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“COAL KEEPS YOUR LIGHTS ON”

Commission file number: 001-3473

“COAL KEEPS YOUR LIGHTS ON”

HALLADOR ENERGY COMPANY

(www.halladorenergy.com)

	HALLADOR ENERGY COMPANY (www.halladorenergy.com)

Issuer'sIssuer’s telephone number: 303.839.5504812.299.2800

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

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¨ ☐  Noþ ☑

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes¨ ☐ Noþ ☑

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.  Yesþ ☑  No¨ ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.þ

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).   Yesþ ☑ 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 "larger“large accelerated filer," "accelerated filer"” “accelerated filer,” “smaller reporting company,” and "smaller reporting company"“emerging growth company” in Rule 12b-2 of the Exchange Act.

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¨ ☐    Noþ ☑

The aggregate market value of the common stock held by non-affiliates (public float) on June 30, 20172023 was $124.5 million$193,711,455, based on the closing price reported that date by the NASDAQ of $7.77$8.57 per share.

As of March 9, 2018,8, 2024, we had 29,955,71334,885,153 shares outstanding.

Portions of our Proxy Statement to be filed with the SEC in connection with our annual stockholders’ meeting are incorporated by reference into Part III of this Form 10-K. Our Annual Meeting of Shareholders will be held on May 23, 201830, 2024, in New York City, NY.Terre Haute, IN.

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 reasonable, but 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.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 websitehttp://www.halladorenergy.comand 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- MDA“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 industry isand 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 utilityelectric 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, particularlyincluding 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.producers as well as the cost of electric power generation.

Capital expendituresExpenditures 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, and 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 minepower 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 time-consuming, 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

Stringent safety and health standards have been imposed by federal legislation since the Federal Coal Mine Health and Safety Act of 1969 (“CMHSA”) was adopted.  The Federal Mine Safety and Health Act of 1977 (“FMSHA”), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards of the CMHSA, and imposedimposes 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 U.S.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.

The 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, andalong 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.  The 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 Miner’sMiners’ Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.”  The final rule implementsimplemented 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.

Additionally, 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 2014, MSHA proposed a rule addressing the “criteria and procedures for assessment of civil penalties.”  Public commenters have expressed concern that the proposed rule exceeds MSHA’s rulemaking authority and would result in substantially increased civil penalties for regulatory violations cited by MSHA.  MSHA last revised the process for proposing civil penalties in 2006 and, as discussed above, civil penalties increased significantly.  The notice-and-comment period for this proposed rule has closed, and it2022. It is uncertain whenwhether MSHA will present aadditional proposed rules, or revisions to the final rule, addressing these civil penalties.following the closing of the comment period.

In January 2015, MSHA has also published, a final rule requiring mine operatorsand may continue to install proximity detection systems on continuous mining machines, over a staggered time frame ranging from November 2015 through March 2018.  The proximity detection systems initiate a warningpublish, various proposed rules or shutdown the continuous mining machine depending on the proximity of the machine to a miner. MSHA subsequently proposed a rule requiring mine operators to also install proximity detection systems on other types of underground mobile mining equipment.  The comment periodrequests for this proposed rule closed on April 10, 2017, and it is uncertain when MSHA will promulgate a final rule addressing the issue of proximity detection systems on underground mobile mining equipment, other than continuous mining machines.

Ininformation, 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 was reopened and 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 proposedfinal rule pertaining to exposure of underground miners to diesel exhaust, after completing its evaluationaddressing any of the comments received.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 statefederal and federalstate 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, and to some survivors of a miner who dies from this disease.  The BLBA levies a tax on production of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price, in order to compensate miners who are totally disabled due to black lung disease, and some survivorsto a trust fund for the payment of miners who died from this disease,benefits and who were last employed as miners prior to 1970 or subsequentlymedical expenses where no responsible coal mine operator has been identified for claims.  In addition, the BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax.  The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlierAs of January 1, 2014, or2022, the datetrust fund was funded by an excise tax on whichproduction 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 government trust becomes solvent.  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 also liable undersubject 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 claims.  Congresslung. 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 state legislatures regularly consider various items of black lung legislation, which, if enacted, could adversely affect our business, results of operations and financial position.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 relatedlung-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.

Workers’ Compensation

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.  States in which we operate consider changes in workers’ compensation laws from time to time.

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 deepunderground mining. Although we have minimalCurrently, approximately 96% of our production capacity involves underground room and pillar mining (no surface mining activitysubsidence), and no mountaintopapproximately 4% involves surface mining. We do not engage in either mountain top removal mining activity,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 mined propertysurface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore theaffected 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 taxreclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977.  The taxfee 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 $0.28$0.224 per ton and $0.12$0.096 per ton, respectively.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 U.S. Office of Surface Mining Reclamation (“OSM”) published in November 2009 an Advance Notice of Proposed Rulemaking, announcing its intent to revise the Stream Buffer Zone (“SBZ”) rule published in December 2008.  The SBZ rule prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality.  Environmental groups brought lawsuits challenging the rule, and in a March 2010 settlement, the OSM agreed to rewrite the SBZ rule.  In January 2013, the environmental groups reopened the litigation against OSM for failure to abide by the terms of the settlement.  Oral arguments were heard on January 31, 2014.  OSM published a notice on December 22, 2014, to vacate the 2008 SBZ rule to comply with an order issued by the U.S. District Courtestablished nationally applicable minimum criteria for the District of Columbia.  OSM reimplemented the 1983 SBZ rule.

OSM issued its final Stream Protection Rule ("SPR") in December 2016 to replace the vacated SBZ rule.  The rule would have generally prohibited the approval of permits issued pursuant to SMCRA where the proposed operations would result in "material damage to the hydrologic balance outside the permit area." Pursuant to the rule, permittees would have also been required to restore any perennial or intermittent streams that a permittee mined through. Finally, the rule would have also imposed additional baseline data collection, surface/groundwater monitoring, and bonding and financial assurance requirements. However, in February 2017, both the U.S. House of Representatives and the Senate passed resolutions disapproving the SPR under the Congressional Review Act ("CRA"). President Trump signed the resolution on February 16, 2017, and, pursuant to the CRA, the SPR "shall have no force or effect" and OSM cannot promulgate a substantially similar rule absent future legislation.  Whether Congress will enact future legislation to require a new SPR rule remains uncertain.

Following the spill of coal combustion residues (“CCRs”) in the Tennessee Valley Authority impoundment in Kingston, Tennessee, in December 2009, the EPA issued proposed rules on CCRs in 2010.  This final rule was published on December 19, 2014.  The EPA's final rule does not address the placementdisposal of CCRs in minefillsnew 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 non-minefill usesproposed amendments to the federal CCR rule or state CCR regulations, the results of CCRs at coal mine sites.  OSM has announced their intention to releasegroundwater monitoring data, or the outcome of CCR-related litigation could have a proposed rule to regulate placementmaterial impact on our business, financial condition and useresults of CCRs at coal mine sites, but, to date, no further action has been taken.  These actions by OSM, potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.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 usour competitors and for our competitorsus to secure new surety bonds without posting collateral.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 statefederal and federalstate 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:

Carbon DioxideGHG 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 which is considered a GHG.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.  CongressAlthough no comprehensive climate change regulation has considered various proposals to reduce GHG emissions, and it is possiblebeen adopted at the federal legislation could be adoptedlevel in the future.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 Kyoto Protocol set binding emission targets for developed countries that ratified it (the U.S. did not ratify, and Canada officially withdrew from its Kyoto commitment in 2012)Paris Agreement requires member states to reduce their global GHG emissions.  The Kyoto Protocol was nominally extended past its expiration date of December 2012, with a requirement for a new legal construct to be put into place by 2015.  The United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an international climate agreement (Paris Agreement).  Although this agreement does not create any binding obligations for nations to limit their GHGsubmit non-binding, individually-determined emissions it does include pledges to voluntarily limit or reduce future emissions.reduction targets. These commitments could further reduce demand and prices for our coal. In June of 2017, President Trump announced thatfossil fuels. Although the U.S. would withdrawhad 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 hasmultiple announcements were made, including a four-year exit process.   Future participationcall 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 Paris Agreement byenergy 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 uncertain.  However,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 inMassachusetts v. Environmental Protection Agencythat the EPA has authority to regulate GHG emissions. In 2009,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 known as the “Endangerment Finding”,” declaringwhich found that GHG emissions, including carbon dioxide and methane, endanger public health and welfare and that six GHGs, including carbon dioxide and methane, emitted by motor vehicles endanger both the public health and welfare.

