and margin improvements we have seen in our forward contracted power sales for 2025 and thereafter. These tables do not include the significantly higher prices that we are expecting if we are able to finalize our agreements in support of data center development.
In addition to the transaction we are negotiating with Merom, we continue to evaluate other strategic transactions that could add durability, scale, and geographic expansion opportunities to our electric operations. While these types of deals are limited and complex, we believe that Hallador is uniquely positioned to transform retiring and/or underperforming assets into future opportunities. This will enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail consumers, unlike a traditional utility siphoning off consumer power to serve these types of large load end-users. By continuing the operations of the dispatchable plants to support large load industrial users as the utilities transition to non-dispatchable generation, the new generation becomes additive to the already struggling grid rather than cannibalizing the overall reliability of what exists today. We are optimistic about the potential to add to our strategic portfolio and the long-term benefits that such a transaction could produce for the Company, its shareholders and its customers. This model for growth enables us to shift from transactional pricing related to plant acquisition, to traditional wholesale market pricing, and ultimately to the enhanced pricing associated with supporting data centers and other large load end users.
In the first quarter of 2024, we announced a restructuring of our Coal Operations to address the increase in costs we experienced at our mines. See “Note 17 - Organizational Restructuring” to the Consolidated Financial Statements in this Form 10-K for further information. We spent much of the year adjusting to this restructuring to optimize production, headcount, and strategy to best support our Electric Operations and our existing third-party coal contracts. By reducing headcount, focusing production on our most profitable mines and units within those mines, and improving our infrastructure and processes within those favored units, we were able to both slow the impact of rapidly increasing costs and reduce costs to better support the continued operations of our mines.
Historically, Sunrise has produced between four and six million tons annually. As we continue to optimize the mines in support of the plant, we expect to produce approximately 3.6 million tons of coal in 2025, with approximately 2.3 million tons produced directed to support our Electric Operations. We have also secured supplemental coal from third party suppliers at favorable prices to diversify self-production supply risk and to provide us additional flexibility in our sales portfolio and to fulfill future sales obligations to third-parties and Merom as shown in the table below. The optionality to obtain low-cost tons either internally or from third parties while capturing upward swings in the commodity markets for coal should further maximize margins while optimizing fuels costs at Merom.
We remain excited about the continued and deliberate transformation of Hallador from a commodity focused producer of coal to an IPP. We believe this transition provides significant opportunity to capture the expanding margins of the energy markets and capitalize on the soaring demand for electricity. We are pleased by the strong interest we continue to see from potential counterparties in our energy and capacity offerings, bolstered by Indiana’s efforts to attract data centers and other high-density power users through its business-friendly climate and favorable tax policies. With the continued growth of our sales book, coupled with our ongoing focus to transition our operations to primarily electricity generation, we believe we are well positioned to materially strengthen our opportunities for growth and cash flow generation.
Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations
Total
Power
Energy
Contracted MWh (in millions)
4.25
3.36
1.78
1.09
0.27
10.75
Average contracted price per MWh
$
37.24
$
44.43
$
54.66
$
52.94
$
51.33
Contracted revenue (in millions)
$
158.27
$
149.28
$
97.29
$
57.70
$
13.86
$
476.40
Capacity
Average daily contracted capacity MWh
Average contracted capacity price per MWd
$
$
$
$
$
Contracted capacity revenue (in millions)
$
55.95
$
61.12
$
51.40
$
37.33
$
3.47
$
209.27
Total Energy & Capacity Revenue
Contracted Power revenue (in millions)
$
214.22
$
210.40
$
148.69
$
95.03
$
17.33
$
685.67
Coal
Priced tons - 3rd party (in millions)
2.95
2.50
2.50
0.50
-
8.45
Avg price per ton - 3rd party
$
51.04
$
55.49
$
56.74
$
59.00
$
-
Contracted coal revenue - 3rd party (in millions)
$
150.57
$
138.73
$
141.85
$
29.50
$
-
$
460.65
TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED
$
364.79
$
349.13
$
290.54
$
124.53
$
17.33
$
1,146.32
Priced tons - Intercompany (in millions)
2.30
2.30
2.30
2.30
-
9.20
Avg price per ton - Intercompany
$
51.00
$
51.00
$
51.00
$
51.00
$
-
Contracted coal revenue - Intercompany (in millions)
$
117.30
$
117.30
$
117.30
$
117.30
$
-
$
469.20
TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT
$
482.09
$
466.43
$
407.84
$
241.83
$
17.33
$
1,615.52
*
Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.
Electric Operations
Internal Controls Disclosure
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. CAMS 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. CAMS provides regular reports on key performance indicators (“KPIs”) such as heat rates and forced outage rates to help us assess plant efficiency. CAMS assists in ensuring adherence to local, state and federal regulations including
environmental rules and safety mandates. We maintain oversight of CAMS through regular audits and performance reviews, confirming all procedures align with our company policies and best practices.
We engage 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 regional transmission organizations (“RTOs”) or independent system operators (“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 assists in risk management by executing short-term trades on our behalf to mitigate price volatility and lock in predictable revenues as well as ensures 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 committee that evaluates all marketing activities and exposures.
Merom operates under permits issued by various agencies. CAMS provides support and expertise to ensure compliance with emissions requirements, water use regulations, and waste disposal guidelines. The power markets we operate in periodically update their rules and tariffs, which may affect how we dispatch our plants or manage financial positions. ACES continuously monitors changes, recommending updates to our strategies as needed.
Volatility in wholesale power prices can impact revenue. ACES provides strategies to mitigate price risk.
Equipment failures or unexpected downtime at coal plants can lead to missed market opportunities or contractual liabilities. Our relationship with CAMS is designed to minimize these risks through comprehensive operations and maintenance practices. Future environmental or market regulations may require capital investments or shift market behavior. Our teams, in conjunction with CAMS and ACES, monitor emerging policies to proactively plan operational or strategic adjustments.
Property
Through Hallador Power, the Company owns and operates 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. Unit 1 entered commercial operations in 1982 and Unit 2 in 1983. The units are dispatched to the MISO interconnection. Hallador Power sells wholesale energy and accredited capacity to utilities within the MISO system through PPA’s and other bilateral transactions. Merom is located in Sullivan County, Indiana, on approximately 691 acres, which also holds a 112-acre landfill. Hallador Power has two tracts under option for approximately 72 acres for expansion and future development at Merom. Merom is about twenty miles from Sunrise’s Oaktown Mining Complex and has rail and truck access. The Company acquired Merom from Hoosier Energy Rural Electric Cooperative, Inc. in 2022.
Year Ended December 31,
Power Capacity and Utilization
Nameplate capacity (MW)(i)
1,080
1,080
Accredited capacity for the period (MW)(ii)
Accredited capacity utilization(iii)
%
%
i. Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.
ii. Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 808 MW and 838 MW per day for 2024 and 2023, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.
iii. Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24 times the number of days for the period.
Permits are required by federal and state law for Merom’s facilities and landfill. Merom holds several construction and environmental permits for air, wastewater and solids waste disposal. All necessary permits to support current operations are in place. New permits or permit revisions may be necessary from time to time to facilitate future operations or to keep pace with the changing regulatory landscape. Given sufficient time and planning, we should be able to secure new permits, as required, to maintain our planned operations within the context of the current regulations. Merom continually excels in environmental excellence and compliance.
Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide assurance that any disturbance or liability created is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. We hold surety bonds of $9.7 million to cover obligations relating to reclamation at Merom.
Coal Operations
Internal Controls Disclosure
The preparation of coal reserve and resource estimates is conducted by independent individuals who are by virtue of their education, experience and professional association considered qualified persons (as defined in SEC rules). Company personnel meet on an annual basis with the independent qualified person to provide updates to the reserve and resource estimates. Company personnel review the work of the qualified person to ensure such work is prepared in accordance with applicable rules and regulations and that the data and assumptions provided were properly applied to the final reserve and resource model. The Company’s engineering personnel ensure estimates are based on current mine plans, incorporate the most recent drilling and lab data, properly reflect changes in permitting status, consider known encumbrances, and are consistent with operating knowledge and expectations in terms of mining methods, recovery rates, minimum seam heights or maximum strip ratios, and saleable qualities.
An American National Standards Institute-certified third-party laboratory is utilized to support reserve and resource estimates. The laboratory follows standard sample preparation, security, and environmental procedures. In addition, the Company’s qualified person performs independent data verification procedures to ensure data is of sufficient quantity and reliability to reasonably support the coal reserve and resource estimates.
Estimates of any mineral reserve and resources are always subject to a degree of uncertainty. The level of confidence that can be applied to a particular estimate is a function of, among other things, the amount, quality, and completeness of exploration data; geological complexity of the deposit; and economic, legal, social, and environmental factors associated with mining the reserve/resource. The Company’s current coal reserves and resource estimates are based on the best information available and are subject to updates as conditions change. Also refer to "Item 1A. Risk Factors" for discussion of risks associated with the estimates of the Company’s reserves and resources.
Summary of All Mining Properties
The Company has seven total mining properties. These properties are the Oaktown Mining Complex (“Oaktown”), which is comprised of Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine, the Ace in the Hole Mine, the Ace in the Hole Mine #2 Reserves, Prosperity, Freelandville and Carlisle. Oaktown Fuels No. 2, Prosperity and Freelandville were temporarily idled in February of 2024 as part of the Organizational Restructuring in “Note 17 - Organizational Restructuring” to the Consolidated Financial Statements below. Ace in the Hole Mine and Carlisle are fully depleted.
The Oaktown Fuels No. 1 Mine is an underground mine in the Illinois Basin located near Oaktown in Knox County, Indiana. Oaktown Fuels No. 1 Mine utilizes continuous mining units operating in room and pillar mining techniques to produce high-sulfur coal. The Oaktown Fuels No. 2 Mine is an underground mine in the Illinois Basin (“ILB”) located near Oaktown in Knox County, Indiana. The Oaktown Fuels No. 2 Mine utilizes continuous mining units operating in room and pillar mining techniques to produce high-sulfur coal. The preparation plant at Oaktown has a throughput capacity of 1,600 tons of raw coal per hour. Freelandville is a surface mine in the Illinois Basin located near Freelandville in Knox County, Indiana. Freelandville utilizes surface mining techniques to produce high-sulfur coal from as many as three seams. Prosperity is a surface mine in the Illinois Basin located near Petersburg in Pike County, Indiana. Prosperity utilizes surface mining techniques to produce low-sulfur coal. The low-sulfur coal is trucked to the Oaktown and other Sunrise Coal logistic facilities where it is blended with coal from the Oaktown Mines.
These properties and further summaries concerning property description, purpose, property overview, geology, background, processing operations, mine infrastructure, and market analysis can be found and are hereby incorporated by reference from Sections 1.1, 1.2, 1.3, 1.6, 2.1, 3, 4, 5, 6, 7.1, 7.3, 7.4, 8, 9, and 10 from the March 2025 Technical Report Summary prepared by the John T. Boyd Company, attached as Exhibit 99.1 to this Form 10-K.
The following figure shows the general location of Merom and our mining properties discussed above:
Individual Mining Properties
The following information concerning our mining properties has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K. Subpart 1300 of Regulation S-K requires us to disclose our mineral (coal) resources, which we have none, in addition to our mineral (coal) reserves, as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties.
As used in this Annual Report on Form 10-K, the terms “mineral resources,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination
has been made by a qualified person (“QP”) that the mineral resources can be the basis of an economically viable project. You are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the SEC.
Internal qualified person(s) have estimated the Company’s mineral reserves and mineral resources based on geologic data, coal ownership (control) information, and current and/or proposed operating plans. Periodic updates occur to mineral reserve and mineral resource estimates attributable to revised mine plans, new exploration data, depletion from coal production, property acquisitions or dispositions, and/or other geologic or mining data. Sunrise’s estimates of mineral reserves are proven and probable reserves that could be extracted or produced at the time of the reserve determination, economically, legally, and after considering all material modifying factors. Modifications or updates of the estimates of the Company’s mineral reserves is limited to qualified geologists and mining engineers. All modifications or updates of the estimates of recoverable coal reserves are documented. The John T. Boyd Company, a qualified person firm, has assessed the Company’s estimates of mineral reserves and mineral resources and supporting information. Based upon the review, John T. Boyd Company provided modification to the Company’s estimates of mineral reserves where warranted.
The information that follows is derived, for the most part, from, and in some instances is extracted from, the Oaktown Mining Complex technical report summary (“TRS”) from John T. Boyd Company dated March 2025 in accordance with Subpart 1300 of Regulation S-K (Coal Resources and Coal Reserves, Oaktown Mining Complex) attached hereto as Exhibit 99.1 to this Form 10-K; and a letter, dated March 7, 2025, from John T. Boyd Company providing an update of estimated coal reserves at the Oaktown Mining Complex as of December 31, 2024, attached as Exhibit 99.2 to this Form 10-K. The Oaktown Mining Complex is the Company’s individually material property. Sections of the following information provided herein do not fully describe assumptions, qualifications, and procedures. Reference should be made to the full text of the TRS which is made a part of this Annual report on Form 10-K and incorporated hereby by reference. The Oaktown Mining Complex TRS was prepared by the John T. Boyd Company in compliance with the Item 60(b)(96) and subpart 1300 of Regulation S-K.
The Company hereby incorporates by reference Section 6.3 "Coal Reserves" from the TRS, attached as Exhibit 99.1 to this Form 10-K, as to the mineral price, cut-off grade, and metallurgical recovery factors utilized in John T. Boyd Company’s preparation of the mineral reserve estimates. The Company hereby incorporates the letter, dated March 7, 2025, from John T. Boyd Company, attached as Exhibit 99.2 to this Form 10-K, providing an update of the Company’s mineral reserves at the Oaktown Mining Complex as of December 31, 2024 and including a comparison of the Company’s mineral reserves at the Oaktown Mining Complex as of December 31, 2024 and as of December 31, 2023. The following table provides a summary of all of the Company’s mineral reserves determined by the John T. Boyd Company as of the end of the fiscal year ended December 31, 2024:
SUMMARY MINERAL RESERVES AT END OF THE
FISCAL YEAR ENDED DECEMBER 31, 2024
Mineral Reserves (tons in millions)
Proven
Probable
Total
Oaktown
Oaktown Fuels No. 1 Mine
25.7
2.7
28.4
Oaktown Fuels No. 2 Mine
5.9
0.2
6.1
Total
31.6
2.9
34.5
Oaktown Mining Complex
The Oaktown Mining Complex is a coal mining and processing operation located in Knox and Sullivan counties, Indiana, and Crawford and Lawrence counties, Illinois.
