Hallador Energy (HNRG) 10-K2023 FY Annual report

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D. C. 20549 

FORM 10-K

  

☒	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended: December 31, 2023 OR
☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

   

	Commission file number: 001-3473
	HALLADOR ENERGY COMPANY (www.halladorenergy.com)

Colorado	84-1014610
(State of incorporation)	(IRS Employer Identification No.)
1183 East Canvasback Drive, Terre Haute, Indiana	47802
(Address of principal executive offices)	(Zip Code)

  

Issuer’s telephone number: 812.299.2800

  

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class		Trading Symbol(s)		Name of each exchange on which registered
Common Stock, $0.01 par value per share		HNRG		Nasdaq Capital Market

  

Securities registered pursuant to Section 12(g) of the Act: None

  

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐  No ☑

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ☐ No ☑

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes ☑  No ☐

 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes ☑ No ☐

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

  

☐ Large accelerated filer	☑ Accelerated filer
☐ Non-accelerated filer	☑ Smaller reporting company
	☐ Emerging growth company

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

 

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

 

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

 

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐    No ☑

 

The aggregate market value of the common stock held by non-affiliates (public float) on June 30, 2023 was $193,711,455, based on the closing price reported that date by the NASDAQ of $8.57 per share. 

 

As of March 8, 2024, we had 34,885,153 shares outstanding. Our Annual Meeting of Shareholders will be held on May 30, 2024, in Terre Haute, IN.

 

 

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Table of Contents

 

FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.”  These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “Item 1A. Risk Factors” below. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law.

You should consider the information above when reading any forward-looking statements contained in this Annual Report on Form 10-K; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website http://www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

ITEM 1.   BUSINESS.

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

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, or that existing laws or regulations may be interpreted differently or more stringently enforced, 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 risk factors described in “Item 1A. Risk Factors” below.

We are committed to conducting mining and electric power generating 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 coal mining company or electric power generating 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 coal mining for domestic coal producers as well as the cost of electric power generation.

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, mine closings, and power plant closing, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations, mine closing and power plant 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.

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.

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, 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.

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:

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 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.

In November 2020, MSHA published a proposed rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments. The comment period for the proposed rule closed in December 2020.

It is uncertain whether MSHA will present a final rule addressing any of the above issues or any of the other various proposed rules or requests for information or whether any such rule 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 actuary 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, approximately 96% of our production capacity involves underground room and pillar mining (no surface subsidence), and approximately 4% involves surface mining. 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.

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:

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. Future 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.  Although no comprehensive climate change regulation has been adopted at the federal level in the U.S., President Biden has announced that climate change will be a focus of his administration. 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. 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, 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. The international community gathered again in Glasgow in November 2021 at the 26th Conference to the Parties (““COP26”)” during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, among other measures.

Relatedly, the U.S. and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. Also at COP26, more than forty countries pledged to phase out coal, although the U.S. did not sign the pledge. At COP27, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The U.S. also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future.  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.

Even in the absence of new federal legislation, 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 adopts 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.

In January 2021, the EPA published a final significant contribution finding for purposes of regulating source category of GHG emissions, confirming that such power plants are a source category for such regulations. However, this finding also excludes several sectors and may, therefore, be subject to revision, and future implementation of the NSPS is uncertain at this time. The EPA published a notice of proposed rulemaking in May 2023 to regulate GHG emissions from new and existing fossil fuel-fired power plants.  The rule would require power plants to employ measures to lower GHG emissions, including technologies to capture and sequester their GHG emissions or co-fire with low-GHG hydrogen. EPA has indicated that it expects to finalize the rule in June 2024. Once finalized, the rule is expected to face significant legal, political and technological challenges. The rule could potentially have a material adverse effect on our business, financial condition, and results of operations. 

Notwithstanding the ACE rule, the CPP’s requirements and impact during the pendency of the litigation led to premature retirements, and the new GHG regulations proposed in May 2023 could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal. Congress has not currently adopted 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 authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP. We cannot predict whether such legislation will be signed into law in the future.

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. In December 2021, President Biden issued an executive order setting a goal for a carbon pollution-free electricity sector across the country by 2035.  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 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.

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 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 proposed rule for public comment in March 2023, which the agency expects to finalize in 2024.  It is unclear what impact these regulations will have on the market for our coal products or on 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 the CWA Section 316(b) rule issued by the EPA effective in 2014 that seeks to protect fish and other aquatic organisms drawn into cooling water systems at power plants and other facilities. These standards require affected facilities to choose among seven 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. 