In May 2010,Several rulemakings have been issued under the EPA issued its final “tailoring rule” for GHG emissions, a policy aimed at shielding small emission sources from CAA permitting requirements.  The EPA’s rule phases in various GHG-related permitting requirements beginning in January 2011.  Beginning July 1, 2011, the EPA requires facilities that must already obtain NSR permits (new or modified stationary sources) for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year.  These permits require that the permittee adopt the Best Available Control Technology (“BACT”).  In June 2012, the D.C. Circuit Court of Appeals upheld these permitting regulations.  In June 2014, the U.S. Supreme Court invalidated the EPA’s position that power plants and other sources can be subject to permitting requirements based on their GHG emissions alone.  For CO2 BACT to apply, CAA permitting must be triggered by another regulated pollutant (e.g., SO2). 

As a result of revisions to its preconstruction permitting rules that became fully effective in 2011, the EPA now requires new sources, including coal-fired power plants, to undergo control technology reviews for GHGs (predominantly carbon dioxide) as a condition of permit issuance.  These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for and so discourage development of coal-fired power plants. The EPA has also issued final rules requiring the monitoring and reporting of greenhouse gas emissions from certain sources.

In March 2012, the EPA proposed New Source Performance Standards (“NSPS”) for carbon dioxidethat constrain the GHG emissions from new fossil fuel-firedof fossil-fuel-fired power plants. The proposal requires new coal units to meet a carbon dioxide emissions standard of 1,000 lbs. CO2/MWh, which is equivalent to the carbon dioxide emitted by a natural gas combined cycle unit.  In January 2014, the EPA formally published its re-proposed NSPS for carbon dioxide emissions from new power plants.  The re-proposed rule requires an emissions standard of 1,100 lbs. CO2/MWh for new coal-fired power plants.  To meet such a standard, new coal plants would be required to install carbon capture and storage (“CCS”) technology. In August 2015, the EPA released final rules requiring newly constructed coal-fired steam electric generating units (“EGUs”) to emit no more than 1,400 lbs CO2/MWh (gross) and be constructed with CCS to capture 16% of CO2 produced by an electric generating unit burning bituminous coal.  At the same time, the EPA finalized GHG emissions regulations for modified and existing power plants.  The rule for modified sources required reducing GHG emissions from any modified or reconstructed source and could limit the ability of generators to upgrade coal-fired power plants thereby reducing the demand for coal.  In April 2017, the EPA published notice in the federal register that the agency has initiated a review of the NSPS for new and modified fossil fuel-fired power plants and that, following the review, the EPA will initiate reconsideration proceedings to suspend, revise or rescind this NSPS.  Challenges to the NSPS have been filed in U.S. Court of Appeal for the D.C. Circuit and oral arguments were set for April 2017; however, in April 2017, the U.S Court of Appeal for the D.C. Circuit ordered the NSPS case held in abeyance for an EPA review of the rule.  It is likely than any repeal or revisions to the NSPS will be subject to legal challenges as well.  Future implementation of the NSPS is uncertain at this time.

In August 2015, the EPA issued its final Clean Power Plan ("CPP"(“CPP”) rules that establish carbon pollution standards for power plants, called CO₂CO2 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"Court”) even issued a decision. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted.   The Supreme Court's stay applies only to EPA's regulations for CO₂ emissions from existing power plants and will not affect EPA's standards for new power plants.  It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP. Additionally,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 althoughwith 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 outcomerepeal of this action and the pending litigation regarding 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. In connection with thisThe EPA published a notice of proposed repeal, the EPA issued an Advance Notice of Proposed Rulemaking ("ANPRM")rulemaking in December 2017 regarding emission guidelinesMay 2023 to limitregulate GHG emissions from new and existing electricity utility generating units.fossil fuel-fired power plants.  The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source regulation under the Clean Air Act ofrule would require power plants to employ measures to lower GHG emissions, from electric utility generating unitsincluding technologies to capture and sequester their GHG emissions or co-fire with low-GHG hydrogen. EPA has indicated that it may propose.  Ifexpects to finalize the effortrule in June 2024. Once finalized, the rule is expected to repeal the rules is unsuccessfulface significant legal, political and the rules were upheld at the conclusion of this appellate process and were implemented in their current form, or if the ANPRM results intechnological challenges. The rule could potentially have a different proposal to control GHG emissions from electric utility generating units, demand for coal would likely be further decreased, potentially significantly, andmaterial adverse effect on our business, would be adversely impacted.financial condition, and results of operations. 

Collectively, theseNotwithstanding the ACE rule, the CPP’s requirements haveand 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 rejectednot currently adopted legislation to restrict carbon dioxide emissions from existing power plants and it is unclear whetherhas not otherwise expanded the legal authority of the EPA has the legalfollowing West Virginia v. EPA, including as it relates to authority to regulate carbon dioxide emissions forfrom existing and modified power plants as proposed in the NSPS and CPP. Substantial limitations on GHG emissions could adversely affect demand forWe cannot predict whether such legislation will be signed into law in the coal we produce.future.

There have been numerous protests of 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. These standards generally range from 10%Several states have announced their intent to 30%, over time periods that generally extend from the present until between 2020 and 2030.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 coal-fired power,fossil fuel energy, and may affect long-term demand for our coal. Finally, a federal appeals court allowed a lawsuit pursuing federal common law claim to proceed against certain utilities onwhile the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds.  The U.S. Supreme Court overturned that decision in June 2011, holdinghas held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions.  The Supremeemissions, the Court did not however, 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 December 2014,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 updated draft guidance, discussing howeffective immediately, to assist federal agencies should considerin assessing the effects of GHG emissions and climate change ineffects of their NEPA evaluations.  The guidance encourages agencies to provide a more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably foreseeable emissions and effects.  This guidance could create additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our future operations, including due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts. In April 2017, CEQ withdrew its final 2016 guidance on how federal agencies should incorporate climate change and GHG considerations into NEPA reviews of federal actions.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. Though New Jersey withdrew from RGGI in 2011, sinceSince its inception, several additional northeastern states and Canadian provinces have joined RGGI as participants or observers. New Jerseyobservers, while Virginia has announcedwithdrawn from RGGI via executive order by its intentiongovernor. Similar to rejoin RGGI, following the change in state government administrations.

Following the RGGI model, five Westernwestern states launched the Western Regional Climate Action Initiative, to identify, evaluate,although only California and implement collective and cooperative methods of reducing GHGcertain Canadian provinces are currently active participants. We cannot predict what other regional greenhouse gas reduction initiatives may arise in the region to 15% below 2005 levels by 2020.  These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions.  It is likely that these regional efforts will continue.future.

It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with coalfossil 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 coalfossil 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.