Oaktown is an underground Room-and-Pillar (“R&P”) coal mining complex. It is comprised of 83 square miles within the ILB coal-producing region of the mid-western U.S. Oaktown operations currently consists of one active underground mine - Oaktown Fuels No. 1 Mine - and related infrastructure. Geographically, the Oaktown Complex Coal Preparation
Plant is located at approximately 28°51’24.7” N latitude and 87°25’30.9” W longitude. Within the Oaktown area and its immediate vicinity, our Company controls approximately 64,000 acres of mineral rights. We have a complex collection of leases that apply to more than 1,000 tracts. Leased tracts range from less than an acre to several hundred acres in size. Ownership of the surface rights and the mineral rights is often severed for the properties and the estates are often fractions, in which mineral rights are split between several owners. The Company and its predecessors have acquired the necessary rights to support development and operations through purchase or lease agreements with predominately private owners or entities. The Company controls surface rights through fee simple ownership for over 1,700 permitted acres, holding mine accesses, processing, storing, shipping, and refuse disposal facilities (i.e., refuse impoundment site and fine refuse injection sites). We acquired Oaktown Fuels No. 1 and No. 2 Mines from Vectren Fuels in 2014.
Oaktown utilizes R&P mining (employing Continuous Miners, or CM) for primary production. This mining method is highly productive and commercially demonstrated; it has been one of the primary approaches to underground mining the Indiana V Seam for decades. Oaktown has utilized this mining method since the inception of each operation. To date, Oaktown has produced a combined 75.0 million tons of clean coal. Oaktown is configured to operate up to 6 CM sections (currently operating 4 CM sections), with an annual production target of approximately 3.6 million tons. The Oaktown Preparation Plant serves as the coal washing and shipment facility for Oaktown’s two R&P mines. The plant was commissioned in 2009 to wash coal by the Oaktown Fuels No. 1 Mine. The Oaktown Preparation Plant’s processing capacity was upgraded to 1,800 raw tons-per-hour (TPH) from its previous 1,600 raw TPH in 2023. Coal from Oaktown is transported to customers via rail and truck. The Oaktown Preparation Plant is served by both the CSX Railroad and Indiana Railroad (INRD) via a rail spur and rail loop that connects the complex with the mainline rail just north of Oaktown, Indiana.
Additionally, the Oaktown Preparation Plant can facilitate the loading of trucks for direct transport to select customers, or to our transload facility in Princeton, Indiana serviced by the Norfolk Southern (NS) Railroad.
Sources of electrical power, water, supplies, and materials are readily available. Electrical power is provided to the mines and facilities by regional utility companies. Water is supplied by public water services, surface impoundments, or water wells.
Multiple permits are required by federal and state law for underground mining, coal preparation and related facilities, and other incidental activities. All necessary permits to support current operations are in place or pending approval. New permits or permit revisions may be necessary from time to time to facilitate future operations. Given sufficient time and planning, we should be able to secure new permits, as required, to maintain our planned operations within the context of the current regulations.
Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. We hold surety bonds of $10.0 million to cover obligations relating to mining and reclamation, road repair, etc. at the Oaktown Mining Complex.
Additional information is provided in the following table regarding Oaktown’s mineral reserves:
OAKTOWN
Recoverable Coal Reserves as of December 31, 2024 and 2023
As Received
As Received
Heat
SO2
Value
Content
(Btu/lb)
(lbs/MMBtu)
Owned
Leased
Recoverable Coal Reserves (As-Received)
Mine/Reserve
Approximate
Approximate
(%)
(%)
Proven
Probable
12/31/2024
12/31/2023
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine
11,630
6.0
-
100.0
25.7
2.7
28.4
34.1
Oaktown Fuels No. 2 Mine
11,576
5.0
-
100.0
5.9
0.2
6.1
26.6
Total
31.6
2.9
34.5
60.7
Oaktown Fuels No. 1 Mine
As of December 31, 2024, the assigned and accessible reserve base for the Oaktown Fuels No. 1 Mine contains 28.4 million tons of recoverable Indiana V seam coal, of which 28.4 million tons are currently permitted. The reserve contains saleable tons which average heating content of approximately 11,630 Btu per pound with approximately 6.0 pounds of sulfur dioxide per MMBtu on an as-received basis. Access to the Oaktown Fuels No. 1 Mine is via a 90-foot-deep box cut and a 2,200-foot long slope, which facilitates the egress of coals being mined in excess of 375 feet below the surface. Since beginning first commercial coal production in 2009, the mine workings have substantially grown, and an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces.
Oaktown Fuels No. 2 Mine
As of December 31, 2024, the assigned and accessible reserve base for the Oaktown Fuels No. 2 Mine contains 6.1 million tons of recoverable Indiana V seam coal, of which 5.4 million tons are currently permitted. The reserve contains saleable tons which average heating content of approximately 11,576 Btu per pound with approximately 5.0 pounds of sulfur dioxide per MMBtu on an as-received basis. Access to the Oaktown Fuels No. 2 Mine is via an 80-foot-deep box cut and 2,600-foot long slope, which facilitates the egress of coals being mined in excess of 400 feet below the surface. In 2021, an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces. Oaktown Fuels No. 2 was temporarily idled in February of 2024.
Coal tons are reported on a clean recoverable basis with average long-term pricing based on available third-party forecasts and historical pricing adjusted for quality at the end of 2024, with the coal sales price estimated over the life of the reserve averaging approximately $49 (ranging from $47.25 to $51.47 per ton), which are the coal sales prices used by John T. Boyd Company to estimate the amount of coal mineral reserves for the Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine as listed above. Coal sales prices vary based on coal quality, access to transportation, and other factors at each location. All reserves are classified as underground mineable in the production stage.
The Company hereby incorporates by reference (i) the TRS, attached as Exhibit 99.1 to this Form 10-K, including Section 6.3 thereof titled "Coal Reserves", as to the recoverable coal reserves reported above for the Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine; and (ii) letter, dated March 7, 2025, from John T. Boyd Company, attached as Exhibit 99.2 to this Form 10-K, providing an update of the Company’s mineral reserves at Oaktown as of December 31, 2024 and including a comparison of the Company’s mineral reserves at Oaktown as of December 31, 2024 and as of December 31, 2023.
Historical production for Oaktown during the years ended December 31, 2024, 2023, and 2022 are provided in the following table:
Annual Saleable Production Tons
(Million Tons)
Mine/Reserve
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine
3.5
3.9
3.9
Oaktown Fuels No. 2 Mine
0.4
2.5
2.5
Total Oaktown Mining Complex Production
3.9
6.4
6.4
Other Properties
The Company holds other recoverable coal reserves in the ILB, which are not deemed individually material.
Ace in the Hole Mine (Ace) (surface) - Assigned
Ace Mine is now depleted. Remaining inventory of coal and base was moved to our Oaktown wash plant in early 2023. Reclamation resumed in the Spring of 2023. There are four phases of reclamation that extend through 2029, of which, Phase 1 and 2 were completed as of December 31, 2024.
Prosperity (surface) - Assigned
The Prosperity mine contains approximately 0.2 million tons of low sulfur coal. The mine opened in the summer of 2022. The mine produced coal and reclaimed the slurry pond and refuse pile left by the Prosperity underground mine. Additional reserves are in the area that may extend the life of this mine. In February 2024, this mine was temporarily idled.
Freelandville (surface) - Assigned
Sunrise is a contract miner at the Freelandville East Mine Center Pit, Permit No. S 358. Sunrise had an option through May 31, 2023 to assume the permit that contained approximately 1.7 million tons of salable coal with an additional 0.6 million available. That option was extended from May 2023 until May 2026. Mining started in the fall of 2022 and continued through April 2023 with limited production in 2024. Remaining reserves under the permit are 0.4 million tons. There are additional reserves of 1.2 million tons available with the completion and approval of an Army Corps of Engineers permit. In February 2024, this mine was idled.
Carlisle
The Carlisle mine is located near the town of Carlisle, Indiana in Sullivan County. It became operational in January 2007 for both surface and underground mining. The mine was permanently closed for mining operations in 2020. A wash plant was relocated to the Carlisle mine in 2022 and was sold in 2024.
Our Coal Contracts
In 2024, on a segment basis Sunrise sold 3.9 million tons of coal to 6 power plants in four different states across five different customers.
During 2024, on a segment basis we derived 96% of our revenue from four customers (5 power plants), with each of the four customers representing at least 10% of our coal sales. During 2023, on a segment basis we derived 94% of our revenue from five customers (11 power plants), with each of the five customers representing at least 10% of our coal sales.
Significant third-party customers in 2024 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC), and Duke Energy Corporation (NYSE: DUK).
Of our 2024 sales, on a segment basis 43%, excluding Merom, were derived to locations in the State of Indiana.
Our future coal commitments are as follows:
3rd Party
Merom Power Plant
Contracted
Contracted
Estimated
tons
tons
Priced
Year
(millions)*
(millions)*
Total
per ton
3.0
2.3
5.3
$
51.03
2026 - 2028 (total)
5.5
6.9
12.4
53.38
Total
8.5
9.2
17.7
*
Contracted tons are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.
**
Unpriced or partially priced committed tons
As of December 31, 2024, we are committed to supplying third-party customers a base amount of 8.5 million tons of coal through 2028 of which 8.5 million tons are priced. We are committed to supplying coal to Merom a base amount of 9.2 million tons of coal through 2028. All committed tons to Merom are priced.
Based on the contracted tons described above, we anticipate our mines will need to produce at a 3.6 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 March of 2026, 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.
Liquidity and Capital Resources
As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $65.9 million and $59.4 million for the years ended December 31, 2024 and 2023 respectively. Operating cash flow increased mainly due to prepaid physically delivered power contracts entered into during 2024.
Our capital expenditure budget for 2025 is $66.0 million. Of the $66.0 million, the electric operations budget is $31.0 million for maintenance capex and $14.0 million for ELG. The coal operations budget is $14.8 million plus an additional $5.8 million for discretionary items.
As of December 31, 2024, our bank debt was $44.0 million. On March 13, 2023, we executed an amendment to our credit agreement with PNC Bank, National Association (in its capacity as administrative agent, “PNC”), administrative agent for our lenders under our credit agreement. The primary purpose of the amendment was to convert $35 million of the revolver into a new term loan with a maturity of March 31, 2024, and extend the maturity date of the revolver to May 31, 2024. On August 2, 2023, we executed an additional amendment with PNC. The primary purpose of the amendment was to convert $65 million of the existing outstanding debt into a new term loan with a maturity of March 31, 2026, and enter into a revolver of $75 Million with a maturity date of July 31, 2026. Principal payments for the term loan were $3.3 million per quarter for September 30, 2023, and December 31, 2023, and $6.5 million per quarter starting March 31, 2024, through maturity. The effect of the amendment on our future cash flow is to extend the maturity date of $65.0 million of our outstanding term debt to March 31, 2026, and our revolver to July 31, 2026.
On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC. The primary purpose of the First Amendment was to provide the Company with short-term covenant relief to pursue additional liquidity. The First Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repays outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a maximum of $20.0 million. These required prepaid forward power sale Term Loan repayments, if any, will take the place of the $6.5 million quarterly Term Loan payments.
We expect cash from operations generated primarily by our expected higher Electric Operation margins in 2025 to fund our capital expenditures and our debt service.
See “Note 4” to our Consolidated Financial Statements for additional discussion about our bank debt and related liquidity.
Off-Balance Sheet Arrangements
Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value of reclamation obligations of $16.9 million, including $5.7 million at Merom, presented as asset retirement obligations (ARO) in our accompanying consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.8 million to cover ARO.
Capital Expenditures (“Capex”)
For the year ended December 31, 2024, our Capex was $53.4 million allocated as follows (in millions):
Oaktown - maintenance capex
$
22.5
Oaktown - investment
11.3
Merom Plant
18.7
Other
0.9
Capex per the Condensed Consolidated Statements of Cash Flows
$
53.4
Results of Operations
Presentation of Segment Information
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50.0% interest in Sunrise Energy, which is accounted for using the equity method.
Electric Operations
Year Ended December 31,
(in thousands)
Delivered Energy
$
203,434
$
211,772
Capacity Revenue
58,093
56,155
Electric Sales
$
261,527
$
267,927
Fuel
$
(111,768)
$
(139,496)
Other Operating Costs (1)
(19)
(32)
Other Operating and Maintenance Costs (2)
(28,622)
(33,777)
Cost of Purchased Power
(10,888)
-
Utilities
(2,070)
(429)
Labor
(30,842)
(31,245)
General and Administrative
(5,311)
(4,914)
EBITDA Margin
72,007
58,034
Other Operating Revenue
Amortization of Contract Asset
-
(26,581)
Depreciation, Depletion and Amortization
(19,290)
(18,739)
Asset Retirement Obligations Accretion
(457)
(576)
Interest expense
(1,875)
(322)
Income (Loss) before Income Taxes
$
51,367
$
12,230
1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in 1).
Year Ended December 31,
(per MWh)
MWh Generated (in thousands)
3,830
4,224
MWh Purchased (in thousands)
-
MWh Sold (in thousands)
4,184
4,224
Delivered Energy
$
48.62
$
50.14
Capacity Revenue
13.88
13.29
Electric Sales
$
62.50
$
63.43
Fuel
$
(26.71)
$
(33.02)
Other Operating Costs (1)
-
(0.01)
Other Operating and Maintenance Costs (2)
(6.84)
(8.00)
Cost of Purchased Power
(2.60)
-
Utilities
(0.49)
(0.10)
Labor
(7.37)
(7.40)
General and Administrative
(1.27)
(1.16)
EBITDA Margin
17.22
13.74
Other Operating Revenue
0.23
0.10
Amortization of Contract Asset
-
(6.29)
Depreciation, Depletion and Amortization
(4.61)
(4.44)
Asset Retirement Obligations Accretion
(0.11)
(0.14)
Interest expense
(0.45)
(0.08)
Income (Loss) before Income Taxes
$
12.28
$
2.89
1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in 1).