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. The EPA published a proposed rule in May 2023 that would regulate inactive surface impoundments at inactive electric utilities, called “legacy CCR surface impoundments.” 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. 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 proposed 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 are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, electricity, fuel, and tires. 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, 2023, Hallador and its subsidiaries employed 936 full-time employees and temporary miners, 886 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.

Other

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

Our corporate office, as well as Sunrise Coal and Hallador Power Company, LLC's (“Hallador Power”) 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.

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 stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal or electric power.

In 2023, a significant portion of our coal, capacity and energy 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 electric utility customers, and if supply exceeds demand in the coal and power 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 a portion of our revenue stream to the increased volatility of the spot market.

Some of our long-term sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.

Some of our long-term coal sales contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. 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.

Several of our long-term contracts also 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 labor disputes, mechanical malfunctions and changes in government regulations, including 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 on similar terms, our business, financial condition and results of operations could be adversely affected.

We depend on a few customers for a significant portion of our revenue, and the loss of one or more significant customers could affect our ability to maintain the sales volume and price of our products.

During 2023, we derived 93% of our coal revenue from four third-party customers, each representing at least 10% of our 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 electric operations revenue for the first half of 2023 was generated largely by one customer as required by the terms of the Asset Purchase Agreement for our acquisition of Hoosier Energy's Merom Generation Station ("Merom"). 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.

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 coal and electric power 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.

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.

Contractors that we use to provide employees at our power plant may experience work stoppages, slowdowns, lockouts or other labor disputes.

At our power plant, 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.

Our recent acquisition of Merom may not achieve its intended results.

On October 21, 2022, the Company, through its subsidiary Hallador Power, completed its acquisition of the one Gigawatt Merom Generating Station located in Sullivan County, Indiana pursuant to an Asset Purchase Agreement with Hoosier Energy.  The Company entered into the Asset Purchase Agreement with the expectation that the acquisition of Merom would result in various benefits, including, among other things, securing future demand for a material portion of the Company’s coal production and also providing a path for Merom’s possible transition to renewable energy when the coal plant is eventually retired. Achieving the anticipated benefits of the acquisition (including the eventual transition to renewable energy) is subject to a number of uncertainties. Failure to achieve these anticipated benefits could result in lower-than-expected revenues or income generated by the combined businesses and diversion of management’s time and energy and could have an adverse effect on the Company’s business, financial results and prospects.  In addition, in connection with the Asset Purchase Agreement, 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.

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.

The operation and maintenance of generating facilities 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, while additional costs may be required as we eventually transition the Merom facilities to renewable energy.  In October 2023, the Merom facilities experienced a transformer failure causing one unit to be offline for the month of October; the failed transformer has since been replaced. We may experience similar failures in the future. We could 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.

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 mining, power 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. These factors 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 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a Minimum Debt Service Coverage Ratio (consolidated adjusted EBITDA/annual debt service) of 1.25 to 1.00 and (ii) a Maximum Leverage Ratio (consolidated funded debt/trailing twelve months adjusted EBITDA) not to exceed 2.25 to 1.00.

On December 31, 2023, our debt service coverage ratio was 3.30, and our leverage ratio was 1.32. Therefore, we were in compliance with these two ratios.

Our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.

On December 31, 2023, our funded bank debt was $91.5 million, we had outstanding convertible notes totaling $19 million, and held letters of credit totaling $18.6 million. Our leverage may:

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.

We could be deemed ineligible for the Paycheck Protection Program (“PPP”) loan we received in 2020 upon audit by the United States Small Business Administration (“SBA”) upon completion of an SBA audit.