WaterWater Discharge

The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on effluent dischargeregulate discharges into certain waters, andprimarily through permitting. Section 402 of the dischargeCWA governs discharges of dredged or fill materialpollutants into the waters of the U.S.  Regular monitoring, as well as compliance with reporting requirements and performance standards,United States, primarily through National Pollutant Discharge Elimination System (“NPDES”) permits. Hallador’s Merom Generating Station is a preconditionsubject to an NPDES permit for the issuance and renewal of permits governing the discharge of pollutants into water.  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. Although permitting requirements have been tightened in recent years, weWe 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.  AlthoughThe 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.

TheIn 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”) maintains two permitting programsand/or a discharge permit from the state regulatory authority under CWA Section 404 for the discharge of dredged or fill material: one for “individual” permits and a more streamlined program for “general” permits.  In June 2010,state counterpart to the Corps of Engineers suspended the use of “general” permits under Nationwide Permit 21 (“NWP 21”) in the Appalachian states.  In February 2012, the Corps of Engineers reissued the final 2012 NWP 21.  The Center for Biological Diversity later filed a notice of intent to sue the Corps of Engineers based on allegations the 2012 NWP 21 program violated the Endangered Species Act (“ESA”).  The Corps of Engineers and National Marine Fisheries Service (“NMFS”) have completed their programmatic ESA Section 7 consultation process on the Corps of Engineers’ 2012 NWP 21 package, and NMFS has issued a revised biological opinion finding that the NWP 21 program does not jeopardize the continued existence of threatened and endangered species and will not result in the destruction or adverse modification of designated critical habitat. However, the opinion contains 12 additional protective measures the Corps of Engineers will implement in certain districts to “enhance the protection of listed species and critical habitat.” While these measures will not affect previously verified permit activities where construction has not yet been completed, several Corps of Engineers districts with mining operations will be impacted by the additional protective measures going forward. These measures include additional reporting and notification requirements, potential imposition of new regional conditions and additional actions concerning cumulative effects analyses and mitigation.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.  A challenge to the EPA’s exercise of this authorityproject which veto was made in the U.S. District Court for the District of Columbia, and in March 2012, that court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively.  In April 2013,subsequently upheld by the D.C. Circuit Court of Appeals reversed this decision and authorized the EPA to retroactively veto portions of a Section 404 permit.  The U.S. Supreme Court denied a request to review this decision.in 2013. Any future use of the EPA’s Section 404 “veto” power could create uncertainlyuncertainty 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 revenue.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 water bodywaterbody 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.production or electric power generation operations.

ConsiderableOn 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 uncertainty exists surroundingcases relevant to determination of “functional equivalent” are ongoing in various jurisdictions. It is too early to determine whether the standardSupreme 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 what constitutes jurisdictional watersthe 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 wetlandsthe outcome of any such challenges.

The Merom Generating Station is subject to the protections and requirements of the Clean Water Act. A 2015 rulemaking by EPA to revise the standard was stayed nationwideCWA Section 316(b) rule issued by the U.S. CourtEPA 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 Appeals foraquatic organisms. It is possible that this process, which includes permitting and public input, could result in the Sixth Circuit and stayed for certain primarily western states by a United States District Court in North Dakota. In January 2018,need to install closed-cycle cooling systems (closed-cycle cooling towers), or other technology, although the Supreme CourtIndiana Department of Environmental Management has previously determined that the circuit courts do not have jurisdiction to hear challenges tosystems in place currently at Merom Station meet the 2015 rule, removing the basis for the Sixth Circuit to continue its nationwide stay. Additionally, EPA has promulgated a final rule that extends the applicability date of the 2015 rule for another two years in order to allow EPA to undertake a rulemaking on the question of what constitutes a water of the United States. In the meantime, judicial challenges to the 2015 rulemaking are likely to continue to work their way through the courts along with challenges to the recent rulemaking that extends the applicability date of the 2015 rule. For now, EPA and the Corps of Engineers will continue to apply the existing standard for what constitutes a water of the United States as determined by the Supreme CourtBTA requirements. If additional capital expenditures became necessary in the Rapanos case and post-Rapanos guidance. Should the 2015 rule take effect, or should a different rule expanding the definition of what constitutes a water of the United Statesfuture, they could be promulgated as a result of EPA and the Corps of Engineers' rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.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 liabilitiesliability 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.sites or electric power generating operations.

The Federal Resource Conservation and Recovery Act (“RCRA”) and correspondinganalogous state laws regulating hazardous waste affect coal mining operations by imposingimpose 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.

In June 2010,RCRA impacts the EPA released a proposed rule to regulatecoal industry and electric power generation industry in particular because it regulates the management and disposal of certain coal combustion by-productsresiduals (“CCB”CCR”).  The proposed rule set forth two very different options for regulating CCB under RCRA.  The first option called for regulation of CCB as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal.  The second option utilized Subtitle D, which would give the EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits.  The proposal leaves intact the Bevill exemption for beneficial uses of CCB.  In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule.  Several companies and industry groups intervened.  A consent decree was entered on January 29, 2014.

The EPA finalized the CCB rule on December 19, 2014, setting nationwide solid, nonhazardous waste standards for CCB disposal. On April 17, 2015, the EPA finalized regulations under RCRA for the solidmanagement and disposal of CCR. Under the finalized regulations, CCR is regulated as “non-hazardous” waste provisions (“Subtitle D”) of RCRA and notavoids the stricter, more costly, regulations under RCRA’s hazardous waste provisions (“Subtitle C”) which became effective on October 19, 2015.  EPA affirms in the preamble to the final rule that “this rule does not apply to CCR placed in active or abandoned underground or surface mines.”  Instead, “the U.S. Department of Interior (“DOI”) and EPA will address the management of CCR in mine fills in a separate regulatory action(s).”rules. While classification of CCBCCR 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.

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 November 3, 2015,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 finalrevised CCR rule Effluent Limitations Guidelines and Standards (“ELG”), revisingwere vacated by the regulations for the Steam Electric Power Generating category which became effectiveD.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 4, 2016.25, 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 rule setscurrent determinations, future determinations of the first federal limits on the levelssame nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension 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.coal-fired boilers. The combined effect of the CCR rules and ELG regulations (discussed above) has forcedcompelled power generating companies to close existing ash ponds and will likelymay force the closure of certain older existing coal-burningcoal burning power plants that cannot comply with the new standards. These regulations add costs toSuch retirements may adversely affect the operation of coal-burning power plants on top of other regulations like the 2014 regulations issued under Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment.  Individually and collectively, these regulations could, in turn, impact the marketdemand for our products.  In April 2017, EPA granted petitions for reconsiderationcoal, and an administrative stay of all future compliance deadlines for the ELG rule.  In August 2017, EPA granted petitions for reconsideration of the CCR rule.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 impacts.  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.requirements, which in turn could increase operating costs or adversely affect our revenues.

Other Environmental, Health and Safety RegulationsRegulation

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 regulation.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 principleprincipal 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. Clean Air Act,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 has re-opened as a significant fuel source for utilities and has enabled them to burn lower costlower-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.U.S. Coal Industry

The major coal production basins in the U.S. include ILB, Central Appalachia (CAPP)(“CAPP”), Northern Appalachia (NAPP), Illinois Basin (ILB)(“NAPP”), Powder River Basin (PRB)(“PRB”), and the Western Bituminous region (WB)(“WB”). CAPP includes eastern Kentucky, Tennessee, Virginia, and southern West Virginia. NAPP includes Maryland, Ohio, Pennsylvania, and northern West Virginia. The ILB includes Illinois, Indiana and western Kentucky. 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 useend-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 useutilize 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 United StatesU.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 Alliance (Nasdaq: ARLP) and smallother private producers.