Fuel decreased $27.7 million, or 19.9%, from 2023 due to production decreasing by 394 MWh, or 9.3%, and the expiration of a purchased coal contract in 2023 reducing our average coal pricing by $8.61 per ton, or 14%, on a segment basis. We used 189,000 tons, or 9.2%, less in production compared to the prior year. The decrease in demand for electric power was related to mild weather throughout 2024 and the associated higher demand for natural gas as natural gas inventories remained high causing a decline in the average spot prices for natural gas which changed $0.34 per mbtu, or 13.5% from 2023.
Other operating and maintenance costs decreased $5.2 million, or 15.3%, from 2023 primarily due to 2023 year-to-date planned maintenance of $13.0 million compared to $9.1 million in 2024.
Cost of purchased power increased $10.9 million, or 100.0%, from 2023. When energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.
Amortization of the contract asset decreased by $26.6 million, or 100.0%, from 2023 due to the expiration of our coal purchase contract.
Income (loss) before income taxes increased $39.1 million, or 320.0%, and increased $9.39 per MWh, from 2023 due to the items described in the discussion above.
Coal Operations
Year Ended December 31,
(in thousands)
Coal Sales
$
202,525
$
432,888
Fuel
$
2,851
$
7,089
Other Operating and Maintenance Costs
89,283
165,479
Utilities
13,844
17,301
Labor
85,322
121,172
General and Administrative
9,877
10,287
EBITDA Margin
1,348
111,560
Other Operating Revenue
2,756
2,936
Depreciation, Depletion and Amortization
(46,245)
(48,365)
Asset Impairment
(215,136)
-
Asset Retirement Obligations Accretion
(1,171)
(1,228)
Exploration Costs
(260)
(904)
Gain (loss) on disposal or abandonment of assets, net
(1,629)
(398)
Interest expense
(11,033)
(11,869)
Loss on Extinguishment of Debt
-
(1,491)
Settlement of Litigation
(2,750)
-
Income (Loss) before Income Taxes
$
(274,120)
$
50,241
Year Ended December 31,
(per ton)
Tons Sold
3,864
6,922
Coal Sales
$
52.41
$
62.54
Fuel
$
0.74
$
1.02
Other Operating and Maintenance Costs
23.11
23.91
Utilities
3.58
2.50
Labor
22.08
17.51
General and Administrative
2.56
1.49
EBITDA Margin
0.34
16.11
Other Operating Revenue
Depreciation, Depletion and Amortization
(11.97)
(6.99)
Asset Impairment
(55.68)
-
Asset Retirement Obligations Accretion
(0.30)
(0.18)
Exploration Costs
(0.07)
(0.13)
Gain (loss) on disposal or abandonment of assets, net
(0.42)
(0.06)
Interest expense
(2.86)
(1.71)
Loss on Extinguishment of Debt
-
(0.22)
Settlement of Litigation
(0.71)
-
Income (Loss) before Income Taxes
$
(71.67)
$
6.82
During 2024, we undertook an Organizational Restructuring of our Coal Operations. See “Note 17 - Organizational Restructuring” in the Consolidated Financial Statements for further information.
Segment operating revenues from coal operations decreased $230.4 million, or 53.2%, from 2023. Consolidated operating revenues from coal operations decreased $224.5 million, or 62.0%, from 2023. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $10.13 per ton and we sold 3.1 million tons less compared to 2023. Our average sales price, on a consolidated basis, for 2024 decreased $7.58 per ton and we sold 3.3 million tons less compared to 2023.
Other operating and maintenance costs decreased $76.2 million, or 46.0%. Labor decreased $35.9 million, or 29.6%, from 2023, however labor cost per ton sold increased $4.57 per ton sold. These changes were driven by the Reorganization Plan disclosed in “Note 17 - Organizational Restructuring” to the Consolidated Financial Statements. As part of the Organizational Restructuring, we incurred aggregate expenses of $1.9 million ($1.1 million in the first
quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in coal operations “Labor”. These charges related to compensation, tax, professional, and insurance related expenses and are considered one-time charges paid during 2024. During 2024, we produced 2.7 million tons less on a segment basis than 2023. Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 305 employees.
We recorded an asset impairment of $215.1 million during 2024. During the fourth quarter of 2024, we began our annual business plan review. We evaluated core hole samples at several of our mines, reviewing the quality of the mine seam and density of the coal. Based upon market price trends, we believe that the required course of action is to only produce those reserves that will allow us the lowest possible cost, and therefore capture the highest possible margins. The core hole samples at our Oaktown 2 mine were of a lower quality and density than that of the Oaktown 1 mine. As such, at the conclusion our annual business plan review during the fourth quarter of 2024, we decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs. Due to that decision, we determined a triggering event had occurred and completed an impairment review to determine if the carrying value of our coal properties were impaired by comparing the net book value of our coal properties to estimated undiscounted future net cash flows. The result of this undiscounted cash flow test indicated the carrying amount of our coal properties may not be recoverable. As a result, the Company prepared a discounted cash flow model (Level 3 fair value measurement under the fair value hierarchy) to estimate fair value.
Income (loss) before income taxes decreased $324.4 million, or 645.6%, and decreased $78.49 per ton, from 2023. The main drivers of this change in income from operations are described in the discussion above.
The following tables presenting our quarterly results of operations should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of this Form 10-K. We have prepared the unaudited information on the same basis as our audited consolidated financial statements. Our operating results for any quarter are not necessarily indicative of results for any future quarters or for a full year. The tables present our unaudited quarterly results of operations for the eight quarters ended December 31, 2024, and include all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair presentation of our consolidated operating results for the quarters presented. In the fourth quarter of 2024, the Company made certain reclassifications that reduced “other operating and maintenance costs” and increased “depreciation, depletion and amortization” for certain assets with a useful life of one to three years. The entire adjustment is reflected in the fourth quarter of 2024. Previous interim periods and prior year periods were not adjusted as the amounts were not material. The amounts recognized in the fourth quarter of 2024 that are related to the first, second and third quarters of 2024 were $2.1 million, $2.6 million and $1.7 million, respectively.
Mar-31
Jun-30
Sep-30
Dec-31
Total 2024
(in thousands, except per share information)
SALES AND OPERATING REVENUES:
Electric sales
$
60,681
$
59,465
$
71,715
$
69,666
$
261,527
Coal sales
49,630
32,801
31,662
23,355
137,448
Other revenues
1,263
1,045
1,377
1,734
5,419
Total revenue
111,574
93,311
104,754
94,755
404,394
EXPENSES:
Fuel
8,059
10,439
13,176
17,669
49,343
Other operating and maintenance costs
37,482
35,912
33,320
11,650
118,364
Cost of purchased power
1,926
2,619
3,149
3,194
10,888
Utilities
4,374
3,396
3,185
4,959
15,914
Labor
35,168
26,555
26,721
27,720
116,164
Depreciation, depletion and amortization
15,443
13,649
13,838
22,696
65,626
Asset retirement obligations accretion
1,628
Exploration costs
General and administrative
5,944
7,803
6,471
6,309
26,527
Asset impairment
-
-
-
215,136
215,136
(Gain) loss on disposal or abandonment of assets, net
(24)
(222)
(290)
(50)
Settlement of litigation
-
-
-
2,750
2,750
Total operating expenses
108,841
100,597
100,042
313,070
622,550
INCOME (LOSS) FROM OPERATIONS
2,733
(7,286)
4,712
(218,315)
(218,156)
Interest expense (1)
(3,937)
(3,735)
(2,692)
(3,486)
(13,850)
Loss on extinguishment of debt
(853)
(1,937)
-
-
(2,790)
Equity method investment income (loss)
(249)
(257)
(234)
(6)
(746)
INCOME (LOSS) BEFORE INCOME TAXES
(2,306)
(13,215)
1,786
(221,807)
(235,542)
INCOME TAX EXPENSE (BENEFIT):
Current
-
-
-
(169)
(169)
Deferred
(610)
(3,011)
(5,846)
(9,235)
Total income tax expense (benefit)
(610)
(3,011)
(6,015)
(9,404)
NET INCOME (LOSS)
$
(1,696)
$
(10,204)
$
1,554
$
(215,792)
$
(226,138)
NET INCOME (LOSS) PER SHARE:
Basic
$
(0.05)
$
(0.27)
$
0.04
$
(5.06)
$
(5.72)
Diluted
$
(0.05)
$
(0.27)
$
0.04
$
(5.06)
$
(5.72)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic
34,816
37,879
42,598
42,617
39,504
Diluted
34,816
37,879
43,018
42,617
39,504
Mar-31
Jun-30
Sep-30
Dec-31
Total 2023
(in thousands, except per share information)
SALES AND OPERATING REVENUES:
Electric sales
$
92,392
$
71,017
$
67,403
$
37,115
$
267,927
Coal sales
94,602
88,574
97,420
81,330
361,926
Other revenues
1,361
1,640
1,059
5,025
Total revenue
188,355
161,231
165,788
119,504
634,878
EXPENSES:
Fuel
55,973
32,641
11,345
3,429
103,388
Other operating and maintenance costs
32,520
41,908
65,551
59,876
199,855
Cost of purchased power
-
-
-
-
-
Utilities
4,497
4,343
4,507
4,383
17,730
Labor
40,531
36,528
37,639
37,719
152,417
Depreciation, depletion and amortization
17,976
17,169
16,230
15,836
67,211
Asset retirement obligations accretion
1,804
Exploration costs
General and administrative
6,947
5,595
6,054
7,563
26,159
(Gain) loss on disposal or abandonment of assets, net
Total operating expenses
159,122
138,987
141,985
129,772
569,866
INCOME (LOSS) FROM OPERATIONS
29,233
22,244
23,803
(10,268)
65,012
Interest expense (1)
(3,899)
(3,541)
(3,030)
(3,241)
(13,711)
Loss on extinguishment of debt
-
-
(1,491)
-
(1,491)
Equity method investment income (loss)
(217)
(177)
(227)
(552)
INCOME (LOSS) BEFORE INCOME TAXES
25,403
18,486
19,105
(13,736)
49,258
INCOME TAX EXPENSE (BENEFIT):
Current
(178)
(479)
(164)
Deferred
2,920
1,510
3,208
(3,009)
4,629
Total income tax expense (benefit)
3,352
1,571
3,030
(3,488)
4,465
NET INCOME (LOSS)
$
22,051
$
16,915
$
16,075
$
(10,248)
$
44,793
NET INCOME (LOSS) PER SHARE:
Basic
$
0.67
$
0.51
$
0.49
$
(0.31)
$
1.35
Diluted
$
0.61
$
0.47
$
0.44
$
(0.31)
$
1.25
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic
32,983
33,137
33,140
33,245
33,133
Diluted
36,740
36,708
36,848
33,245
36,827
Quarterly coal sales and cost data follow on a segment basis (in 000’s, except for per ton data and wash plant recovery percentage):
All Mines
1st 2024
2nd 2024
3rd 2024
4th 2024
T4Qs
Tons produced
1,271
4,004
Tons sold
1,214
3,864
Wash plant recovery in %
%
%
%
%
Capex (Coal Operations)
$
8,632
$
7,560
$
6,810
$
11,079
$
34,081
Maintenance capex (Coal Operations)
$
8,085
$
6,014
$
4,208
$
4,492
$
22,799
Maintenance capex per ton sold (Coal Operations)
$
6.66
$
7.08
$
4.54
$
5.13
$
5.90
Average cost per ton sold⁽ⁱ⁾
$
51.65
$
49.94
$
52.22
$
43.25
$
49.51
All Mines
1st 2023
2nd 2023
3rd 2023
4th 2023
T4Qs
Tons produced
2,006
1,723
1,594
1,331
6,654
Tons sold
1,693
1,714
2,054
1,461
6,922
Wash plant recovery in %
%
%
%
%
Capex (Coal Operations)
$
12,639
$
14,445
$
11,570
$
17,867
$
56,521
Maintenance capex (Coal Operations)
$
7,778
$
9,754
$
7,938
$
13,567
$
39,037
Maintenance capex per ton sold (Coal Operations)
$
4.59
$
5.69
$
3.86
$
9.29
$
5.64
Average cost per ton sold⁽ⁱ⁾
$
38.81
$
41.52
$
46.54
$
53.78
$
44.94
i)Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”, “Utilities” and “Labor” costs as adjusted for the fourth quarter 2024 reclassification adjustments previously described, divided by tons sold for the respective period in this table. Coal Operations costs are presented in the “Presentation of Segment Information” above.
Critical Accounting Estimates
We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, treatment of business combinations, and the estimates used in impairment analysis are our critical accounting estimates.
The reserve estimates are used in the depreciation, depletion and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal.
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.
Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include
reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.
Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions and our tax provision and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant.
Inventory is valued at lower of cost or net realizable value (NRV). The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of December 31, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $0.3 million and $2.0 million, respectively.
Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the Company and its Board of Directors no less than annually, normally during the 4th quarter of each year. Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statement of Stockholders’ Equity
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Hallador Energy Company
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Hallador Energy Company (a Colorado corporation) and subsidiaries (the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, cash flows and stockholders’ equity for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 17, 2025 expressed an unqualified opinion.
Change in accounting principle
As discussed in Notes 1 and 20 to the consolidated financial statements, the Company has adopted new accounting guidance in 2024 related to the disclosure of segment information in accordance with ASU 2023-07, Segment Reporting (Topic 280). The adoption was retrospectively applied to 2023.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they relate.