The PPP loan application required us to certify that the current economic uncertainty made the PPP loan request necessary to support our ongoing operations. While we made this certification in good faith after analyzing, among other things, our financial situation and access to alternative forms of capital and believe that we satisfied all eligibility criteria and that our receipt of the PPP loan is consistent with the broad objectives of the Paycheck Protection Program of the CARES Act, the certification described above does not contain any objective criteria and is subject to interpretation. In addition, the SBA has stated that it is unlikely that a public company with substantial market value and access to capital markets will be able to make the required certification in good faith. The lack of clarity regarding loan eligibility under the program resulted in significant media coverage and controversy with respect to public companies applying for and receiving loans. If despite our good faith belief that we satisfied all eligibility requirements for the PPP loan, we are found to have been ineligible to receive the PPP loan or in violation of any of the laws or regulations that apply to us in connection with the PPP loan, including the False Claims Act, we may be subject to penalties, including significant civil, criminal and administrative penalties and could be required to repay the PPP loan. We received forgiveness of the entire $10 million of the PPP loan in July 2021, and as a part of the forgiveness process were required to make certain certifications that remain subject to audit and review by governmental entities and could subject us to significant penalties and liabilities if found to be inaccurate. In addition, our receipt of the PPP loan resulted in adverse publicity, and a review or audit by the SBA or other government entity or claims under the False Claims Act could consume significant financial and management resources. Any of these events could harm our business, results of operations, and 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, are facing increased scrutiny from stakeholders related to their ESG practices. Companies that do not adapt or comply with evolving 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. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also 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. 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.

A significant portion of the electricity we sell is used by residential and commercial customers for heating and air conditioning. Accordingly, fluctuations in weather, gas and electricity commodity costs, inflation and economic conditions impact demand of our customers and our operating results.

Energy sales are sensitive to variations in weather. Forecasts of energy sales are based on “normal” weather, which represents a long-term historical average. Significant variations from normal weather resulting from climate change or other factors could have, and have had, a material impact on energy sales. Additionally, residential usage, and to some degree commercial usage, is sensitive to fluctuations in commodity costs for electricity, whereby usage declines with increased costs, thus affecting our financial results. Commodity prices have been and may continue to be volatile. Lastly, residential and commercial customers’ usage is sensitive to economic conditions and factors such as recession, inflation, unemployment, consumption and consumer confidence. Therefore, prevailing economic conditions affecting the demand of our customers may in turn affect our financial results.

We face various risks related to pandemics and similar outbreaks, which have had and may continue to have material adverse effects on our business, financial position, results of operations, and/or cash flows.

Since first reported in late 2019, the COVID-19 pandemic has dramatically impacted the global health and economic environment, including millions of confirmed cases, business slowdowns or shutdowns, government challenges, and market volatility of an unprecedented nature. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty, and turmoil in the coal and electric industry driven by widespread government-imposed lockdowns. While most government-imposed shut-downs in the U.S. and abroad have been phased out, there is a possibility that such shut-downs may be reinstated if COVID-19 or another pandemic were to again become an acute, severe risk. This could cause a sustained decrease in demand for our coal and electric power and the failure of our customers to purchase coal or electric power from us that they are obligated to purchase pursuant to existing contracts, which would have a material adverse effect on our operations and financial condition. The various governmental and private responses to the pandemic also led to widespread, global supply chain disruptions. These supply chain disruptions have previously caused and may continue to or again cause some of our suppliers to fail to deliver the quantities of supplies we need or fail to deliver such supplies in a timely manner.

The extent to which COVID-19 or another future pandemic may adversely impact our results of operations, cash flows and financial condition depends on future developments, which are highly uncertain and unpredictable.

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.

The consumer privacy landscape continues to experience momentum for greater privacy protection and reform at the state and federal level in response to precedents set forth by the General Data Protection Regulation (the “GDPR”) and the California Consumer Privacy Act (the “CCPA”). The development and evolving nature of domestic and international privacy regulation and enforcement could impact and potentially limit how Hallador processes personally identifiable information. Beginning January 1, 2023, California residents have increased access rights (including the right to limit the use and disclosure of sensitive personal information), which are enforced by a new 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 effective in 2023 and patterned after the standards set forth by CCPA, including broader data access rights, with Virginia going a step further requiring businesses to perform data protection assessments for certain processing activities.

As new laws and regulations are created, 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 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.

The Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks.

The Company’s trading and hedging activities do not cover certain risks and may expose it to earnings volatility and other risks. In addition to overall price volatility, the Company is currently subject to price volatility on diesel fuel and other commodities utilized in its operations. The Company has entered into certain hedging arrangements to address these risks and may continue in the future to enter into hedging arrangements, including economic hedging arrangements, to manage these risks or other exposures. Since the Company’s existing hedging arrangements do not receive cash flow hedge accounting treatment, all changes in fair value are reflected in current earnings.

Some of these hedging arrangements may require the Company to post margin based on the value of the related instruments and other credit factors. If the fair value of its hedge portfolio moves significantly, or if laws, regulations, or exchange rules are passed requiring all hedge arrangements to be exchange-traded or exchange-cleared, the Company could be required to post additional margin, which could negatively impact its liquidity.