EmployeesHuman Capital

We have 742As of December 31, 2023, Hallador and its subsidiaries employed 936 full-time employees and temporary miners, 886 of which 736those 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 employees.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 Denvercorporate office, is located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504as well as Sunrise Coal and Sunrise Coal'sHallador Power Company, LLC's (“Hallador Power”) corporate office, is located at 1183 East Canvasback Drive, Terre Haute, Indiana, 47802, phone47802. All offices can be reached at 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis. Our website iswww.halladorenergy.com.

ITEM 1A. RISK FACTORS.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 maycould 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:

A substantial or extended decline 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, as well as our ability to improve productivity and control costs.  The prices we receive for our production depends upon factors beyond our control, including:

Any adverse change in these factors could result in weaker demand and lower prices for our products.  A substantial or extended decline in coal prices could materially and adversely affect us by decreasing our revenue to the extent we are not protected by the terms of existing coal supply agreements.

Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

We compete with other coal producers for domestic coal sales.  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 may 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 may impact our ability to retain or attract customers and could adversely impact our revenue and cash from operations.   In addition, declining prices from an oversupply of coal in the market could reduce our revenue and cash from operations.

Changes in consumption patterns by utilities regarding the use of coal have affected our ability to sell the coal we produce. Since 2000, coal’s share of U.S. electricity production has fallen from 53% to 30%, while natural gas’ share has increased from 16% to 32%.

The domestic electric utility industry accounts for over 93% 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 coal-fueled generation, particularly from older, less efficient coal-powered generators.  We expect that many of the new power plants needed in the U.S. to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain.

Future environmental regulation of GHG emissions could accelerate the use by utilities of fuels other than coal.  In addition, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for coal.  For example, the EPA’s CPP will likely incentivize additional electric generation from natural gas and renewable sources, and Congress has extended tax credits for renewables.  In addition, a number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of power.  Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal.  A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash from operations.

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 may require further emission reductions and associated emission control expenditures.  These laws and regulations may affect demand and prices for coal.  There is also continuing pressure on state and federal 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 five 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. 

Increased regulation of GHG emissions could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for our products, decrease our revenue and reduce our profitability.

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere.  On December 15, 2009, the EPA published the Endangerment Finding asserting that emissions of carbon dioxide and other GHGs present an endangerment to public health and the environment, and the EPA has begun to regulate GHG emissions pursuant to the CAA.  The EPA has finalized an NSPS to regulate GHG emissions from new power plants.  The finalized standard requires CCS, a technology that is not yet commercially feasible without government subsidies and that has not been demonstrated in the marketplace.  This requirement effectively prevents the construction of new coal-fired power plants. The EPA published notice in the federal register in April 2017 that the agency has initiated a review of the NSPS for new and modified fossil fuel-fired power plants and that, following the review, the EPA will initiate reconsideration proceedings to suspend, revise or rescind this NSPS.  In August 2015, the EPA issued its final CPP rules that establish carbon pollution standards for existing power plants, called CO₂emission 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 Circuit Court even issued a decision.  By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted.  The Supreme Court's stay applies only to EPA's regulations for CO₂emissions from existing power plants and will not affect EPA's standards for new power plants.  It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time.   In connection with this proposed repeal, the EPA issued an ANPRM in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units.  The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose.  If the effort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of this appellate process and were implemented in their current form, or if the ANPRM results in a different proposal to control GHG emissions from electric utility generating units, demand for coal would likely be further decreased, potentially significantly, and our business would be adversely impacted. Please read “Item 1. Business—Regulation and Laws—Air Emissions” and “—Carbon Dioxide Emissions.”

Numerous political and regulatory authorities and governmental bodies, as well as environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal and potentially materially and adversely impacting our future financial results, liquidity and growth prospects.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events.  Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants.

Federal, state and local governments may pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may decrease demand for our coal products.  The CPP is one of a number of recent developments aimed at limiting GHG emissions which could limit the market for some of our products by encouraging electric generation from sources that do not generate the same amount of GHG emissions.  Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures.  For example, the agreement resulting from the 2015 United Nations Framework Convention on Climate Change contains voluntary commitments by numerous countries to reduce their GHG emissions and could result in additional firm commitments by various nations with respect to future GHG emissions.  These commitments could further disfavor coal-fired generation, particularly in the medium to long-term.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves.  In California, for example, legislation was signed into law in October 2015 that requires California’s state pension funds to divest investments in companies that generate 50% or more of their revenue from coal mining by July 2017.  Other activist campaigns have urged banks to cease financing coal-driven businesses.  As a result, several major banks enacted such policies.  The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation.  Collectively, these actions and campaigns could adversely impact our future financial results, liquidity and growth prospects.

Government regulations have resulted and could continue to result in significant retirements of coal-fired electric generating units.  Retirements of coal-fired electric generating units decrease the overall capacity to burn coal and negatively impact coal demand.

Since 2010, utilities have formally announced the retirement or conversion of over 600 coal-fired electric generating units through 2030.  These retirements and conversions amount to over 111,000 megawatts (“MW”) or approximately 35% of the 2010 total coal electric generating capacity.  At the end of 2017 retirement and conversions affecting 69,000 MW, or approximately 22% of the 2010 total coal electric generating capacity, is estimated to have occurred.  Most of these announced and completed retirements and conversions have been attributed to the EPA regulations, although other factors such as an aging coal fleet and low natural gas prices have also played a role.  The reduction in coal electric capacity negatively impacts overall coal demand.  Additional regulations and other factors could lead to additional retirements and conversions and, thereby, additional reductions in the demand for coal.

Plaintiffs in federal court litigation have attempted to pursue tort claims based on the alleged effects of climate change.

In 2004, eight states and New York City sued five electric utility companies inConnecticut v. American Electric Power Co.  Invoking the federal and state common law of public nuisance; plaintiffs sought an injunction requiring defendants to abate their contribution to the nuisance of climate change by capping carbon dioxide emissions and then reducing them.  In June 2011, the U.S. Supreme Court issued a unanimous decision holding that the plaintiffs’ federal common law claims were displaced by federal legislation and regulations.  The U.S. Supreme Court did not address the plaintiffs’ state law tort claims and remanded the issue of preemption for the district court to consider.  While the U.S. Supreme Court held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, tort-type liabilities remain a possibility and a source of concern.  The proliferation of successful climate change litigation could adversely impact demand for coal and ultimately have a material adverse effect on our business, financial condition and results of operations.

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.coal or electric power.

In 2017, approximately 50%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. Long-term salesThese 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 maycould 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 industry, electric utilitiesand 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 coal 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 maycould 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 the coal we produce.our products.

During 2017,2023, we derived 92%93% of our coal revenue from fivefour third-party customers, andeach representing at least 10% of our revenue from each of them.coal sales. If in the future we were to 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.

Litigation resulting from disputes with 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 may result in substantial costs, liabilities, and purchasers of accredited capacity, the loss of revenue.

From time to time we have disputes with ourone or more of these material 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 may 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 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 revenuerevenues will decrease, and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

Our profitability may 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 revenue and profitability, which could materially adversely impact our quarterly or annual results.

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 maycould still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.

Risks Related to Our IndebtednessNatural disasters and Liquidity

If we are unable to comply with the covenants contained inother events beyond our credit agreement, the lenders could declare all amounts outstanding to be due and payable and foreclose on their collateral, whichcontrol could materially adversely affect our financial condition and operations.

As disclosed in Note 3 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a minimum debt service coverage ratio of 1.25 to 1 and (ii) a current maximum leverage ratio (Sunrise funded debt/adjusted EBITDA) not to exceed 4.25 to 1, which also decreases in future periods further reducing the maximum leverage permitted.  On December 31, 2017, our debt service coverage ratio was 1.90, and our leverage ratio was 2.40. Therefore, we were in compliance with these two ratios.