Asset retirement obligations
As of December 31, 2024, the Company’s asset retirement obligations totaled $16.9 million. As described further in Note 1 to the consolidated financial statements, the Company’s asset retirement obligations are associated with retirement of long-lived assets and recognized at fair value at the time the obligations are incurred. The Company reviews its asset retirement obligations at least annually and makes necessary adjustments for revisions of inputs and
assumptions utilized in the calculations. The calculation of asset retirement obligations requires significant management judgment due to the inherent complexity in estimating the amount and timing of future reclamation activities. We identified the accounting for the asset retirement obligations as a critical audit matter.
The principal consideration for our determination that the accounting for the asset retirement obligations is a critical audit matter is that management utilized significant judgment in determining the amount of asset retirement obligations. In particular, the obligations’ value is estimated based upon a discounted cash flow technique and includes inputs and assumptions related to uncertain future reclamation costs and the timing of reclamation activities. Accordingly, auditing management’s assumptions involved a high degree of subjectivity due to the uncertainty of management’s significant judgments.
Our audit procedures related to the accounting for asset retirement obligations included the following, among others:
● We tested the design and operating effectiveness of internal controls over the asset retirement obligations estimation and recognition process.
● We assessed the reasonableness of the Company’s methodology to calculate asset retirement obligations.
● We tested the completeness and accuracy of the underlying data used in management’s asset retirement obligations calculation.
● We evaluated the reasonableness of significant judgments including inflation rate, credit-adjusted risk-free rate, reclamation cost estimates and timing of expected reclamation activities.
● We interviewed the Company’s professionals with specialized skill and knowledge regarding the regulatory requirements and mine plans.
Impairment of coal properties
As described further in Notes 1 and 19 to the consolidated financial statements, long-lived assets are evaluated for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. When performing the impairment assessments, the Company projects undiscounted cash flows at the asset group level. If the asset group is determined not to be recoverable, the Company, with the assistance of third-party valuation specialists, performs an analysis of the fair value of the asset group and recognizes an impairment loss when the fair value of the asset group is less than the carrying value. As of December 31, 2024, the Company recorded asset impairment charges of $215.1 million associated with its coal properties. The identification of impairment indicators and the calculation of the amount of impairment requires significant management judgment. We identified the long-lived asset impairment assessment of coal properties as a critical audit matter.
The principal consideration for our determination that the long-lived asset impairment assessment of coal properties is a critical audit matter is due to the uncertainties and significant management judgment when estimating the fair value of the coal properties. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to management’s forecasted future revenues and cash flows and evaluation of the reasonableness of the valuation model used. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and evaluating the audit evidence obtained.
Our audit procedures related to the long-lived asset impairment assessment of coal properties included the following, among others:
● We tested the design and operating effectiveness of internal controls over the identification of impairment indicators, estimation of fair value, and recognition processes.
● With the assistance of professionals with specialized skill and knowledge, we tested management’s process for calculating the asset impairment of coal properties, including evaluating the reasonableness of the valuation methodology and certain significant assumptions used in the calculations including the discount rate applied to the estimated future cash flows.
● We evaluated the qualifications of the third-party specialist engaged by the Company based on their credentials and experience.
● We evaluated the reasonableness of significant judgments including forecasted revenue and operating expenses. We tested whether these forecasts were reasonable and consistent with historical performance and industry projections and conditions found in industry reports, as applicable.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2022.
Tulsa, Oklahoma
March 17, 2025
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
Consolidated Balance Sheets
As of December 31,
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents
$
7,232
$
2,842
Restricted cash
4,921
4,281
Accounts receivable
15,438
19,937
Inventory
36,685
23,075
Parts and supplies
39,104
38,877
Prepaid expenses
1,478
2,262
Assets held-for-sale
-
1,540
Total current assets
104,858
92,814
Property, plant and equipment:
Land and mineral rights
70,307
115,486
Buildings and equipment
429,857
537,131
Mine development
92,458
158,642
Finance lease right-of-use assets
13,034
12,346
Total property, plant and equipment
605,656
823,605
Less - accumulated depreciation, depletion and amortization
(347,952)
(334,971)
Total property, plant and equipment, net
257,704
488,634
Equity method investments
2,607
2,811
Other assets
3,951
5,521
Total assets
$
369,120
$
589,780
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net
$
4,095
$
24,438
Accounts payable and accrued liabilities
44,298
62,908
Current portion of lease financing
6,912
3,933
Contract liabilities - current
97,598
66,316
Total current liabilities
152,903
157,595
Long-term liabilities:
Bank debt, net
37,394
63,453
Convertible notes payable
-
10,000
Convertible notes payable - related party
-
9,000
Long-term lease financing
8,749
8,157
Deferred income taxes
-
9,235
Asset retirement obligations
14,957
14,538
Contract liabilities - long-term
49,121
47,425
Other
1,711
1,789
Total long-term liabilities
111,932
163,597
Total liabilities
264,835
321,192
Commitments and contingencies (Note 22)
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
-
-
Common stock, $.01 par value, 100,000 shares authorized; 42,621 and 34,052 issued and outstanding, as of December 31, 2024 and December 31, 2023, respectively
Additional paid-in capital
189,298
127,548
Retained earnings (deficit)
(85,439)
140,699
Total stockholders’ equity
104,285
268,588
Total liabilities and stockholders’ equity
$
369,120
$
589,780
The accompanying notes are an integral part of these Consolidated Financial Statements
Hallador Energy Company
Consolidated Statements of Operations
For the years ended December 31,
(in thousands, except per share data)
SALES AND OPERATING REVENUES:
Electric sales
$
261,527
$
267,927
Coal sales
137,448
361,926
Other revenues
5,419
5,025
Total sales and operating revenues
404,394
634,878
EXPENSES:
Fuel
49,343
103,388
Other operating and maintenance costs
118,364
199,855
Cost of purchased power
10,888
-
Utilities
15,914
17,730
Labor
116,164
152,417
Depreciation, depletion and amortization
65,626
67,211
Asset retirement obligations accretion
1,628
1,804
Exploration costs
General and administrative
26,527
26,159
Asset impairment
215,136
-
(Gain) loss on disposal or abandonment of assets, net
(50)
Settlement of litigation
2,750
-
Total operating expenses
622,550
569,866
INCOME (LOSS) FROM OPERATIONS
(218,156)
65,012
Interest expense (1)
(13,850)
(13,711)
Loss on extinguishment of debt
(2,790)
(1,491)
Equity method investment (loss)
(746)
(552)
NET INCOME (LOSS) BEFORE INCOME TAXES
(235,542)
49,258
INCOME TAX EXPENSE (BENEFIT):
Current
(169)
(164)
Deferred
(9,235)
4,629
Total income tax expense (benefit)
(9,404)
4,465
NET INCOME (LOSS)
$
(226,138)
$
44,793
NET INCOME (LOSS) PER SHARE:
Basic
$
(5.72)
$
1.35
Diluted
$
(5.72)
$
1.25
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic
39,504
33,133
Diluted
39,504
36,827
(1) Interest Expense:
Interest on bank debt
$
9,286
$
8,636
Other interest
2,817
1,842
Amortization:
Amortization of debt issuance costs
1,747
3,233
Total amortization
1,747
3,233
Total interest expense
$
13,850
$
13,711
The accompanying notes are an integral part of these Consolidated Financial Statements
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
$
(226,138)
$
44,793
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax (benefit)
(9,235)
4,629
Equity method investment (loss)
Cash distribution - equity method investment
-
Depreciation, depletion and amortization
65,626
67,211
Asset impairment
215,136
-
Loss on extinguishment of debt
2,790
1,491
(Gain) loss on disposal or abandonment of assets, net
(50)
Amortization of debt issuance costs
1,747
3,233
Asset retirement obligations accretion
1,628
1,804
Cash paid on asset retirement obligation reclamation
(1,407)
(3,384)
Stock-based compensation
4,454
3,554
Amortization of contract asset and contract liabilities
(70,203)
(97,018)
Director fees paid in stock
-
Change in current assets and liabilities:
Accounts receivable
4,499
9,952
Inventory
(13,610)
15,548
Parts and supplies
(227)
(10,582)
Prepaid expenses
1,186
Accounts payable and accrued liabilities
(14,580)
(18,992)
Contract liabilities
103,181
33,804
Other
Net cash provided by operating activities
$
65,934
$
59,414
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
(continued)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
$
(53,367)
$
(75,352)
Proceeds from sale of equipment
4,239
Proceeds from held-for-sale assets
3,200
-
Investment in equity method investments
(542)
-
Net cash used in investing activities
(46,470)
(75,290)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt
(147,000)
(59,713)
Borrowings of bank debt
99,500
66,000
Payments on lease financing
(5,633)
-
Proceeds from sale and leaseback arrangement
5,134
11,082
Issuance of related party notes payable
5,000
-
Payments on related party notes payable
(5,000)
-
Debt issuance costs
(673)
(6,013)
ATM offering
34,515
7,318
Taxes paid on vesting of RSUs
(277)
(2,101)
Net cash provided by (used in) financing activities
(14,434)
16,573
Increase in cash, cash equivalents, and restricted cash
5,030
Cash, cash equivalents, and restricted cash, beginning of year
7,123
6,426
Cash, cash equivalents, and restricted cash, end of year
$
12,153
$
7,123
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents
$
7,232
$
2,842
Restricted cash
4,921
4,281
$
12,153
$
7,123
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest
$
10,511
$
9,966
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense
$
$
1,882
The accompanying notes are an integral part of these Consolidated Financial Statements
Hallador Energy Company
Consolidated Statement of Stockholders’ Equity
(in thousands)
Additional
Retained
Total
Common Stock Issued
Paid-in
Earnings
Stockholders’
Shares
Amount
Capital
(Deficit)
Equity
BALANCE, DECEMBER 31, 2022
32,983
$
$
118,788
$
95,906
$
215,024
Stock-based compensation
-
-
3,554
-
3,554
Stock issued on vesting of RSUs
(5)
-
-
Taxes paid on vesting of RSUs
(198)
(2)
(2,099)
-
(2,101)
Stock issued in ATM offering
7,310
-
7,318
Net income
-
-
-
44,793
44,793
BALANCE, DECEMBER 31, 2023
34,052
$
$
127,548
$
140,699
$
268,588
Stock-based compensation
-
-
4,454
-
4,454
Stock issued on vesting of RSUs
(4)
-
-
Taxes paid on vesting of RSUs
(159)
(2)
(275)
-
(277)
Stock issued on redemption of convertible notes
3,672
22,957
-
22,993
Stock issued in ATM offering
4,655
34,468
-
34,515
Stock issued for director fees
-
-
Net loss
-
-
-
(226,138)
(226,138)
BALANCE, DECEMBER 31, 2024
42,621
$
$
189,298
$
(85,439)
$
104,285
The accompanying notes are an integral part of these Consolidated Financial Statements
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2024 AND 2023
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Consolidation
The consolidated financial statements include the accounts of Hallador Energy Company (hereinafter, “we”, “our” or “us”) and our wholly owned subsidiaries Hallador Power Company, LLC (“Hallador Power”), Sunrise Coal, LLC (“Sunrise”), and Hourglass Sands, LLC (“Hourglass”), as well as Hallador Power and Sunrise’s wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Hallador Power is engaged in the production of coal-fired electric power generation located in Sullivan County, Indiana. Sunrise is engaged in the production of steam coal from mines located in western Indiana.
Segment Information
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC (“Sunrise Energy”), a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.
During the fourth quarter of 2024, we sold our held-for-sale wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River. For further information, see “Note 21 - Assets Held For Sale” below.
The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant (“Merom”).
The Coal Operations reportable segment includes our currently operating underground mining complex Oaktown 1 among other mining complexes and locations which operated throughout the year ended December 31, 2023 and were subsequently idled during the year ended December 31, 2024.
Reclassifications
Amounts in the prior years consolidated financial statements are reclassified whenever necessary to conform to the current year’s presentation. Any reclassification adjustments had no impact on prior year total assets, liabilities, net income or shareholders’ equity.
In the fourth quarter of 2024, the Company made certain reclassifications that reduced “other operating and maintenance costs” and increased “depreciation, depletion and amortization” on the Consolidated Statements of Operations for certain assets with a useful life of one to three years. The entire adjustment is reflected in the fourth quarter of 2024. Previous interim periods and prior year were not adjusted as the amounts were not material. The amounts recognized in the fourth quarter of 2024 that are related to the first, second and third quarters of 2024 were $2.1 million, $2.6 million and $1.7 million, respectively.
Cash and Cash Equivalents
Cash and cash equivalents include investments with maturities when purchased of three months or less. Cash balances at individual banks may exceed the federally insured limit by the Federal Deposit Insurance Corporation. The Company has not experienced any material losses in such accounts.
Restricted Cash
Restricted cash represents cash held by third parties primarily for future workers’ compensation claims and MISO escrow payments. Workers’ compensation is based estimated claim liabilities and MISO escrow payments are based on power purchased or sold related to power demand and our power purchase agreements (“PPA”).
Accounts Receivable
The timing of revenue recognition, billings and cash collections results in accounts receivable from customers. Customers are invoiced as power is delivered or as coal is shipped or at periodic intervals in accordance with contractual terms. Coal invoices typically include customary adjustments for the resolution of price variability, such as coal quality thresholds. Payments are generally received within thirty days of invoicing. Historically, credit losses have been insignificant. No charges for credit losses were recognized during the years ended December 31, 2024 or 2023.
Inventory and Parts and Supplies
Inventory and parts and supplies are valued at the lower of cost or net realizable value determined using the first-in first-out method. Inventory costs include labor, supplies, operating overhead, and other related costs incurred at or on behalf of the mining location or plant, including depreciation, depletion, and amortization of equipment, buildings, mineral rights, and mine development costs.
Contract Asset - Coal Purchase Agreement
Contract Asset - Coal Purchase Agreement, is the result of a coal purchase agreement with Hoosier whereby we purchased coal from Hoosier through May 31, 2023, at fixed prices which were below market prices at the date of entry into the agreement. This agreement was entered into as consideration in our 2022 acquisition of Merom. The asset was amortized to inventory as coal was purchased over the term of the agreement as the contract was fulfilled. During the years ended December 31, 2023, $19.6 million was amortized, of which $30.7 million was recognized in operating expenses on the consolidated statements of operations. The Coal Purchase Agreement term was from October 21, 2022 to May 31, 2023.