Risks Related to our Industry

Substantial or extended volatility in coal prices could negatively impact our results of operations.

Our results of operations are primarily dependent upon the prices we receive for our coal in our coal operations, or the price we pay for our coal in the case of our electric operations, as well as our ability to improve productivity and control costs. These prices depend upon factors beyond our control, including:

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. 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.

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 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 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.

Our operations are subject to a series of risks resulting from climate change.

Combustion of fossil fuels, such as the coal we produce, 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. Most 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.

In the U.S., no comprehensive climate change legislation has been implemented at the federal level. However, 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, following President Biden’s executive order in January 2021, the U.S. rejoined the Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below levels by 2030. Additionally, at COP26 in Glasgow in November 2021, the U.S. and the European Union jointly announced the launch of a Global Methane Pledge committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The U.S. also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a 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, including certain climate-related pledges made by certain candidates now in political office. 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. 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, although Congress has not passed such legislation, 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, and, in September 2022, announced that six of the U.S.’ largest banks will participate in a pilot climate scenario analysis to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve released its pilot exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolio. 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 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.” 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 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:

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 mining 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, 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. 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 operations, or indirect impacts that discourage or limit our customers’ use of coal. Federal and state laws addressing mine 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.

We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash flow and profitability.

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. 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. 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.

The Federal Reserve raised the federal funds interest rate throughout December 31, 2023, in its effort to take action against domestic inflation, and rates are expected to remain higher throughout 2024. We have exposure to these past increases in interest rates and may be affected further in the future. Based on our current variable debt level of $91.5 million as of December 31, 2023, 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 less than $1 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.

We have expanded our operations by adding and developing mines and coal reserves in existing, adjacent, and neighboring properties, including through our recent acquisition of Merom. We continually seek to expand our operations and coal reserves. 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 coal companies for attractive properties 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:

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 unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our profitability to decline.

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. Replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which could adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also could have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

The estimates of our coal reserves could prove inaccurate and could result in decreased profitability.

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:

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.

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 coal mining operations are affected by commodity prices. 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, 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.

A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs and could adversely affect our profitability.

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks.  In recent years, a shortage of experienced coal miners has caused us to include some inexperienced staff in the operation of certain mining units, which decreases our productivity and increases our costs.�� This shortage of experienced coal miners is the result of a significant percentage of experienced coal miners reaching retirement age, combined with the difficulty of retaining existing workers in and attracting new workers to the coal industry.  Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

Disruptions in supply chains could significantly impair our operating profitability.

We are dependent upon vendors to supply mining equipment, equipment within our power plant, 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 and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduce demand for our coal or electric power 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:

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.

ITEM 1B.  UNRESOLVED STAFF COMMENTS.  None.

ITEM 1C.  CYBERSECURITY.

Risk Management and Strategy

We rely on information technology to operate our business. We have endpoint and other protection systems, and incident response processes, both internally and through third-party consultants, designed to protect our information technology systems. These established processes assist us to continuously assess and identify threats to our systems and minimize impact to our business in the event of a breach or other security incident. With our third-party consultants, the processes protect our information systems and allow us to resolve issues timely.

As new threats to security may be identified, our personnel are notified, with instruction to increase awareness of the threat and how to react if such a threat or actual breach appears to be encountered. Periodic educational notices are also disseminated to all personnel. Additionally, as our systems are modified and upgraded, all personnel are notified, with instruction as appropriate. Responsibility for the identification and assessment of risks and the recommendation of upgrades to our systems resides with our expert consultants who report to our IT Director.

Governance

Our Board oversees the risks involved in our operations as part of its general oversight function, integrating risk management into the Company’s compliance policies and procedures. With respect to cybersecurity, the Board has the ultimate oversight responsibility, with the Audit Committee and IT Steering Committee each having certain responsibilities relating to risk management of cybersecurity.

Among other things, the Audit Committee discusses with management the Company’s major policies with respect to risk assessment and risk management, including cyber-security, as they relate to the integrity of the Company’s accounting and financial reporting processes and the Company’s compliance with legal and regulatory requirement.

In addition to its other responsibilities, the IT Steering Committee oversees operational information technology risks, including cybersecurity, as they relate to the technical aspects of the Company’s operations.