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

On December 31, 2017, our debt was $202 million.  Our leverage may:

Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on business opportunities.  Any subsequent refinancingNatural disasters or other events outside of our current indebtednesscontrol may cause damage or any new indebtednessdisruption to our operations, and thus could have similara 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 greater restrictions.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.

Risk Related to Possible Future Impairment Charge

Carlisle Mine

In December 2016, the deterioration of the North End of the Carlisle Mine, coupled with lower coal prices led us to determine that the northern end of the Carlisle Mine no longer could be safely and profitably mined. The sealing of the North End was completed in March 2017.  In connection therewith, we identified specific assets totaling $16.6 million ($15.1 million of property and equipment and $1.5 million of advanced royalties) that were written off in 2016. 

The Carlisle Mine assets had an aggregate net carrying value of $110 million at December 31, 2017.  With the Carlisle Mine remaining in hot idle status, we conducted a review of the Carlisle Mine assets as of December 31, 2017, based on estimated future net cash flows, and determined that no further impairment was necessary; however, if future expectations and assumptions change we may incur possible impairment in future periods.

Bulldog Reserves

In October 2017, we entered into an agreement to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase the property for 8 years. Because of the likelihood of exercising the repurchase option, we are accounting for the sale as a financing transaction. The Bulldog Mine assets had an aggregate net carrying value of $15 million at December 31, 2017. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. The permit will be issued upon submittal of a fee and bond which are required within 12 months of the notification. We have determined that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.

ITEM 1B.  UNRESOLVED STAFF COMMENTSCOMMENTS.  None.. 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“Item 7 MDA- Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our mines.

Coal Reserve Estimates

“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves mean coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. “Proven (measured) reserves” are defined by Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Our reserve estimates are prepared by Scott McGuire, one of our mining engineers. Mr. McGuire is a licensed Professional Engineer in the State of Indiana and Kentucky and has sixteen years’ experience estimating coal reserves.

Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards, coal within 1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable category. Only tons greater than 4’ in thickness are included in our underground reserves. All reserves are stated as a final salable product.

Prior to acquiring coal mineral leases, title abstractors conduct a preliminary title search on the property.  This information provides a strong indication of the coal owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us the rights to explore and mine the property.   Prior to mining, attorneys review the chain of mineral ownership to verify the lessor is the mineral owner. Prior to purchasing coal properties, we follow a similar process

ITEM 3.  LEGAL PROCEEDINGS.  None   None

ITEM 4.  MINE SAFETY DISCLOSURES:

Safety is a core value for us.us and our subsidiaries. As such, we have dedicated a great deal of time, energy, and resources to creating a culture of safety. Thus, we are very proud of the mine rescue team at Sunrise Coal whose current list of achievements includes reigning National Champions of the Nationwide Mine Rescue Skills Championship and Governor’s Award recipient (1^st place) at the 2017 Indiana Mine Rescue Association Contest.

See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.

PART II

ITEM 5.  MARKET FOR REGISTRANT'SREGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Stock Price Information

Our common stock is tradedtrades on the NASDAQ Capital Market under the symbol HNRG, and 46%30.5% is held by our officers, directors, and their affiliates. The following table sets forth the dividends paid and the high and low closing sales price for the periods indicated:

		Dividends Paid				High				Low
2018
January 1 through March 9		$	0.04			$	7.31			$	5.96
2017
Fourth quarter			.04				6.56				4.87
Third quarter			.04				8.34				5.40
Second quarter			.04				8.32				6.30
First quarter			.04				9.79				7.48
2016
Fourth quarter			.04				10.02				7.24
Third quarter			.04				8.26				4.50
Second quarter			.04				5.10				4.03
First quarter			.04				5.68				4.05

AtOn March 8, 2018,2024, we had 205215 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street“street name.”  We estimate we have over 5,000 street name holders.

 

Equity Compensation Plan Information

 

See Note 58 to our consolidated financial statements.

27

 

Stock PerformanceITEM 6.  [RESERVED]

 

The following performance compares Hallador Energy (Nasdaq: HNRG), the Russell 2000 Index, the SNL Coal Index, Alliance Resource Partners LP (NYSE: ARLP), Cloud Peak Energy (NYSE: CLD), and Foresight Energy (NYSE: FELP).

The graph assumes that you invested $100 in our common stock and in each company and index at the closing price on December 31, 2012, that all dividends were reinvested, and that you continued to hold your investment through December 31, 2017.

		Period Ended
Company / Index		12/31/12				12/31/13				12/31/14				12/31/15				12/31/16				12/31/17
Hallador Energy Company			100.00				99.14				137.64				58.09				119.20				81.70
Russell 2000 Index			100.00				138.82				145.62				139.19				168.85				193.58
Alliance Resource Partners LP			100.00				141.46				167.02				57.64				107.98				103.62
SNL Coal Index			100.00				98.12				72.68				18.19				37.61				37.92
Foresight Energy LP							100.00				90.66				21.51				39.43				27.41
Cloud Peak Energy Inc.			100.00				93.12				47.49				10.76				29.02				23.02
Source: S&P Global Market Intelligence

28

ITEM 6.    SELECTED7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL DATA.CONDITION AND RESULTS OF OPERATIONS.

For the years ended December 31,

(in thousands, except per share data)

		2017				2016				2015				2014				2013
Revenue:
Coal sales		$	268,202			$	278,924			$	339,490			$	233,902			$	137,436
Equity (loss) income – Savoy			460				(1,187	)			(1,532	)			5,272				5,827
Equity (loss) income - Sunrise Energy			(95	)			(249	)			(74	)			248				629
Liability extinguishment																			4,300
Other			3,066				3,962				2,236				1,749				5,678
			271,633				281,450				340,120				241,171				153,870
Net income before impairment and income taxes*			13,882				25,044				27,570				10,701				29,598
Asset impairment			-				16,560				-				-				-
Income tax expense (benefit)			(19,194	)			(4,026	)			7,438				482				7,175
Net income		$	33,076			$	12,510			$	20,132			$	10,219			$	22,423
Net income per share :
Basic and diluted		$	1.08			$	0.42			$	0.68			$	0.34			$	0.78
Cash dividends per share		$	0.16			$	0.16			$	0.16			$	0.16			$	0.12
Balance Sheet Information (end of period):
Total assets		$	518,193			$	531,323			$	540,378			$	579,585			$	259,199
Total bank debt*			201,992				238,617				249,470				306,345				16,000

* Non-GAAP measurement. See Note 2, Note 3, and Note 4 to the consolidated financial statements.

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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.

 

OverviewOVERVIEW

 

TheHallador Energy Company (the “Company” or “Hallador”) is an energy company operating in the state of Indiana. Historically, the largest portion of our business ishas been devoted to coal mining in the State of Indiana through Sunrise Coal, LLC (a wholly ownedwholly-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 ownbelieve 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. We also own a 30.6% equity interest in Savoy Energy, L.P., a private oil and gas exploration company with operations in Michigan. We accountIndiana, accounted for our interest in Savoy and Sunrise Energy using the equity method. Wemethod, 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 reachedgreat influence on overall electricity price, remained low throughout the second half of 2023 and dropped to an agreement for Savoyinflation adjusted all-time low in the first quarter of 2024.

The acquisition of Merom, brought with it additional capex spending requirements to redeem our entire partnership interest for $8 million,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 finalizeproduce roughly 4.5 million tons of coal annually at improved margins to our former structure.  Additionally, in mid-March 2018. Our net after commissions paid2024, 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 $7.5 million.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 operate two underground minesare 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 one surfaceto 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.  