Prepaid Expenses
Prepaid expenses include prepaid insurance and other prepaid balances with vendors for various services paid for in advance of use.
Advanced Royalties
Coal leases that require minimum annual or advance payments and are recoverable from future production are generally deferred and charged to expense as the coal is subsequently produced. Advance royalties are included in other assets.
Plant Equipment and Mining Properties
The values of our Hallador Power property, plant and equipment were initially recorded at relative fair value based on the consideration paid upon closing of the acquisition of Merom in 2022. Other equipment is recorded at cost. Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase the productivity of the assets are expensed as
incurred. Most power plant equipment is depreciated over the remaining estimated useful life of the Merom at the time of equipment acquisition, or seven to nine years.
Mining properties are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase the productivity of the assets are expensed as incurred. Other than land and most mining equipment, mining properties are depreciated using the units-of-production method over the estimated recoverable reserves. Most surface and underground mining equipment is depreciated using estimated useful lives ranging from three to fifteen years.
The Company reviews long-lived assets for impairment whenever events or changes in circumstances, known as triggering events, indicate that the carrying amount of a long-lived asset or asset group, may not be recoverable. Management considers various factors when determining if long-lived assets should be evaluated for impairment, including a significant adverse change in the business climate or industry conditions (such as sustained decreases in commodity prices, volatility in energy costs, and the global economy), a current period operating or cash flow loss combined with a history of losses, a significant adverse change in the extent or manner in which an asset is used, or a current expectation that the asset will be sold or otherwise disposed of before the end of its useful life.
During the fourth quarter of 2024, the Company completed a review of its coal mining facilities and future mining plans. The impairment analysis was based upon our coal mining operating plans, market driven pricing and cost trends. As part of that analysis, the Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in 2024. See “Note 19 - Impairment of Coal Properties” below related to our 2024 impairment. There were no long-lived asset impairments during the year ended December 31, 2023.
Mine Development
Costs of developing new mines, including asset retirement obligation assets, or significantly expanding the capacity of existing mines, are capitalized and amortized using the units-of-production method over estimated recoverable reserves.
Asset Retirement Obligations (“ARO”) - Reclamation
At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to mine development. Obligations are typically incurred when the Company commences development of underground and surface mines and include reclamation of support facilities, refuse areas and slurry ponds.
Obligations are reflected at the present value of their future cash flows. The Company reflects accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. The Company uses the credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Federal and state laws require that mines be reclaimed in accordance with specific standards and approved reclamation plans, as outlined in mining permits. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.
The Company reviews its ARO at least annually and reflects revisions for permit changes, changes in estimated reclamation costs and changes in the estimated timing of such costs. The change in estimate for the year ended December 31, 2023, was a result of a change in timing and acreage of expected reclamation of Merom. There was no change in estimate for the year ended December 31, 2024. In the event the Company is not able to perform reclamation, it has surety bonds at December 31, 2024 totaling $30.8 million to cover ARO. The undiscounted asset retirement obligation was $26.1 million and $26.6 million at December 31, 2024 and 2023, respectively.
The table below (in thousands) reflects the changes to ARO for the periods presented:
Year Ended December 31,
Balance, beginning of year
$
16,688
$
20,834
Accretion
1,628
1,804
Change in estimate
-
(2,566)
Payments
(1,407)
(3,384)
Balance, end of year
16,909
16,688
Less current portion
(1,952)
(2,150)
Long-term balance, end of year
$
14,957
$
14,538
Contract Liabilities
Contract Liabilities include the PPA with Hoosier whereby Hallador Power is selling power to Hoosier through 2025 at fixed prices which were below market prices at the date the parties entered into the agreement. Hallador Power also agreed to a reduction in future capacity payments as part of the acquisition consideration. These agreements were entered into as consideration for the acquisition of Merom in 2022. The agreement was amended August 31, 2023 to extend through 2028. The amendment included additional obligations to Hoosier of $186.6 million, or $56.00 per MWh, as of December 31, 2024. The power purchase agreement liability is amortized to electric sales revenue pro-rata over the term of the agreement as the contract is fulfilled. During the years ended December 31, 2024 and 2023, amortization of the power purchase agreement contract liability totaled $47.1 million and $70.5 million, respectively. The Power Purchase Agreement term is from October 21, 2022 to May 31, 2028. The Capacity Payment Reductions occurred on May 31, 2023 and November 30, 2023 in the amount of $7.5 million each. The contract liability relating to this contract totaled $43.5 million as of December 31, 2024.
We also have contract liabilities arising from PPA’s for capacity and physically delivered power entered into whereas the customers made advance payments to Hallador Power. These contracts that have delivery periods through the Spring shoulder season ending May 31, 2025. The liability will be amortized to electric sales revenue over the remaining term of the agreement as the contract is fulfilled. The contract liability relating to these contracts totaled $42.0 million as of December 31, 2024.
During the year ended December 31, 2024, the Company entered into a $60.0 million prepaid physically delivered power contract. The power purchase agreement term is from June 1, 2025 through December 31, 2026. The power purchase agreement liability will be amortized to electric sales revenue pro-rata over the term of the agreement as the contract is fulfilled. The contract liability, including $1.2 million of implied interest relating to this contract totaled $61.2 million as of December 31, 2024.
Commitments and Contingencies
From time to time, we are involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. We have concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on our business, financial position, results of operations or liquidity. See “Note 22 - Contingencies” related to our decision to settle certain litigation in February of 2025.
Fuel Costs
Fuel costs in our Electric Operations include coal purchased from Sunrise Coal and third parties to operate Merom. Fuel costs in our Coal Operations include mainly diesel, as well as natural gas and petroleum to operate our coal mines. These fuel costs are expensed as the fuel is used. The difference between Sunrise Coal’s cost to produce coal and the contracted sales price to Hallador Power is eliminated from fuel costs on the Consolidated Statements of Operations.
Income Taxes
Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on pretax financial income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting and principally relate to differences in the tax basis of assets and liabilities and their reported amounts, using enacted tax rates in effect for the year in which differences are expected to reverse.
Net Income per Share
Basic earnings per share (“EPS”) are computed by dividing net earnings by the weighted average number of common shares outstanding for the period.
Diluted EPS attributable to common shareholders is computed by adjusting net earnings by the weighted average number of common shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include shares of restricted stock units as if the units issued by us were vested and convertible debt. We apply the treasury stock method to account for the dilutive impact of its restricted stock units and the if converted method for its convertible notes. Anti-dilutive securities are excluded from diluted EPS. As a result of determining the effect of potentially dilutive securities, in certain periods, diluted net loss per share is the same as the basic net loss per share for the periods presented.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual amounts could differ from those estimates. The most significant estimates included in the preparation of the financial statements relate to: (i) deferred income tax accounts, (ii) coal reserves, (iii) SMCRA and other state statutes, (iv) depreciation, depletion, and amortization, (v) the lower of cost or net realizable value for our inventory (vi) estimates used in our impairment analysis, and (vii) estimates used in the calculation of ARO.
Long-term Contracts
Power Operations
As of December 31, 2024, we are committed to supply the following long-term delivered energy and capacity related to Hoosier and third-party customers:
Annual plant energy generation (in MWh) (in millions)
6.0
6.0
6.0
6.0
6.0
Hoosier PPA delivered energy (in MWh) (in millions)
1.7
1.6
1.3
0.4
-
Percentage of annual plant energy generation
28%
27%
22%
7%
0%
Other customers delivered energy (in MWh) (in millions)
0.6
1.8
0.5
0.7
0.3
Percentage of annual plant energy generation
10%
30%
8%
12%
5%
Plant capacity (in MW)
Hoosier PPA Capacity (in MW)
-
Percentage of annual plant capacity
13%
13%
14%
6%
0%
Other customers capacity (in MW)
Percentage of annual plant capacity
9%
11%
15%
15%
2%
For 2024, we derived 89% of our delivered energy and 88% of our capacity sales revenue from three and four customers, respectively, each of which representing at least 10% of sales revenue. At December 31, 2024, 100% of our accounts receivable were with three customers.
For 2023, we derived 100% of our electric delivered energy generation from Hoosier and 91% of our capacity sales revenue from three customers, each representing at least 10% of capacity sales revenue. For the year ended December 31, 2023, 100% of our electric sales and accounts receivable were with two customers.
Coal Operations
As of December 31, 2024, we are committed to supplying third-party customers 8.4 million tons of coal through 2028. There are no coal contracts with price reopeners at December 31, 2024. In addition, we are committed to supplying 9.2 million tons of coal to Merom through 2028. All committed tons to Merom are priced based upon the terms of the intercompany sales transactions.
For 2024, we derived 94% of our third-party coal sales from three customers, each representing at least 10% of coal sales. At December 31, 2024, 98% of our coal operations accounts receivable was from four customers, each representing more than 10%.
For 2023, we derived 93% of our third-party coal sales from five customers, each representing at least 10% of coal sales. At December 31, 2023, 85% of our coal operations accounts receivable was from four customers, each representing more than 10%.
Stock-based Compensation
Stock-based compensation for restricted stock units is measured at the grant date based on the fair value of the award and is recognized as expense over the applicable vesting period of the stock award (generally two to four years) using the straight-line method.
Recent Accounting Pronouncements - Adopted
The Company has adopted Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ("ASU 2023-07"), which is effective retrospectively for the year end December 31, 2024. ASU 2023-07 primarily enhances disclosures about significant segment expenses regularly provided to the chief operating decision maker ("CODM"), the amount and composition of other segment items, and the title and position of the CODM. The Company updated the “Segment of Business” footnote below to reflect changes for what the CODM reviews on a regular basis. The Company updated its prior year information to conform to the current year presentation. See “Note 20 - Segments of Business” for enhanced disclosures associated with the adoption of ASU 2023-07.
Recent Accounting Pronouncements Not Yet Adopted
In December 2023, the Financial Accounting Standards Board ("FASB") issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures ("ASU 2023-09"). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-09, but do not expect it to have a material effect on our consolidated financial statements.
In November 2024, the FASB issued ASU 2024-04, Debt - Debt With Conversion and Other Options (Subtopic 470-20): Induced Conversion of Convertible Debt Instruments. The objective of the standard is to improve the relevance and consistency in application of the induced conversion guidance in Subtopic 470-20, Debt with Conversion and Other
Options. This standard will affect entities that settle convertible debt instruments for which the conversion privileges are changed to induce conversion. The guidance will be effective for annual reporting periods beginning after December 15, 2025, and interim reporting periods within those annual reporting periods. The Company is currently evaluating the impact of the new standard on its financial statements and related disclosures.
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting-Comprehensive Income-Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory, employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its financial statement disclosures.
(2) INVENTORY
Inventory is valued at lower of cost or net realizable value (“NRV”). As of December 31, 2024 and 2023, coal inventory includes NRV adjustments of $0.3 million and $2.0 million, respectively.
(3) OTHER LONG-TERM ASSETS (IN THOUSANDS)
December 31,
Advanced coal royalties
$
3,906
$
5,521
Other
-
Total other assets
$
3,951
$
5,521
(4) BANK DEBT
On March 13, 2023, we executed an amendment (“March 13th Amendment”) to our credit agreement with PNC Bank, National Association (in its capacity as administrative agent, "PNC"). The primary purpose of the March 13th Amendment was to convert $35.0 million of the outstanding balance on the revolver into a new term loan with a maturity date of March 31, 2024, and extend the maturity date of the revolver to May 31, 2024. The March 13th Amendment also reduced the total capacity under the revolver to $85.0 million and waived the maximum annual capital expenditure covenant for 2022 and increased the covenant for 2023 to $75.0 million. Subsequent to December 31, 2022, and prior to the effective date of the March 13th Amendment, we had borrowed an additional $17.0 million under the revolver. Additionally, the March 13th Amendment provided for the transition in interest rates from the London Interbank Offered Rate (“LIBOR”) to the Secured Overnight Financing Rate (“SOFR”) based pricing with ranges from SOFR plus 4.00% to SOFR plus 5.00%, depending on our leverage ratio.
On August 2, 2023, we executed an additional amendment (“August 2nd Amendment”) to our credit agreement with PNC, which was accounted for as a debt extinguishment. The primary purpose of the August 2nd Amendment was to convert $65.0 million of the outstanding funded debt into a new term loan with a maturity of March 31, 2026, and enter into a revolver of $75.0 million with a maturity of July 31, 2026. The August 2nd Amendment increased the maximum annual capital expenditure limit to $100.0 million.
Prior to the March 13th Amendment, bank debt was comprised of term debt ($5.5 million as of December 31, 2022) and a $120 million revolver ($79.7 million borrowed as of December 31, 2022). The term debt amortization was to conclude with the final payment of $5.5 million in March 2023. The revolver was to mature in September 2023. Under the provision of the March 13th Amendment, bank debt was comprised of term debt ($35.0 million as of March 13, 2023) and an $85.0 million revolver ($40.2 million borrowed as of March 13, 2023). The term debt required payment of $10.0 million in June 2023 each quarter thereafter in 2023 and $5.0 million by March 31, 2024. Under the August 2nd Amendment, bank debt was comprised of term debt ($58.5 million borrowed as of December 31, 2023) and a $75.0
million revolver ($33.0 million borrowed as of December 31, 2023). The term debt requires quarterly payments of $6.5 million beginning April 2024 through March 2026.
On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC which was accounted for as a debt modification. The primary purpose of the First Amendment was to provide the Company with short-term covenant relief to pursue additional liquidity. The First Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repays outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a maximum of $20.0 million. These required prepaid forward power sale Term Loan repayments, if any, will take the place of the $6.5 million quarterly Term Loan payments. During the fourth quarter of 2024, the Company entered into a prepaid forward power sales contract in which $20.0 million of the proceeds were used to pay our required $6.5 million quarterly loan payments through the third quarter of 2025 and also reduced our fourth quarter 2025 payment to $6.0 million. Furthermore, the First Amendment defines certain administrative changes which include, among other things, added requirements related to reporting, third party financial advisors, and appraisals on coal and power assets.