The IT Steering Committee and/or the full Executive Team receive at least quarterly reports from management on information technology matters, including cybersecurity. The reports address upgrades to hardware, software, and IT systems throughout the Company, and include the identification of IT and cybersecurity risks.  Security scores, risk management, and mitigation measures are routinely presented. As discussed above, we maintain endpoint and other protection systems, and incident response processes, both internally and through third-party experts. As these systems, processes, training, and upgrades are implemented, updates are provided to the Executive Team.

We have not identified an indication of a substantive cyber security incident that would have a material impact on our business, results of operations or financial statements. For additional information regarding risks from cybersecurity threats, please refer to Item 1A, “Risk Factors,” above.

ITEM 2.  PROPERTIES.

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

ITEM 3.  LEGAL PROCEEDINGS.  None

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

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 30.5% is held by our officers, directors, and their affiliates.

On March 8, 2024, we had 215 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 to our consolidated financial statements.

ITEM 6.  [RESERVED]

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 ton and per mega-watt hour (MWh) basis as derived from the condensed 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. Historically, the largest portion of our business has been devoted to coal mining in the State of Indiana through Sunrise Coal, LLC (a wholly-owned subsidiary) serving the electric power generation industry.

On October 21, 2022, the Company, through its wholly owned subsidiary Hallador Power, acquired the Merom Generating Energy Station ("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 believe this acquisition is the catalyst that began Hallador's transition from a producer of coal to a vertically integrated independent power producer ("IPP").

As a result of the Merom acquisition the Company has two reportable segments: coal operations (operated by Sunrise Coal, LLC) and electric operations (operated by Hallador Power).   In addition to our reportable segments, the remainder of our operations are presented as “Corporate and Other” and primarily are comprised of unallocated corporate costs in addition to activities such as a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, accounted for using the equity method, and our wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

2023 was the first whole year in which Hallador Power operated Merom.  In accordance with the Purchase and Sale Agreement associated with the Merom acquisition, for the first five months of 2023, all fuel consumed at Merom was delivered from a third party and all energy produced was sold at $34 per MWh.  Beginning in June 2023, approximately seventy percent of Merom’s energy became available to sell on the open market.  However, despite spot prices for electricity at Merom averaging $39 in 2021 and $69 in 2022, generally milder weather and depressed natural gas prices drove down the average spot price for electricity to $31 in 2023.

Despite near record margins at our coal division for the full year, the fourth quarter was a particularly challenging quarter for Hallador Power. A failure in Merom’s main Generator Step-Up Transformer (GSU) coupled with a scheduled maintenance outage took half of the plant offline for nearly the entire quarter.  The planned maintenance resulted in $12.6 million in expenditures and the transformer replacement resulted in an additional $0.7 million in unplanned capital expenditures.  Additionally, natural gas prices, which have great influence on overall electricity price, remained low throughout the second half of 2023 and dropped to an inflation adjusted all-time low in the first quarter of 2024.

The acquisition of Merom, brought with it additional capex spending requirements to maintain and return the power plant to top condition, which we expected to pay for with fourth quarter free cash flow from in-quarter power sales. However, with fourth quarter challenges at both Merom and in our coal division, Sunrise Coal, we took steps to protect liquidity and to increase the efficiency of our operations.  Thus, in December and early January we improved liquidity and provided operational flexibility through an At-The-Market (ATM) offering. Under the ATM, we sold approximately 800,000 shares of Hallador stock in December 2023 and raised approximately $7.3 million of equity resulting in 34,051,154 shares outstanding at December 31, 2023.  Approximately 700,000 shares of Hallador stock was sold in January 2024 raising an additional $6.6 million of equity. Hallador’s share count stands at 34.9 million shares as of March 8, 2024.  Liquidity at year end was $26.2 million. Subsequently, in February 2024, we further added to liquidity as several members of Hallador's Board of Directors loaned the company a total of $5 million through an unsecured one year note at an interest rate of 12% per annum. Receipt of roughly $36 million in capacity revenue for the 2024-2025 planning year will begin in the first quarter of 2024, further strengthening our financial position.  See Note 4 to our consolidated financial statements for additional discussion about our bank debt and related liquidity.

On February 23, 2024, our Coal Operations Segment undertook an initiative designed to strengthen our financial and operational efficiency and to create significant operational savings and higher margins in our coal segment. This step will advance our transition from a company primarily focused on coal production to a more resilient and diversified vertically integrated IPP.  As part of this initiative, we idled production at our higher cost Prosperity Mine, and substantially idled production at Freelandville Mine with minimal production.  This should reduce our capital reinvestment for coal production in 2024 by approximately $10 million. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. As part of the initiative, we reduced our workforce by approximately 110 employees.