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Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations 

		2024				2025				2026				2027				2028				Total
Coal
Priced tons - 3rd party (in millions)			3.4				1.8				0.5				0.5				-				6.2
Average price per ton - 3rd party		$	51.82			$	50.57			$	56.09			$	56.09			$	-
Priced tons (in millions) - Hallador Power			1.5				2.3				2.3				2.3				2.3				10.7
Average price per ton - Hallador Power		$	51.00			$	51.00			$	51.00			$	51.00			$	51.00
Contracted coal revenue (in millions)		$	252.69			$	208.33			$	145.35			$	145.35			$	117.30			$	869.02
% Priced			109	%			91	%			62	%			62	%			51	%
Committed & unpriced tons (in millions) - 3rd party			-				1.0				1.0				1.0				-				3.0
Committed & unpriced tons (in millions) - Hallador Power			-				-				-				-				-				-
Total contracted tons (in millions)			4.9				5.1				3.8				3.8				2.3				19.9
% Coal Sold*			109	%			113	%			84	%			84	%			51	%
Average cost per ton of coal sold was $33.67 for the year ended December 31, 2023 ($26.98 after eliminating for intercompany sales to Hallador Power)
2024 Coal Capex Budget (in millions)		$	25.00
Power
Energy
Contracted MWh (in millions)			1.87				1.90				1.83				1.78				1.09				8.47
Average contracted price per MWh		$	35.23			$	36.06			$	55.37			$	54.65			$	52.98
Contracted revenue (in millions)		$	65.88			$	68.51			$	101.33			$	97.28			$	57.75			$	390.75
% Energy Sold*			31	%			32	%			31	%			30	%			18	%
Capacity
Average daily contracted capacity			810				748				743				623				454
% Capacity Contracted**			94	%			87	%			86	%			72	%			53	%
Average contracted capacity price per MWd		$	200			$	210			$	230			$	226			$	224
Contracted capacity revenue (in millions)		$	59.13			$	57.33			$	62.37			$	51.39			$	37.12			$	267.34
Total Energy & Capacity Revenue
Contracted Power Revenue (in millions)		$	125.01			$	125.84			$	163.70			$	148.67			$	94.87			$	658.09
Contracted Power Revenue per MWh*		$	45.69			$	47.05			$	67.40			$	66.47			$	64.70
2023 average cost per MWh sold was $33.67 for the year ended December 31, 2023 ($26.98 assuming intercompany sales of coal were sold at cost)
2024 Power Capex Budget (in millions)		$	18.00
TOTAL CONTRACTED REVENUE (IN MILLIONS)		$	377.70			$	334.17			$	309.05			$	294.02			$	212.17			$	1,527.11

        *    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 southwestern Indiana.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 underground mines,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 are in Oaktown, Indiana, 43 miles south of Terre Haute, Indiana. TheMine, the Ace in the Hole surface mine is in Clay City, Indiana, 30 miles southeast of Terre Haute, Indiana. We also ownMine, the Carlisle Mine located near Carlisle, Indiana, 36 miles south of Terre Haute. The Carlisle reserve is contiguous to Oaktown 2. The Carlisle Mine is developed, but currently idle.

Oaktown 1, Oaktown 2 and Carlisle are one large underground mining complex representing 121 million tons of controlled reserves, with three slopes, one elevator, two wash plants, and two rail facilities, located on the CSX railroad. We anticipate total capacity for the three mines to be roughly 10.5 million tons annually. Additionally, the capacity of our 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 .4 millionan 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 annually. Thus,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 total mining capacity is 10.9 million tons annually. Theproperties 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 Princeton Rail Loop, expected to come onlinemost recently completed fiscal year both in the springaggregate and for each of 2018,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 also provide usever 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 accessexploration 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 marketsreserves 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

		Mineral Reserves (tons in millions)
		Proven				Probable				Total
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine			29.9				4.2				34.1
Oaktown Fuels No. 2 Mine			20.4				6.2				26.6
Total			50.3				10.4				60.7

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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:

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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 Railway Company.(NS) Railroad.

 

For 2017,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. 

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Additional information is provided in the following table regarding the Oaktown Mining Complex mineral reserves:

OAKTOWN MINING COMPLEX

Recoverable Coal Reserves as of December 31, 2023 and 2022

		As Received				As Received
		Heat				SO2
		Value				Content
		(Btu/lb)				(lbs/MMBtu)				Owned				Leased				Recoverable Coal Reserves (As-Received)
Mine/Reserve		Approximate				Approximate				(%)				(%)				Proven				Probable				12/31/2023				12/31/2022
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine			11,527				6.0				—				100.0				29.9				4.2				34.1				36.7
Oaktown Fuels No. 2 Mine			11,518				5.4				—				100.0				20.4				6.2				26.6				29.6
Total																			50.3				10.4				60.7				66.3

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 67%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:

		Annual Saleable Production Tons
		(Million Tons)
Mine/Reserve		2023				2022				2021
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine			3.9				3.9				3.5
Oaktown Fuels No. 2 Mine			2.5				2.5				2.1
Total Oaktown Mining Complex Production			6.4				6.4				5.6

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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 customers with large scrubbed coal-fired power plantslocations in the State of Indiana. Our mines and coal reserves are strategically located in close proximity to our primary customers, which reduces transportation costs and thus provides us with a competitive advantage with respect to those customers; our closest customer’s plant is 13 miles away, and the farthest Indiana customer is 80 miles away. We have access to our primary customers directly through either the CSX railroad (NYSE: CSX) or the Indiana Rail Road which is majority owned by the CSX. Beginning in Q2 2018, our new Princeton Loop will be operational and allow us to access the NS Railroad (NYSE: NS), increasing our coal markets.

The majority of our coal is sold to investment grade customers who have scrubbed power plants; thus, we expect to be supplying these plants for many years.

President Trump Promotes Coal

Below is a timeline of some of the milestones accomplished for the coal industry thus far under the Trump administration:

November 8, 2016

Donald Trump was elected President of the United States of America. His administration has dramatically improved the regulatory environment in which we operate.

January 20, 2017

Donald Trump was inaugurated as the 45^th President of the United States.

February 15, 2017

Both the U.S. House of Representatives and the Senate passed resolutions disapproving the Stream Protection Rule (SPR) under the Congressional Review Act (CRA). President Trump signed the resolution on February 16, 2017, and, pursuant to the CRA, the SPR "shall have no force or effect" and the Office of Surface Mining (OSM) cannot promulgate a substantially similar rule absent future legislation.

 

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Currently, the Federal Surface Mining Control and Reclamation Act of 1977 (SMCRA) is implemented by each State’s respective State agency, which is the Department of Reclamation in Indiana. The SPR would have mandated additional approvals from Federal Agencies, suchOur future coal commitments are as U.S. Fish and Wildlife. The rule would have also imposed additional baseline data collection, surface/groundwater monitoring, financial assurance requirements and numerous other requirements.follows:

 

		3rd Party		Merom Power Plant
		Contracted		Contracted				Estimated
		tons		tons				Priced
Year		(millions)*		(millions)*		Total		per ton
2024		3.4		1.5		4.9		$	53.91
2025 - 2028 (total)		5.8		9.2		15.0			**
Total		9.2		10.7		19.9

February 17, 2017  ______________________

Scott Pruitt was confirmed as Administrator of the Environmental Protection Agency (EPA). As former Attorney General of the state of Oklahoma, he joined a coalition of state attorney generals in suing the EPA concerning the Clean Power Plan, the principal Obama-era policy aimed at reducing U.S. greenhouse gas emissions from the electricity sector.