Bank debt was reduced by $47.5 million and increased by $6.3 million during the years ended December 31, 2024 and 2023, respectively.
Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.
Liquidity
As of December 31, 2024, we had additional borrowing capacity of $30.6 million under the revolver and total liquidity of $37.8 million. Our additional borrowing capacity is net of $19.4 million in outstanding letters of credit as of December 31, 2024 that were required to maintain surety bonds. Liquidity consists of additional borrowing capacity and cash and cash equivalents.
Fees
Unamortized bank fees and other costs incurred in connection with our initial facility totaled $4.3 million. Additional costs incurred with the First Amendment totaled $0.6 million. These unamortized bank fees were deferred and are being amortized over the term of the loan.
During 2023 we recognized a loss on extinguishment of debt of $1.5 million for the write-off of unamortized loan fees related to the August 2nd Amendment to our credit agreement, which was accounted for as a debt extinguishment. The remaining costs were deferred and are being amortized over the term of the loan. Unamortized bank fees as of December 31, 2024 and 2023, were $2.5 million and $3.6 million, respectively.
Bank debt, less debt issuance costs, is presented below (in thousands):
December 31,
Current bank debt
$
6,000
$
26,000
Less unamortized debt issuance cost
(1,905)
(1,562)
Net current portion
$
4,095
$
24,438
Long-term bank debt
$
38,000
$
65,500
Less unamortized debt issuance cost
(606)
(2,047)
Net long-term portion
$
37,394
$
63,453
Total bank debt
$
44,000
$
91,500
Less total unamortized debt issuance cost
(2,511)
(3,609)
Net bank debt
$
41,489
$
87,891
Covenants
The First Amendment, among other things, provided the Company with short-term covenant relief to pursue additional liquidity. The First Amendment waived the Company’s Leverage Ratio requirement for the third and fourth quarters of 2024, increased the threshold to 5.50 to 1.00 for the first quarter of 2025, and decreased the threshold back to 2.25 to 1.00 for each fiscal quarter thereafter. Additionally, the Debt Service Coverage Ratio requirement (1.25 to 1.00) was waived from third quarter of 2024 through the first quarter of 2025. The First Amendment also added additional financial covenants which include: (i) a maximum First Lien Leverage Ratio for the first quarter of 2025, calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 3.50 to 1.00; (ii) a minimum liquidity requirement of $10.0 million, beginning on the First Amendment execution date and ending when the second quarter of 2025 compliance certificate is received; and (iii) a minimum quarterly EBITDA requirement, as defined in the First Amendment, of $5.0 million for the third quarter of 2024 through the first quarter of 2025.
As of December 31, 2024, our liquidity of $37.8 million and quarterly EBITDA of $6.2 million were in compliance with the requirements of the Credit Agreement.
Interest Rate
The interest rate on the facility ranges from SOFR plus 4.00% to SOFR plus 5.00%, depending on our Leverage Ratio. As of December 31, 2024, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 9.48%.
Future Maturities (in thousands):
$
6,000
38,000
-
Total
$
44,000
(5) ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (IN THOUSANDS)
December 31,
Accounts payable
$
24,291
$
43,636
Accrued property taxes
4,185
2,987
Accrued payroll
3,258
6,575
Workers' compensation reserve
4,321
3,629
Group health insurance
1,700
2,300
Asset retirement obligation - current portion
1,952
2,150
Other
4,591
1,631
Total accounts payable and accrued liabilities
$
44,298
$
62,908
(6) REVENUE
Revenue from Contracts with Customers
We account for a contract with a customer when the parties have approved the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all of the consideration will be collected. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer.
Electric operations
We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), is met at the time a PPA is executed by the parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.
We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract capacity performance obligations and daily, based on an output method of MWh of electricity delivered.
For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier. For the delivered energy to all other customers, we recognize revenue daily for the actual delivered electricity.
Coal operations
Our coal revenue is derived from sales to customers of coal produced at its facilities. Our customers typically purchase coal directly from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.
Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as British thermal unit (“Btu”) factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.
Disaggregation of Revenue
Revenue is disaggregated by revenue source for our electric operations and primary geographic markets for our coal operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of its revenue and cash flows are affected by economic factors.
Electric operations
December 31,
Delivered energy (including contract liability amortization)
$
203,434
$
211,772
Capacity
58,093
56,155
Total Electric Operations sales
$
261,527
$
267,927
Coal operations
December 31,
Outside third-party Indiana customers
$
59,045
$
144,942
Customers in Florida, North Carolina, Alabama and Georgia
78,403
216,984
Total Coal Operations sales
$
137,448
$
361,926
Performance Obligations
Electric Operations
We concluded that each megawatt hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the customer.
In accordance with our Asset Purchase Agreement (“Hoosier APA”) with Hoosier in which Hallador Power shall sell, and Hoosier shall buy, delivered energy quantities through 2025 at the contract price, which is $34.00 per MWh. We have remaining delivered energy obligations to Hoosier totaling $59.0 million through 2025 as of December 31, 2024. The agreement was amended August 31, 2023 to extend through 2028. The amendment included additional obligations to Hoosier of $186.6 million, or $56.00 per MWh, as of December 31, 2024.
In addition to delivered energy, under the Hoosier APA, Hallador Power shall provide a stand-ready obligation to provide electricity to MISO, also known as contract capacity. The contract capacity that Hallador Power shall provide to Hoosier is 917 megawatts (“MW”) for contract year one, and on average 300 MW for contract years two to four. Hoosier shall pay Hallador Power the capacity price of $5.80 per kilowatt month for the contract capacity. We have remaining capacity obligations to Hoosier through 2025 totaling $18.6 million as of December 31, 2024. The agreement was amended August 31, 2023, to extend through 2028, with additional capacity obligation to Hoosier of $59.5 million as of December 31, 2024, at a price of $7.02 per kilowatt month for the contract capacity.
During the second quarter of 2024, the Company entered into an 11-month, $45.0 million prepaid physically delivered power contract in which Hallador will provide a total of 1,302,480 MWh. Since the period between customer payment
and the transfer of promised services is less than one year, we have elected the practical expedient which allows us to not assess whether a customer contract has a significant financing component.
During the fourth quarter of 2024, we entered into a 19-month, $60.0 million prepaid physically delivered power contract in which Hallador will provide a total of 1,918,200 MWh. As the total amount paid up-front by the customer differs from the stand-alone selling price of the transferred power, the Company concluded the contract contains a significant financing component. The contract liability associated with the $60.0 million prepayment will be accreted over the agreement term based upon the Company’s incremental borrowing rate which approximates 10.3%, and the accretion will be separately recognized as interest expense.
The Company also has additional PPA’s with customers for capacity whereas the customers made advance payments to Hallador Power in the amounts of $35.4 million and $35.3 million during the years ended December 31, 2024 and 2023, respectively. The delivery periods related to these prepayments are June 1 through May 31. The liability will be amortized to electric sales revenue as the contract is fulfilled.
Additionally, during the fourth quarter of 2024, we entered into three contracts in the amount of $52.1 million to provide a total of 1,389,600 MWh from December 2024 through December 2025. We have energy and capacity obligations to customers, excluding the Hoosier APA, through 2029 totaling $230.8 million and $131.3 million, respectively, as of December 31, 2024.
Coal Operations
A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.
We recognize revenue at a point in time as the customer does not have control over the asset at any point during the fulfillment of the contract. For substantially all of our customers, this is supported by the fact that title and risk of loss transfer to the customer upon loading of the truck or railcar at the mine. This is also the point at which physical possession of the coal transfers to the customer, as well as the right to receive substantially all benefits and the risk of loss in ownership of the coal.
We have remaining coal sales performance obligations relating to fixed priced contracts to third-party customers of approximately $460.4 million, which represent the average fixed prices on our committed contracts as of December 31, 2024. We expect to recognize approximately 32.7% of this coal sales revenue in 2025, with the remainder recognized through 2028.
The coal tons used to determine the remaining performance obligations are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.
Contract Balances
Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.
Under the typical payment terms of our contracts with customers, the customer pays us a base price for the coal, increased or decreased for any quality adjustments, electricity, or capacity. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our consolidated balance sheets.
December 31,
Accounts receivable from contracts with customers
$
15,438
$
19,937
$
29,889
Contract assets
-
-
19,567
Contract liabilities - current
97,598
66,316
123,599
Contract liabilities - long-term
49,121
47,425
84,096
Total contract liabilities
146,719
113,741
207,695
We received payments related to advanced capacity and advanced physically delivered energy of $160.0 million and $41.2 million for the years ending December 31, 2024 and 2023, respectively. Of the amount of contract liabilities that we recorded as of the beginning of the period, we recognized $70.2 million and $123.6 million of electric revenue related to these advance contract liability payments for the years ended December 31, 2024 and 2023, respectively. We do not currently have any other contracts in place where it would transfer coal, electricity or capacity in advance of knowing the final price, and thus do not have any other contract assets recorded. Contract liabilities also arise when consideration is received in advance of performance.
(7) INCOME TAXES
Our income tax is different than the expected amount computed using the applicable federal statutory income tax rate of 21%. The reasons for and effects of such differences for the years ended December 31st are below (in thousands):
Expected amount
$
(49,464)
$
10,344
State income taxes, net of federal benefit
(9,059)
1,246
Percentage depletion
-
(3,348)
Change in valuation allowance
49,695
(3,681)
Stock-based compensation
(844)
Return to provision adjustments
(722)
Nondeductible items
-
Other
(150)
Total income tax expense
$
(9,404)
$
4,465
The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following at December 31st (in thousands):
Deferred tax assets:
Net operating loss
$
32,725
$
20,029
Power contracts
10,828
23,302
Compensation
1,955
2,287
Accrued liabilities
ARO liabilities
2,293
2,798
Lease liabilities
3,938
3,044
Coal properties
26,191
-
Other
5,215
2,016
Total deferred tax assets
83,568
54,046
Valuation allowance
(49,695)
-
Deferred tax assets, net of valuation allowance
33,873
54,046
Deferred tax liabilities:
Coal properties
-
(28,535)
Power properties
(27,960)
(31,126)
Investment partnerships
(531)
(549)
ROU assets
(5,382)
(3,071)
Total deferred tax liabilities
(33,873)
(63,281)
Net deferred tax liability
$
-
$
(9,235)
Our effective tax rate (“ETR”) for 2024 and 2023 was approximately 4% and 9% respectively. The tax rate for the years ended December 31, 2024 and 2023 are not predictive of future tax rates. Our ETR differs from the statutory rate due to statutory depletion in excess of tax basis, return to provision adjustments, stock-based compensation and changes in the valuation allowance. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income taxes.
We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations. Due to historical cumulative losses over the prior three years as well as projected losses over the next year, we believe that it is not more likely than not that the benefit from certain federal and state deferred tax assets will be realized. As such, we have recorded a full valuation allowance as of December 31, 2024.
The remaining federal NOLs generated in pre-2018 years of $19.5 million can offset 100% of future years’ taxable income. The federal NOLs generated in post 2017 years of $104.9 million can offset 80% of future years’ taxable income. The pre-2018 federal NOLs will expire in varying amounts from 2035 to 2037 if they are not utilized. Indiana NOLs, which total $168.0 million, have a 20-year carryforward period and will expire in the years 2034 to 2044 if they are not utilized.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions, to determine whether the positions will be more likely than not be sustained by the applicable tax authority. Tax positions not deemed to meet the more-likely-than-not threshold are not recorded as a tax benefit or expense in the current year. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deduction will be sustained on audit and do not anticipate any adjustments that will result in a material change to its consolidated financial position. While not material, we record any penalties and interest as general and administrative expense. Tax returns filed with the Internal Revenue Service and state entities generally remain subject to examination for three years after filing.
(8) STOCK COMPENSATION PLANS
Restricted Stock Units (RSUs)
The table below shows the number of RSUs available for issuance at December 31, 2024:
Total authorized RSUs in Plan approved by shareholders
4,850,000
Stock issued out of the Plan from vested grants
(3,761,430)
Non-vested grants
(1,034,486)
RSUs available for future issuance
54,084
Non-vested grants at December 31, 2022
1,056,937
Granted - weighted average share price on grant date was $9.30
312,147
Vested
(472,721)
Forfeited
(38,000)
Non-vested grants as of December 31, 2023
858,363
Awarded - weighted average share price on award date was $5.69
599,013
Vested
(380,390)
Forfeited
(42,500)
Non-vested grants as of December 31, 2024
1,034,486
RSU Vesting Schedule
Vesting Year
RSUs Vesting
682,068
176,210
176,208
1,034,486
Shares vested in 2024 had a value of $2.0 million based on the share price of $5.33 on their vesting dates. Under our RSU plan, participants are allowed to relinquish shares to pay for their required statutory income taxes.
The outstanding RSUs have a value of $8.9 million based on the March 10, 2025 closing stock price of $8.60.
For the years ended December 31, 2024 and 2023, stock-based compensation was $4.5 million and $3.6 million, respectively.
As of December 31, 2024, unrecognized stock compensation expense to be recognized over the remaining 3-year vesting period was $2.7 million, and we had 54,084 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities. Forfeitures are recognized as they occur.
Stock Options
We have no stock options outstanding.
(9) EMPLOYEE BENEFITS
Our employee benefit expenses for the years ended December 31st are below (in thousands):
Health benefits, including premiums
$
13,796
$
18,483
401(k) matching
1,851
2,910
Deferred bonus plan
Total
$
16,200
$
22,080
Of the amounts in the above table, $15.2 million and $21.5 million are recorded in “labor” in the consolidated statements of operations for the years ended December 31, 2024 and 2023, respectively, with the remainder in general and administrative.
Our mine employees are also covered by workers’ compensation and such costs were approximately $4.0 million and $4.9 million for 2024 and 2023, respectively, and are recorded in “labor” in the consolidated statements of operations. Workers’ compensation is a no-fault system by which individuals who sustain work-related injuries or occupational diseases are compensated. Benefits and coverage are mandated by each state which includes disability ratings, medical claims, rehabilitation services, and death and survivor benefits. We are partially self-insured for such claims, however, its operations are protected from these perils through stop-loss insurance policies. Our maximum annual exposure is limited to $1.0 million per occurrence with a $4.0 million aggregate deductible.