Historically, Sunrise Coal has generated approximately six million tons of coal annually. Following the restructuring, we expect Sunrise to produce roughly 4.5 million tons of coal annually at improved margins to our former structure.  Additionally, in 2024, we have secured supplemental coal from third party suppliers at favorable prices.  This allows us to diversify self-production supply risk and provides us with additional flexibility in our sales portfolio.  The optionality to obtain low-cost tons either internally or from third parties while capturing upward swings in the commodities markets for coal should further maximize margins while optimizing fuels costs at Merom. 

In addition to the expected improvements in coal margins, Merom has the capability to provide revenue on up to 6 million mega-watt-hours (MWh) annually.  Based on the currently available forward power price curves, we believe over time, the margins earned on energy and capacity sales will be more than double our historical margins of approximately eight dollars per ton on coal production. Furthering this belief, in Q3 we reported contracted sales of 3.4 million MWh to be delivered in 2026-2028 at MWh margins that we believe could exceed twenty-five dollars per MWh.  We continue to see strong indications for both energy and capacity sales in 2024 and in future years.  Our approach has been to sell energy primarily through bi-lateral agreements on a unit contingent basis in an attempt to reduce our exposure to market risk if we fail to produce due to operational issues in what we believe to be an increasingly volatile power market.  While we are seeing success in this approach, sales of this type are largely bespoke and require more time and negotiation than a typical firm power sale as we build our forward sales positions.  As we methodically work to contract our forward sales book, we continue to sell energy on the spot market, resulting in episodic cash generation largely dependent on demand created by seasonal weather and various other conditions which stress the power grid.

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 gas face transportation and storage challenges which increase price volatility.  Batteries and hydro generation are improving, but current technology and expense limit the ability to economic practicability of implementing the technology on a large-scale basis.  We believe that the lack of economically viable storage options coupled with the challenges of non-dispatchable generation gaining market share in an environment where the sun does not always shine and the wind does not always blow, indicates that energy’s price volatility is likely to increase over the next decade. This volatility appears to be keeping the forward power price premium intact.

In an effort to capture additional margins above our traditional wholesale energy markets, we recently agreed to a structure with Hoosier Energy and their distribution member, WIN REMC, that should allow us to attract industrial users of power, such as data centers, AI providers and power dense manufacturers, to the Merom property.  We believe leveraging our plant to help supply these large users of energy with reliable, resilient electricity should allow us to operate more efficiently in a volatile power environment, generate increased margins and support the fragile power grid as it navigates the challenges of transition to new sources of energy in the coming decades.  These types of relationships should allow us to capture the upside of increasing demand and volatility while providing stability to our earnings and ability to dispatch in a world that is consistently seeking more electricity but lacks the real time infrastructure and generation to satisfy those increasing power needs. Combined with our increased volume of forward power sales, we believe that these types of opportunities will continue to improve the outlook for the company and provide a stable platform to leverage both our power and coal assets in a responsible and sustainable manner.

We are excited about the transformation of Hallador from a commodity focused producer of coal to a vertically integrated IPP. We believe that this transition provides significant opportunity to capture the increased margins of the energy markets, to take advantage of the increasing demand for electricity and to step up the value chain in a more sustainable and future proofed industry than that which we have traditionally operated in. As evidenced by the ongoing build of our long-term sales book, our deliberate movement into the electricity sector should materially strengthen our company and the products that we sell.  

Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations 

        *    Based on coal production of 4.5 million tons and 6.0 million MWh annually.

        **  Based on a MISO accreditation of 860MW per day. Accreditations are adjusted annually based on 3-year rolling performance metrics.

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 six total mining properties. These properties are the Oaktown Mining Complex, 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 and Freelandville. 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 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 the Oaktown Mine Complex 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 Complex and other Sunrise Coal logistic facilities where it is blended with coal from the Oaktown Mines. Ace in the Hole Mine is now depleted.