February 28, 2017

President Trump signed an Executive Order regarding the “waters of the US” (WOTUS) rule.  The order requires the EPA and the Army Corps of Engineers to review the WOTUS rule and publish a proposed rule that rescinds or revises the rule as appropriate and consistent with law, keeps the Nation’s navigable waters free from pollution, promotes economic growth, minimizes regulatory uncertainty, and shows due regard for the roles of the Congress and the States under the Constitution.

In President Trump’s first full official speech to a joint session of Congress, he stated: “We’re going to stop the regulations that threaten the future and livelihood of our great coal miners.”

March 28, 2017

President Trump signed an Executive Order to dismantle many of the climate change policies enacted during the Obama era. The order takes steps to downplay the future costs of carbon emissions, walks back tracking of the federal government’s carbon emissions, rescinds a 2016 moratorium on coal leases on federal lands. It also begins the process of rescinding the EPA's Clean Power Plan to reduce carbon dioxide emissions from new and existing power plants.

April 13, 2017 

The EPA said it would review and reconsider the effluent limitations guidelines (ELG) rule which targets coal combustion generators’ ash transport wastewater, and wastewater discharges from flue-gas desulfurization and mercury control systems and would require power plants to install new treatment technologies. The rule has been challenged in court by a coalition of utilities. The EPA has issued an administrative stay to delay the compliance deadlines for the ELG rule as long as litigation is ongoing.

June 1, 2017

President Trump announced that the U.S. would pull out of the Paris Agreement steering away from a group of 194 other countries that have promised to curb planet-warming greenhouse gas emissions.

October 10, 2017

EPA Administrator Scott Pruitt announced that the EPA would seek to repeal the Clean Power Plan in its entirety.

January 25, 2018

The Trump administration eliminated a policy dictating how certain major sources of hazardous air pollutants are regulated. The repeal of the agency’s “once in, always in” policy. Under the new interpretation of the policy, “major sources” can be reclassed as “area sources,” which*     Contracted tons are subject to different standards when their emissions reach an enforceable limit.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

 

These actionsAs of December 31, 2023, we are encouraging and will be importantcommitted to us and the U.S. energy sector.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.

 

Our Coal Contracts

We sell coal to the following customers: Duke Energy Corporation (NYSE: DUK), Hoosier Energy, an electric cooperative, Indianapolis Power & Light Company (IPL), a wholly-owned subsidiary of The AES Corporation (NYSE: AES), Vectren Corporation (NYSE: VVC), and Orlando Utility Commission (OUC). In 2018, we have signed new sales contracts with two plants we have never shipped to before. One of the new customers is certainly due to the addition of our Princeton Rail LoopBased on the Norfolk Southern Railroad. The other iscontracted tons described above, we anticipate our mines will need to produce at a plant located in the Carolinas. We attribute the latter to the trend of ILB coals replacing coals from higher cost eastern basins.

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The table below reflects our projected tons. Some of our contracts contain language that allow our customers to increase or decrease tonnages throughout the year. In some cases, our customers are required to purchase their additional tonnage needs from us. We have 17.74.5 million tons committedton annualized pace for the next 5 years (2018foreseeable future to 2022), which represents 51% of our current projected sales.meet the Merom plant and third-party market demand.

		Targeted tons				Committed tons								Estimated price
Year		(millions)				(millions)				% Committed				per ton
2018			6.8				6.4				94	%		$	40.00
2019			7.0				4.5				64	%		$	41.00

 

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.

 

Asset Impairment Review

See Note 2Some utility customers have proposed shuttering certain plant units or entire plants in the coming years.  It remains to our consolidated financial statements.be seen whether these plans will be implemented. 

 

Reserve Table - Controlled Tons (in millions):

						2017 Year-End Reserves
		Tons				Annual
		Sold				Capacity				Proven				Probable				Total				Sulphur #				BTU
Oaktown 1 (assigned)			3.771				4.0				41.5				9.6				51.1				5.9				11,600
Oaktown 2 (assigned)			2.552				4.0				30.7				12.2				42.9				5.7				11,600
Carlisle (assigned)			-				2.5				21.8				5.5				27.3				4.4				11,500
Ace in the Hole (assigned)			0.240				0.4				0.9				-				0.9				2.0				10,900
Bulldog (unassigned)			-				-				19.6				16.2				35.8				4.5				11,300
Total			6.563				10.9				114.5				43.5				158.0
Assigned																			122.2
Unassigned																			35.8
Total																			158.0

Our assigned underground coal reserves are high sulfur (4.0# – 6.5#) with an average BTU content in the 11,500 -11,600 range. Our reserves have lower chlorine (<0.12%) than average ILB reserves of 0.22%.  Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%.  The relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants. As discussed below, the Ace surface mine is low sulfur (2.0#) with an average BTU content of 10,900. We have no metallurgical coal reserves, only steam (thermal) coal reserves. Below is a discussion of our current projects. Only tons greater than 4 feet in thickness are included in our underground reserves.

Oaktown 1 Mine (underground) – Assigned

We have 51.1 million controlled, salable tons of the Indiana #V coal seam. We began 2017 with 56.9 million tons controlled. Besides production, the remainder of the decrease relates to tons that were deemed unrecoverable due to geologic conditions combined with increases for new drilling and new leases. Oaktown 1 reserves are located in Knox County, IN.

Access to the Oaktown 1 Mine is via a 90-foot-deep box cut and a 2,200-foot slope, reaching coal in excess of 375 feet below the surface. In 2017, we added an elevator 7 miles from the slope allowing miners to enter closer to the active face, thereby reducing unproductive daily travel time.

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Oaktown 2 Mine (underground) – Assigned

We have 42.9 million controlled, saleable tons of the Indiana #V coal seam. We began 2017 with 53.5 million controlled tons. Besides production, the remainder of the decrease relates to tons that were deemed unrecoverable due to geologic and economic conditions based on new drilling. Oaktown 2 reserves are located in both Knox County, Indiana and Lawrence County, Illinois.

Access to the Oaktown 2 Mine is via an 80-foot-deep box cut and a 2,600-foot slope, reaching coal in excess of 400 feet below the surface.

Our underground mines are room and pillar mines that utilize developed entries for ventilation and transportation. Continuous miners extract coal from rooms by removing coal from the seam, leaving pillars to support the roof.  Coal haulers are used to transport coal to a conveyor belt for transport to the surface.  The two Oaktown mines are separated by a sandstone channel.  The coal seam thickness ranges from 4 feet to over 9 feet.  The Oaktown mines share the same wash plant which is rated at 1,800 tons per hour.  The two mines are connected to a rail loadout that can store two 120 car trains at once and is serviced by the CSX Railroad and Indiana Railroad.  Coal is also transported via truck to customers.

Carlisle Mine (underground) – Assigned

We have 27.3 million controlled, saleable tons at our Carlisle Mine. The mine is located near the town of Carlisle, Indiana in Sullivan County and became operational in January 2007. The coal is accessed with a slope to a depth of 340'. The coal is mined in the Indiana #V coal seam which is highly volatile bituminous coal and has been extensively mined by underground and surface methods in the general area. The coal thickness in the project area is 4' to 7'. The Carlisle Mine is completely developed but was idle for the entirety of 2017.

Ace in the Hole Mine (Ace) (surface) – Assigned

The Ace mine is near Clay City, Indiana in Clay County and 42 road miles northeast of the Carlisle Mine. We control .9 million tons of proven coal reserves of which we own ..5 million tons in fee.  The two primary seams are low sulfur coal (~2# SO₂), which make up .8 million of the .9 million tons controlled.  Mine development began in late December 2012, and we began shipping coal in late August 2013.  We truck low sulfur coal from Ace to Oaktown to blend with high sulfur coal. Many utilities in the southeastern U.S. have scrubbers with lower sulfur limits (4.5# SO₂) which cannot accept the higher sulfur contents of the ILB (4.5# - 6.5# SO₂). Blending high sulfur coal to a lower sulfur specification enables us to market our high sulfur coals to more customers. We expect the maximum capacity of Ace to be 0.4 tons annually.