(10) LEASES
We determine if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, we record a right-of-use (“ROU”) asset and corresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. If our lease does not provide an implicit rate in the contract, we use our incremental borrowing rate when calculating the present value.
We have operating leases for office space with remaining lease terms ranging from one month to approximately eight years. As most of the leases do not provide an implicit rate, we calculate the ROU assets and lease liabilities using our secured incremental borrowing rate at the lease commencement date. Imputed interest on our operating leases was $0.3 million as of December 31, 2024. At December 31, 2024 and 2023, respectively, we had approximately $0.7 million of ROU operating lease assets recorded within buildings and equipment on the consolidated balance sheets. Operating lease expense associated with ROU assets is recognized on a monthly basis over the lease term in operating costs on the consolidated statements of operation.
We entered into three finance leases during 2023 and five finance leases during 2024, which are accounted for as failed sale-leaseback transactions. Finance lease assets are included in finance lease right-of-use assets on the consolidated balance sheets and the associated finance lease liabilities are reflected within current portion of lease financing and long-term lease financing on the consolidated balance sheets as applicable. Depreciation on our finance lease assets was $5.2 million and $2.3 million for the years ended December 31, 2024 and 2023, respectively. Interest expense on our finance lease liability was $1.5 million during the year ended December 31, 2024. Imputed interest expense on our future remaining finance lease liability was $1.7 million for the year ended December 31, 2024. We had deferred financing fees of $0.2 million and $0.1 million at December 31, 2024 and 2023, respectively, in connection with entry into the finance leases. These deferred financing fees will be amortized on a straight-line basis over the term of the finance leases.
Information related to leases was as follows as of December 31st (in thousands):
December 31,
Operating lease information:
Operating cash outflows from operating leases
$
$
Weighted average remaining lease term in years
8.0
8.5
Weighted average discount rate
9.5
%
9.5
%
Finance lease information:
Financing cash outflows from finance leases
$
5,633
$
-
Proceeds from sale and leaseback arrangement
5,134
11,082
Weighted average remaining lease term in years
2.18
3.00
Weighted average discount rate
9.0
%
8.5
%
We recognized the following costs related to our leases in our consolidated balance sheets:
For the Year Ended December 31,
For the Year Ended December 31,
(In thousands)
Operating lease assets
Buildings and equipment
$
$
Operating lease liabilities:
Current operating lease liabilities
Accounts payable and accrued liabilities
$
$
Non-current operating lease liabilities
Other long-term liabilities
Total operating lease liability
$
$
Finance lease assets
Finance lease right-of-use assets
$
13,034
$
12,346
Finance lease liabilities:
Current finance lease liabilities
Current portion of lease financing
$
6,912
$
3,933
Non-current finance lease liabilities
Long-term lease financing
8,749
8,157
Total finance lease liabilities
$
15,661
$
12,090
Future minimum lease payments under non-cancellable leases as of December 31, 2024, were as follows:
Operating Leases
Finance Leases
(In thousands)
$
$
8,147
7,972
1,391
-
-
Thereafter
-
Total minimum lease payments
$
$
17,510
Less imputed interest and deferred finance fees
(313)
(1,849)
Total lease liability
$
$
15,661
(11) SELF INSURANCE
We self-insure non-leased underground mining equipment. Such equipment is allocated among four mining units dispersed over seven miles and seven mining units dispersed over eleven miles, at December 31, 2024 and 2023, respectively. The historical cost of such equipment was approximately $227.8 million and $262.0 million as of December 31, 2024 and 2023, respectively.
We also self-insure for workers’ compensation claims under a guaranteed cost program. Under this program, we are responsible for the first $1.0 million per claim up to an aggregate of $4.0 million annually. Restricted cash of $3.4 million and $3.8 million as of December 31, 2024 and 2023, respectively, represents cash held and controlled by a third party and is restricted for future workers’ compensation claim payments. The Company had $4.3 million and $3.6 million of workers’ compensation reserve as of December 31, 2024 and 2023, respectively in “Accounts payable and accrued liabilities” on the Consolidated Balance Sheets.
(12) NET INCOME (LOSS) PER SHARE
The following table (in thousands, except per share amounts) sets forth the computation of basic earnings per share for the periods presented:
Year Ended December 31,
Basic earnings per common share:
Net income (loss) - basic
$
(226,138)
$
44,793
Weighted average shares outstanding - basic
39,504
33,133
Basic earnings (loss) per common share
$
(5.72)
$
1.35
The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:
Year Ended December 31,
Diluted earnings per common share:
Net income (loss) - basic
$
(226,138)
$
44,793
Add: Convertible Notes interest expense, net of tax
-
1,201
Net income (loss) - diluted
$
(226,138)
$
45,994
Weighted average shares outstanding - basic
39,504
33,133
Add: Dilutive effects of if converted Convertible Notes
-
3,164
Add: Dilutive effects of Restricted Stock Units
-
Weighted average shares outstanding - diluted
39,504
36,827
Diluted net income (loss) per share
$
(5.72)
$
1.25
(13) FAIR VALUE MEASUREMENTS
We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.
Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. See asset impairment discussion below in Nonrecurring Fair Value Measurements sections below.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair value measures as further discussed in “Note 1 - Summary of Significant Accounting Policies”.
Nonrecurring Fair Value Measurements
During the fourth quarter of 2024, the Company completed its review of the coal mining facilities and future mining plans. The impairment analysis was based upon the coal mining operating plans of the Company, market driven pricing and cost trends. As part of that analysis, the Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1 million in 2024.
The discounted cash flow model was calculated using projected economics for the Coal Operations assets, using the Company’s mining plan and reserve estimates to be mined and sold at prevailing commodity prices, operating expenses, and production cost levels, which are classified as Level 3 inputs.
(14) EQUITY METHOD INVESTMENTS
We own a 50% interest in Sunrise Energy, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. The carrying value of the investment included in the consolidated balance sheets as of December 31, 2024 and 2023 was $2.1 million and $2.8 million, respectively.
The Company also owns a 50% interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value of the investment included in the consolidated balance sheets as of December 31, 2024 was $0.5 million.
(15) CONVERTIBLE NOTES
On July 29, 2022, we issued a $5.0 million senior unsecured convertible note (the “July 29th Note”) to a related party affiliated with an independent member of our board of directors. The July 29th Note carried an interest rate of 8% per annum with a maturity date of December 29, 2028. For the period August 18, 2022, through August 17, 2024, the holder had the option to convert the July 29th Note into shares of the Company’s common stock at a conversion price of $6.254. During the first quarter of 2024, the holders of the July 29th Note converted them into 799,488 shares of common stock of the Company, and in connection with such early conversion, we elected to pay interest through August 2025 with 112,570 shares of common stock on the conversion date. We recorded inducement expense which is reported in loss on extinguishment of debt in the condensed consolidated statements of operations in the amount of $0.6 million during the three months ended March 31, 2024. As of December 31, 2024, the entire July 29th Note had been converted to shares of common stock of the Company.
On August 8, 2022, we issued an additional $4.0 million of senior unsecured convertible notes (the “August 8th Notes”) to related parties affiliated with independent members of our board of directors. The August 8th Notes carried an interest rate of 8% per annum with a maturity date of December 29, 2028. For the period August 18, 2022, through August 17, 2024, the holder had the option to convert the Notes into shares of the Company’s common stock at a conversion price of $6.254. Beginning August 8, 2025, we could elect to redeem the August 8th Notes and the holder was obligated to surrender them at 100% of the outstanding principal balance together with any accrued unpaid interest. Upon receipt of the redemption notice from the Company, the holder could have elected to convert the principal balance and accrued interest into the Company’s common stock. During the first quarter of 2024, the holders converted $3.0 million of the August 8th Notes into 479,693 shares of common stock of the Company, and in connection with such early conversion, we elected to pay interest through August 2025 with 67,542 shares of common stock on the conversion date. During the same period, the holders also converted accrued interest into 57,564 shares of the Company’s common stock.
We recorded inducement expense which is reported in loss on extinguishment of debt during the first quarter of 2024 in the condensed consolidated statements of operations in the amount of $0.3 million. During the second quarter of 2024, the holder converted the remaining $1.0 million of August 8th Notes into 159,898 shares of common stock of the Company, and in connection with such early conversion, we paid accrued interest and additional shares of common stock of 5,099 and 25,003, respectively, on the conversion date. We recorded inducement expense which is reported in loss on extinguishment of debt during the second quarter of 2024 in the condensed consolidated statements of operations in the amount of $0.2 million. As of December 31, 2024, the entire August 8th Note had been converted to shares of common stock of the Company.
On August 12, 2022, we issued an additional $10.0 million senior unsecured convertible note (the “August 12th Note”) to an unrelated party. The August 12th Note carried an interest rate of 8% per annum with a maturity date of December 31, 2026. For the period August 18, 2022, through the maturity date, the holder had the option to convert the August 12th Note into shares of the Company’s common stock at a conversion price of $6.15. Beginning August 12, 2025, we could elect to redeem the August 12th Note and the holder would have been obligated to surrender at 100% of the outstanding principal balance together with any accrued unpaid interest. Upon receipt of the redemption notice from the Company, the holder could elect to convert the principal balance and accrued interest into the Company’s common stock. During the three months ended March 31, 2024, the holder converted accrued interest into 65,041 shares of the Company’s common stock. During the second quarter of 2024, the holder converted the $10.0 million August 12th Note into 1,626,016 shares of common stock of the Company, and in connection with such early conversion, we paid accrued interest and additional shares of common stock of 49,716 and 224,268, respectively, on the conversion date. We recorded inducement expense which is reported in loss on extinguishment of debt in the condensed consolidated statements of operations in the amount of $1.7 million during the second quarter of 2024. As of December 31, 2024, the entire August 12th Note had been converted to shares of common stock of the Company.
The funds received from the issuance of the various notes described above were used to provide additional working capital to the Company. The conversion price and number of shares of our common stock issuable upon conversion of the above notes are subject to adjustment from time to time for any subdivision or consolidation of our shares of common stock and other standard dilutive events.
(16) NOTES PAYABLE - RELATED PARTIES
In March 2024, we issued unsecured promissory notes, having a 12-month maturity date and 12% per annum interest rate, to (i) Charles R. Wesley IV Revocable Trust (in which our director Charles R. Wesley IV has a pecuniary interest) in the principal amount of $2,000,000, (ii) Lubar Opportunities Fund I, LLC (in which are our director David J. Lubar has a pecuniary interest) in the principal amount of $2,500,000, and (iii) Hallador Alternative Investment Advisors LLC (in which our director David C. Hardie has a pecuniary interest) in the principal amount of $500,000. The related party notes were paid off in June 2024 with proceeds from the prepaid physically delivered power contract mentioned above in “Note 6 - Revenue”.
(17) ORGANIZATIONAL RESTRUCTURING
On February 23, 2024, (the “Effective Date”), we committed to a reorganization effort in the Coal Operations Segment (the “Reorganization Plan”) that included a workforce reduction of approximately 110 employees, or approximately 12% of the workforce. The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain administrative procedures. The Reorganization Plan is designed to strengthen our financial and operational efficiency and create significant operational savings and higher margins in our coal segment. This step will help to advance our transition from a company primarily focused on coal production to a more resilient and diversified integrated independent power producer (“IPP”). As part of this initiative, we substantially idled production at our higher cost surface mines, Prosperity Mine, and Freelandville Mine, with minimal ongoing production. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. In connection with the Reorganization Plan, we incurred aggregate expenses of $1.9 million ($1.1 million in the first quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in “Labor” in the consolidated statements of operations. These charges related to compensation, tax, professional, and insurance related expenses and are considered one-time charges paid during 2024. The coal mining properties asset group was
tested for impairment as result of the organizational restructuring passing the undiscounted recoverability test. See “Note 19 - Impairment of Coal Properties” for additional changes to the Company’s mining plans that occurred during the fourth quarter of 2024.
(18) AT MARKET AGREEMENT
On December 18, 2023, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with B. Riley Securities, Inc. (the “Agent”), pursuant to which we may issue and sell, from time to time, shares (the “Shares”) of our common stock, par value $0.01 per share (the “Common Stock”), with aggregate gross proceeds of up to $50.0 million through an “at-the-market” equity offering program under which the Agent will act as sales agent (the “ATM Program”). Under the Sales Agreement, we or the Agent have the right, by giving five (5) days’ notice, to terminate the Sales Agreement in our and the Agents sole discretion. The Agent may also terminate the Agreement, by notice to us, upon the occurrence of certain events described in the Sales Agreement.
During December 2023, we issued 794,000 shares of Common Stock under the ATM Program for net proceeds of $7.3 million. During the year ended December 31, 2024, we issued 4,654,430 shares of Common Stock under the ATM Program for net proceeds of $34.5 million.
(19) IMPAIRMENT OF COAL PROPERTIES
Annually, the Company reviews its business plans for the next several years, with specific emphasis on the upcoming year. This business plan review involves updates to its mining plans that take into account many factors, such as changes in market price trends, cost trends, expected demand trends, its latest engineering studies and current year operational and financial results. During the fourth quarter of 2024, the Company began its annual business plan review. The Company evaluated core hole samples at several of its mines, reviewing the quality of the mine seam and density of the coal. Based upon market price trends, the Company believes the required course of action is to only produce those reserves that will allow it the lowest possible cost, and therefore capture the highest possible margins. The core hole samples at the Oaktown 2 mine were of a lower quality and density than that of the Oaktown 1 mine. As such, at the conclusion of the Company’s annual business plan review during the fourth quarter of 2024, it decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs.
As a result of the Company’s decision to temporarily seal the Oaktown 2 mine, the Company determined a triggering event had occurred. The Company then completed an impairment review to determine if the carrying value of its coal properties were impaired. The Company compared the net book value of its coal properties to estimated undiscounted future net cash flows. The result of this undiscounted cash flow test indicated the carrying amount of its coal properties may not be recoverable. As a result, the Company prepared a discounted cash flow model (Level 3 fair value measurement under the fair value hierarchy) to estimate fair value. Significant inputs used to determine fair value include estimates of future cash flows from coal sales and minimum payments, an appropriate discount rate and the useful economic life. The estimated cash flows are the product of a process that began with current realized pricing as of the measurement date and included an adjustment for risk related to the realization of such future cash flows.