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 October 2023 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 All 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 attributableto 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 October, 2023 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 January, 29, 2024, from John T. Boyd Company providing an update of estimated coal reserves at the Oaktown Mining Complex as of December 31, 2023, 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 January 29, 2024, 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, 2023 and including a comparison of the Company's mineral reserves at the Oaktown Mining Complex as of December 31, 2023 and as of December 31, 2022. 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, 2023:

SUMMARY MINERAL RESERVES AT END OF THE

FISCAL YEAR ENDED DECEMBER 31, 2023

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.  The following figure shows the general location of the Oaktown Mining Complex:

 

Comprising 118 square miles within the ILB coal-producing region of the mid-western U.S., the Oaktown Mining Complex is one of the largest underground Room-and-Pillar (R&P) coal mining complexes in North America.  The Oaktown Mining Complex operations currently consist of two active underground mines - Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 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 Mining Complex area and immediate vicinity, our Company controls approximately 75,000 acres of mineral rights.  This control exists as a complex collection of leases that apply to more than 2,000 tracts.  Each of which 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. As part of the Oaktown Mining Complex, the Company controls surface rights through fee simple ownership for over 1,700 permitted acres.  Upon those acres resides the surface facilities for mine accesses, processing, storing, shipping, and refuse disposal facilities (i.e., refuse impoundment site and fine refuse injection sites).  Our involvement with the Oaktown Mining Complex dates to 2014 with the acquisition of Oaktown Fuels No. 1 and No. 2 Mines from Vectren Fuels.

Each mine of the Oaktown Mining Complex 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 Mining Complex has utilized this mining method since the inception of each operation.  To date, Oaktown Mining Complex has produced a combined 71.1 million tons of clean coal.  The complex is configured to operate up to 7 CM sections, with an annual production target of approximately 4.5 million product tons.  The Oaktown Complex Coal Preparation Plant serves as the coal washing and shipment facility for the Oaktown Mining Complex’s two R&P mines.  The plant was commissioned in 2009 to wash coal by the Oaktown Fuels No. 1 Mine.  The Oaktown Complex Coal Preparation Plant's processing capacity was upgraded to 1,800 raw tons-per-hour (TPH) from its previous 1,600 raw TPH.  Product coal from the Oaktown Mining Complex is transported to its customer base via rail, truck, or a combination of both.  The Oaktown Complex Coal 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 Complex Coal 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 $9.9 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 the Oaktown Mining Complex mineral reserves:

Oaktown Fuels No. 1 Mine

As of December 31, 2023, the assigned and accessible reserve base for the Oaktown Fuels No. 1 Mine contains 34.1 million tons of recoverable Indiana V seam coal, of which 34.1 million tons are currently permitted.  The reserve contains saleable tons which average heating content of approximately 11,527 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, 2023, the assigned and accessible reserve base for the Oaktown Fuels No. 2 Mine contains 26.6 million tons of recoverable Indiana V seam coal, of which 21.3 million tons are currently permitted.  The reserve contains saleable tons which average heating content of approximately 11,518 Btu per pound with approximately 5.4 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.  Since beginning first commercial coal production in 2013 the mines workings have substantially grown and, during 2021, an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces.

Tonnages 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 2023, with the coal sales price estimated over the life of the reserve averaging approximately $47 (ranging from $42.50 to $64 per short 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 January 29, 2024, 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, 2023 and including a comparison of the Company's mineral reserves at the Oaktown Mining Complex as of December 31, 2023 and as of December 31, 2022.

Historical production for our Oaktown Mining Complex during the years ended December 31, 2023, 2022, and 2021 is provided in the following table:

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 Carlisle and Oaktown wash plants in early 2023. Reclamation resumed in the Spring of 2023. Phase 1 and 2 reclamation is substantially complete as of December 31, 2023.

Prosperity (surface) – Assigned

The Prosperity mine contains approximately 0.2 million tons of low sulfur coal needed to blend with our Oaktown coal to reduce the sulfur content to a salable level for Southeastern US markets. 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. Mining started in the fall of 2022 and continued through April 2023.  In February 2024, this mine was idled.

Our Coal Contracts

In 2023, on a segment basis Sunrise sold 6.9 million tons of coal to 11 power plants in five different states across six different customers.

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. During 2022, on a segment basis we derived 90% of our revenue from five customers (10 power plants), with each of the five customers representing at least 10% of our coal sales.

Significant customers in 2023 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC), Alcoa Power Generating, Inc., a subsidiary of Alcoa Corporation (NYSE:  AA), Alabama Power, a subsidiary of Southern Company (NYSE: SO), and Duke Energy Corporation (NYSE: DUK).