The discounted cash flow model used assumptions regarding the projected economics of the Coal Operations assets, given prevailing commodity prices and operating expense levels, which are classified as Level 3 inputs. Coal Operations assets include all of our coal mining properties as these properties are all within the same asset group given the near proximity to one another and their sharing of personnel and assets used to fulfill customer contracts. The Company utilized an estimated market participant discount rate of 11.5% and assumed production that is consistent with our current mining plans and reserve estimates that equate to approximately 3.6 million tons per year until all reserves are produced as part of the analysis.
The result of the discounted cash flow analysis confirmed that fourth quarter of 2024 changes to the mining plans caused the carrying amount of its coal properties to not be recoverable. As a result, the Company recorded an impairment expense during the fourth quarter of 2024 of $215.1 million. The Company did not record an impairment during the year ended December 31, 2023.
(20) SEGMENTS OF BUSINESS
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses operating performance measures related to our Electric Operations and our Coal Operations segments.
Our Electric Operations segment includes the electric power generation facilities of our Merom power plant, which is a two unit, 1080-megawatt rated coal fired power plant located in Sullivan County, Indiana. Our sales region is in MISO Zone 6, which includes Indiana and a portion of western Kentucky. Revenues from our Electric Operations segment consist primarily of delivered energy and capacity revenues. Fuel costs included in our Electric Operations segment include the cost of coal purchased from our Coal Operations segment, which are based on multi-year contracts which approximate market prices at the time the contracts are entered into.
Our Coal Operations segment includes the Oaktown 1 and 2 underground mining complexes, as well as other currently idled mining facilities, which produce high-quality bituminous coal from the Illinois Basin. Revenues from our Coal Operations segment consist of sales of coal to various third-parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts which approximate market prices at the time the contracts are entered into. Intercompany coal sales and amounts above actual costs to produce the coal are eliminated in the consolidated statements of operations.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including our equity method investments.
The CODM evaluates segment performance based upon EBITDA margin for each business segment. EBITDA margin is calculated for each segment as follows:
1. For our Electric Operations segment, EBITDA margin is comprised of delivered energy revenues less certain significant segment expenses, which include (i) variable costs, (ii) other operating and maintenance costs, (iii) costs of purchased power, (iv) utilities, (v) labor and (vi) general and administrative costs. Variable operating costs are comprised of fuel costs and certain other operating costs, such as limestone and soda ash.
2. For our Coal Operations segment, EBITDA margin is comprised of coal sales less certain significant segment expenses, which include (i) fuel, (ii) other operating and maintenance costs, (iii) utilities, (iv) labor and (v) general and administrative costs.
EBITDA margin for each segment is a key measure used by our CODM and provides information about our core operating performance, significant expenses and ability to generate cash flow. Additionally, EBITDA margin provides investors with the financial analytical framework upon which our CODM bases financial, operational, compensation and planning decisions and presents a measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations. Our CODM reviews variable costs, as defined above, in our Electric Operations segment in order to evaluate the efficiency of that segments operations.
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM at December 31, 2024 (in thousands):
Electric Operations
Coal Operations
Delivered Energy
$
203,434
Coal Sales
$
202,525
Capacity Revenue
58,093
Electric Sales
$
261,527
Fuel
$
(111,768)
Other Operating Costs (1)
(19)
Total Variable Costs
$
(111,787)
Other Operating and Maintenance Costs (2)
$
(28,622)
Fuel
$
(2,851)
Cost of Purchased Power
(10,888)
Other Operating and Maintenance Costs
(89,283)
Utilities
(2,070)
Utilities
(13,844)
Labor
(30,842)
Labor
(85,322)
Power Margin Without General and Administrative
77,318
Coal Margin Without General and Administrative
11,225
General and Administrative
(5,311)
General and Administrative
(9,877)
Electric Operations - EBITDA Margin
$
72,007
Coal Operations - EBITDA Margin
$
1,348
(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM at December 31, 2023 (in thousands):
Electric Operations
Coal Operations
Delivered Energy
$
211,772
Coal Sales
$
432,888
Capacity Revenue
56,155
Electric Sales
$
267,927
Fuel
$
(139,496)
Other Operating Costs (1)
(32)
Total Variable Costs
$
(139,528)
Other Operating and Maintenance Costs (2)
$
(33,777)
Fuel
$
(7,089)
Cost of Purchased Power
-
Other Operating and Maintenance Costs
(165,479)
Utilities
(429)
Utilities
(17,301)
Labor
(31,245)
Labor
(121,172)
Power Margin Without General and Administrative
62,948
Coal Margin Without General and Administrative
121,847
General and Administrative
(4,914)
General and Administrative
(10,287)
Electric Operations - EBITDA Margin
$
58,034
Coal Operations - EBITDA Margin
$
111,560
(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues at December 31, 2024 (in thousands):
Corporate and Other
Reconciliation of Revenue:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Delivered Energy
$
203,434
$
-
$
-
$
203,434
Capacity Revenue
58,093
-
-
58,093
Other Operating Revenue
2,756
1,681
5,419
Coal Sales (Third-Party)
-
137,448
-
137,448
Coal Sales (Intercompany)
-
65,077
(65,077)
-
Operating Revenues
$
262,509
$
205,281
$
(63,396)
$
404,394
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues at December 31, 2023 (in thousands):
Corporate and Other
Reconciliation of Revenue:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Delivered Energy
$
211,772
$
-
$
-
$
211,772
Capacity Revenue
56,155
-
-
56,155
Other Operating Revenue
2,936
1,675
5,025
Coal Sales (Third-Party)
-
361,926
-
361,926
Coal Sales (Intercompany)
-
70,962
(70,962)
-
Operating Revenues
$
268,341
$
435,824
$
(69,287)
$
634,878
Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at December 31, 2024 (in thousands):
Corporate and Other
Reconciliation of Income (Loss) before Income Taxes:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Electric Operations - EBITDA Margin
$
72,007
$
-
$
65,276
$
137,283
Coal Operations - EBITDA Margin
-
1,348
(65,077)
(63,729)
Other Operating Revenue
2,756
1,681
5,419
Depreciation, Depletion and Amortization
(19,290)
(46,245)
(91)
(65,626)
Asset Impairment
-
(215,136)
-
(215,136)
Asset Retirement Obligations Accretion
(457)
(1,171)
-
(1,628)
Exploration Costs
-
(260)
-
(260)
Gain (loss) on disposal or abandonment of assets, net
-
(1,629)
1,679
Interest Expense
(1,875)
(11,033)
(942)
(13,850)
Loss on Extinguishment of Debt
-
-
(2,790)
(2,790)
Equity Method Investment (Loss)
-
-
(746)
(746)
Settlement of litigation
-
(2,750)
-
(2,750)
Corporate - General and Administrative
-
-
(11,339)
(11,339)
Corporate - Other Operating and Maintenance Costs
-
-
(440)
(440)
Income (Loss) before Income Taxes
$
51,367
$
(274,120)
$
(12,789)
$
(235,542)
Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at December 31, 2023 (in thousands):
Corporate and Other
Reconciliation of Income (Loss) before Income Taxes:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Electric Operations - EBITDA Margin
$
58,034
$
-
$
69,778
$
127,812
Coal Operations - EBITDA Margin
-
111,560
(70,961)
40,599
Other Operating Revenue
2,936
1,675
5,025
Amortization of Contract Asset
(26,581)
-
-
(26,581)
Depreciation, Depletion and Amortization
(18,739)
(48,365)
(107)
(67,211)
Asset Retirement Obligations Accretion
(576)
(1,228)
-
(1,804)
Exploration Costs
-
(904)
-
(904)
Gain (loss) on disposal or abandonment of assets, net
-
(398)
-
(398)
Interest Expense
(322)
(11,869)
(1,520)
(13,711)
Loss on Extinguishment of Debt
(1,491)
-
(1,491)
Equity Method Investment (Loss)
-
-
(552)
(552)
Corporate - General and Administrative
-
-
(10,958)
(10,958)
Corporate - Other Operating and Maintenance Costs
-
-
(568)
(568)
Income (Loss) before Income Taxes
$
12,230
$
50,241
$
(13,213)
$
49,258
Presented below are our Electric and Coal Operations assets and capital expenditures at December 31, 2024 (in thousands):
Corporate and Other
Other Reconciliations:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Assets
$
220,477
$
144,519
$
4,124
$
369,120
Capital Expenditures
$
18,699
$
34,081
$
$
53,367
Presented below are our Electric and Coal Operations assets and capital expenditures at December 31, 2023 (in thousands):
Corporate and Other
Other Reconciliations:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Assets
$
208,331
$
376,387
$
5,062
$
589,780
Capital Expenditures
$
18,831
$
56,521
$
-
$
75,352
(21) ASSETS HELD FOR SALE
During the third quarter of 2024, the Company considered strategic alternatives with respect to its wholly-owned subsidiary Summit. Summit primarily held property, plant and equipment. On July 29, 2024, the Company entered into a ninety day right of first refusal (“ROFR”) with a potential buyer of Summit for $3.2 million. As of July 29, 2024, Summit met the held-for-sale criteria, and its assets were included in "assets held-for-sale" in the current assets section of the consolidated balance sheets. The Company recorded the Summit assets, once held for sale, at the lower of their carrying value or their estimated fair value less cost to sell. The Company also did not record depreciation and amortization of $0.1 million ($0.1 million after-tax) on assets held-for-sale and continued to do so while held-for-sale criteria was met.
Fair value is the amount at which an asset, liability or business could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques or may be observable using quoted market prices. The Company used a market approach consisting of the contractual ROFR sales price, subject to prorations for property taxes and utilities, to determine the fair value, and subtracted estimated costs to sell from that calculated fair value.
The sale of Summit did not represent a strategic shift that has or will have a major effect on the Company, and as such, did not qualify for treatment as a discontinued operation.
The Company sold Summit on December 23, 2024 for $3.2 million. The Company recorded a $1.7 million gain in “(Gain) loss on disposal or abandonment of assets, net” in its consolidated statements of operations.
(22) CONTINGENCIES
Our Coal Operations subsidiary is party to litigation in which the plaintiffs allege violations of the Fair Labor Standards Act and state law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $2.8 million, which is recorded in “accounts payable and accrued liabilities” on our consolidated balance sheets at December 31, 2024.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES.
Disclosure Controls
We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our CEO and CFO as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.
Management’s Annual Report on Internal Control over Financial Reporting (ICFR)
Our management, including our CEO and CFO, is responsible for establishing and maintaining adequate ICFR. Our ICFR is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Management evaluated the effectiveness of our ICFR based on the framework in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in 2013.
Our management evaluated, with the participation of our CEO and CFO, the effectiveness of our ICFR as of December 31, 2024. Based on that evaluation, our management concluded that our ICFR was effective at December 31, 2024.
Grant Thornton LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our internal control over financial reporting as of December 31, 2024, as stated in their report that is included herein.
There were no significant changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2024, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Hallador Energy Company
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Hallador Energy Company (a Colorado corporation) and subsidiaries (the “Company”) as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2024, and our report dated March 17, 2025 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
March 17, 2025

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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ITEM 11. EXECUTIVE COMPENSATION

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
See Item 8 for an index of our financial statements.
Our exhibit index is as follows:
1.1
At Market Issuance Sales Agreement, dated December 18, 2023, between Hallador Energy Company and B. Riley Securities, Inc. (4)
3.1
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009 (1)
3.2
By-laws of Hallador Energy Company, effective December 24, 2009 (2)
4.1
Description of Securities (3)
10.1
Fourth Amended and Restated Loan Agreement dated August 2, 2023 (5)
10.2
First Amendment to Fourth Amended and Restated Loan Agreement dated as of September 27, 2024 (6)
10.3
Second Amendment to Fourth Amended and Restated Loan Agreement dated as of October 23, 2024 (7)
10.4
Amended and Restated Hallador Energy Company 2008 Restricted Stock Unit Plan (8)
10.5
Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement (8)
10.6
2022 Executive Officer Compensation Plan++(9)
10.7
2024 Executive Officer Compensation Plan * ++
10.8
Asset and Purchase Agreement dated February 14, 2022 (10)
14.1
Code of Ethics for Senior Executive Officers*
19.1
Insider Trading Policy *
21.1
List of Subsidiaries*
23.1
Consent of Grant Thornton LLP*
23.2
Consent of John T. Boyd Company*
31.1
SOX 302 Certification - President and CEO*
31.2
SOX 302 Certifications - CFO*
32.1
SOX 906 Certification*
95.1
Mine Safety Disclosure*
96.1
Technical Report Summary (Coal Resources and Coal Reserves, Oaktown Mining Complex), dated March 2025*
101.INS
Inline XBRL Instance Document*
101.SCH
Inline XBRL Schema Document*
101.CAL
Inline XBRL Calculation Linkbase Document*
101.LAB
Inline XBRL Labels Linkbase Document*
101.PRE
Inline XBRL Presentation Linkbase Document*
101.DEF
Inline XBRL Definition Linkbase Document*
104*
Cover Page Interactive Data File (embedded within the Inline XBRL and contained in Exhibit 101)
(1)
IBR to Form 8-K dated December 31, 2009
(2)
IBR to Form 10-K/A amendment 1, filed June 12, 2020
(3)
IBR to Form 10-K filed March 9, 2020
(4)
IBR to Form 8-K filed December 18, 2023
(5)
IBR to Form 10-Q filed on August 7, 2023
(6)
IBR to Form 8-K filed on October 3, 2024
(7)
IBR to Form 10-Q filed on November 11, 2024
(8)
IBR to Form DEF 14A dated April 12, 2017
(9)
IRB to Form 10-Q filed November 14, 2022
(10)
IBR to Form 8-K/A filed March 11, 2022
(11)
IBR to Form 10-K filed March 14, 2024
*
Filed herewith.
++
Management Agreements