Of our 2023 sales, on a segment basis 33%, excluding Merom Power Plant, were derived to locations in the State of Indiana.

Our future coal commitments are as follows:

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*     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, 2023, we are committed to supplying third-party customers up to a maximum of 9.2 million tons of coal through 2027 of which 6.2 million tons are priced. We are committed to supplying coal to Merom Power Plant up to a maximum of 10.7 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 4.5 million ton annualized pace for the foreseeable future to meet the Merom plant and third-party market demand.

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 $59.4 million and $54.2 million for the years ended December 31, 2023 and 2022 respectively. Operating cash flow increased due to an increase in operating margins at our coal mines brought on by the addition of higher priced contracts. This was offset by lower margins from our power plant and a decrease in working capital. 

Our capital expenditure budget for 2024 is $43 million, of which the majority is for maintenance capex.  Of the $43 million, the budget for coal operations is $25 million and the budget for electric operations is $18 million. 

As of December 31, 2023, our bank debt was $91.5 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 debt to May 31, 2026, and our revolver to July 31, 2026.    

We expect cash from operations generated primarily by our expected higher coal margins in 2023 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 $16.6 million, including $5.2 million at Merom, presented as asset retirement obligations (ARO) in our accompanying balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $37.5 million to cover ARO.

Capital Expenditures (capex)

For the year ended December 31, 2023, our capex was $75.4 million allocated as follows (in millions):  

Results of Operations

Presentation of Segment Information

Our operations are divided into two primary reportable segments:  Coal Operations and Electric Operations.  The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other” within the Notes to the Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method, and our wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

Coal Operations

Operating revenues from coal operations increased 48% over 2022 due in large part to unprecedented increases in natural gas prices. As a result, higher priced contracts sold in the summer of 2022 and delivered in Q4 of 2022 through all of 2023 increased our average sales price by $16.90 per ton from 2022. We also sold 581,000 additional tons over 2022 at the higher average price due to lower inventories and the higher gas prices.

Operating expenses increased, however, by ~$7.50 per ton. The addition of the higher cost Freelandville and Prosperity surface mines as well as significant inflationary pressures and geological conditions contributed significantly to the increased costs. 

Depreciation, depletion, and amortization increased 11%. The majority of this change is due to significant capital additions in the coal division.

General and administrative expenses increased 30% over 2022 due in large part to additional professional fees related to bank refinancing and additional audit requirements. Increased wages due to bonuses and incentives to retain and attract talent also contributed to the increased costs.

Electric Operations

A comparative discussion is not relevant as the Electric Operations did not begin until the Merom Acquisition closed in October 2022.

Operating revenue is derived from sales to the Midcontinent Independent System Operator ("MISO") wholesale market and a power purchase agreement (PPA) signed with Hoosier in conjunction with the Merom Acquisition.  The PPA included sales at fixed prices which were below market prices at the date we entered into the agreement.  The power purchase agreement expires in 2025 and requires us to provide a fixed amount of power over the term of the agreement.  As a result of the below market contract, we recorded a contract liability at the close of the acquisition totaling $184.5 million that will be amortized over the term of the agreement as the contract is fulfilled.  For the years ended December 31, 2023, we recorded $70.5 million and $23.3 million, respectively of revenue as a result of amortizing the contract liability.

Operating expenses include coal purchased under an agreement signed with Hoosier in conjunction with the Merom acquisition at fixed prices which were below market prices at the date we entered into the agreement.  The coal purchase agreement expired in May 2023 and required us to purchase a fixed amount of coal over the term of the agreement.  As a result of the below market contract, we recorded a contract asset at the close of the acquisition totaling $34.3 million that was amortized over the term of the agreement as the contract was fulfilled.  The contract asset was fully amortized with an asset value of $0 as of December 31, 2023.  For the years ended December 31, 2023 and 2022, we recorded $30.7 million and $3.6 million respectively in additional operating expense for coal purchased and used. 

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, 2023, 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.

Quarterly coal sales and cost data follow on a segment basis (in 000’s, except for per ton data and wash plant recovery percentage):

Quarterly electric sales and cost data (in thousands, except per MWh data) are provided below.  Fixed costs in the table are considered "non-GAAP" and are a component of operating expenses, the most comparable GAAP measure. We consider fixed costs to be costs associated with the plant whether or not the plant is in operation.

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). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. 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. There were no significant changes to our NRV adjustment estimates from the prior year.