The Ace mine is a multi-seam open pit strip mine. The majority of the seams are sold raw, but some of the seams will be washed prior to sales depending on quality. To convert the tons sold raw, the in-place tonnage is multiplied by a pit recovery of 94% based on seam thickness. To convert the tons sold washed, the in-place tonnage is multiplied by a pit recovery based on seam thickness then reduced by the projected wash plant recovery of 72%.

Bulldog Reserves (underground) – Unassigned

We have leased roughly 19,300 acres in Vermilion County, Illinois near the village of Allerton.  Based on our reserve estimates we currently control 35.8 million tons of coal.  A considerable amount of our leased acres has yet to receive any exploratory drilling.

In October 2017, we entered into an agreement to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase the property for eight years. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. The permit will be issued upon submittal of a fee and bond which is required to be submitted within 12 months of the notification.

Full-scale mine development will not commence until we have a sales commitment. We estimate the costs to develop this mine to be $150 million at full capacity of 3.0 million tons annually.

Unassigned reserves represent coal reserves that would require new mineshafts, mining equipment, and plant facilities before operations could begin on the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin.

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Below is a map that shows the locations of our mines.

 

Railroad Legend:

CSX – CSX Railroad

INRD – Indiana Rail Road

ISRR – Indiana Southern Railroad

NS – Norfolk Southern Railway

Mine and Wash Plant Recovery and Capacity

		Mine recovery				Wash plant recovery*				Wash Plant Capacity (Clean Tons)
Oaktown 1			49	%			81	%		8.0 million**
Oaktown 2			49	%			81	%
Carlisle			53	%			81	%		2.5 million
Bulldog			45	%			77	%

* Does not include out-of-seam material extracted during the mining process.

** Oaktown 1 and Oaktown 2 share the wash plant.

Liquidity and Capital Resources

																		2025 and
Contractual Obligations (in thousands)		Total				2018				2019-2021				2022-2024				thereafter
Long-term debt (matures August, 2019)		$	201,992			$	35,000			$	166,992			$	-			$	-
Future interest obligations			15,700				10,100				5,600				-				-
Reclamation obligations			13,806				300				5,315				3,011			$	5,180
		$	231,498			$	45,400			$	177,907			$	3,011			$	5,180

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As set forth in our StatementConsolidated Statements of Cash Flows, cash provided by operations was $62$59.4 million and $54.2 million for 2017.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 amount was adequate to fundoffset by lower margins from our maintenancepower plant and a decrease in working capital. 

Our capital expenditures for coal properties of $11.1 million, our debt service requirements of $36.6 million, and our dividend of $4.9 million. Our capexexpenditure budget for 20182024 is $31$43 million, of which $16 millionthe majority is for maintenance capex.  CashOf 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 for 2018 should againgenerated primarily by our expected higher coal margins in 2023 to fund our maintenance capital expenditures debt service, and our dividend.debt service.

 

See Note 3 4 to our consolidated financial statements for additional discussion about our bank debt.debt and related liquidity.

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Off-Balance Sheet Arrangements

 

Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. Included inWe have recorded the contractual obligations table arepresent value of reclamation obligations of $13.8$16.6 million, which areincluding $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 $25$37.5 million to cover ARO.

 

Capital Expenditures (capex)

 

For 2017,the year ended December 31, 2023, our capex was $28.6$75.4 million allocated as follows (in millions):

 

Oaktown – investment		$	10.1
Oaktown – maintenance capex			11.1
Princeton Rail Loop			6.3
Other projects			1.1
Capex per the Consolidated Statement of Cash Flows		$	28.6

Oaktown – maintenance capex		$	36.2
Oaktown – investment			18.3
Prosperity mine			0.8
Freelandville mine			1.2
Merom plant			18.8
Other			0.1
Capex per the Consolidated Statements of Cash Flows		$	75.4

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

		2023				2022
OPERATING REVENUES:		$	435,425			$	293,344
EXPENSES:
Operating expenses			311,041				236,416
Depreciation, depletion and amortization			48,365				43,612
Asset retirement obligations accretion			1,228				1,010
Exploration costs			904				651
General and administrative			10,287				7,919
Total operating expenses			371,825				289,608
INCOME (LOSS) FROM OPERATIONS		$	63,600			$	3,736

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. 

 

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ResultsDepreciation, 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

		2023				2022
OPERATING REVENUES:		$	268,341			$	66,316
EXPENSES:
Operating expenses			231,560				29,608
Depreciation, depletion and amortization			18,739				3,117
Asset retirement obligations accretion			576				—
General and administrative			4,914				2,086
Total operating expenses			255,789				34,811
INCOME FROM OPERATIONS		$	12,552			$	31,505

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. 

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The following tabletables presenting our quarterly results of operations should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of their Annual Report onthis 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 following table presentstables present our unaudited quarterly results of operations for the eight quarters ended December 31, 2017. This table includes2023, 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.

 

		Dec-31				Sep-30				Jun-30				Mar-31				Dec-31				Sep-30				Jun-30				Mar-31
		2017				2017				2017				2017				2016				2016				2016				2016
Revenue:
Coal sales		$	68,922			$	73,896			$	62,829			$	62,555			$	71,495			$	65,360			$	66,274			$	75,795
Equity income (loss) in equity method investments			(62	)			169				27				231				(1,130	)			(80	)			174				(400	)
Other			440				403				1,456				767				869				487				2,116				490
Total revenue		$	69,300			$	74,468			$	64,312			$	63,553			$	71,234			$	65,767			$	68,564			$	75,885
Costs and expenses:
Operating costs and expenses			52,025				54,354				44,079				39,692				50,663				46,940				45,397				49,777
DD&A			9,962				9,729				9,101				9,703				9,385				7,942				9,056				9,182
ARO accretion			221				219				214				207				265				260				255				249
Coal exploration costs			288				152				275				139				505				354				395				419
SG&A			2,883				2,859				6,578				2,658				2,444				2,585				2,729				2,762
Interest			2,751				3,229				3,342				3,091				2,148				2,601				4,497				5,596
Asset impairment			-				-				-				-				16,560				-				-				-
Total cost and expenses			68,130				70,542				63,589				55,490				81,970				60,682				62,329				67,985
Income (loss) before income taxes			1,170				3,926				723				8,063				(10,736	)			5,085				6,235				7,900
Less income taxes:
Current			(1,590	)			(2,532	)			1,357				17				103				(270	)			(768	)			768
Deferred			(18,597	)			2,542				(1,023	)			632				(7,012	)			1,033				1,150				970
Total income taxes			(20,187	)			10				334				649				(6,909	)			763				382				1,738
Net income (loss)			21,357				3,916				389				7,414				(3,827	)			4,322				5,853				6,162
Net income (loss) per share:
Basic and diluted		$	0.69			$	0.13			$	0.01			$	0.25			$	(0.13	)		$	0.14			$	0.19			$	0.21
Weighted average shares outstanding:
Basic and diluted			29,830				29,774				29,503				29,413				29,287				29,252				29,251				29,251

Oaktown’s operating costs were $27.59/ton and $30.44/ton for the year and quarter ended December 31, 2017, respectively. We expect Oaktown’s costs to range from $28 to $30 for 2018. For 2018, we expect our SG&A to be $11 million annually and costs associated with the Prosperity and Carlisle mines to be $6 million annually (reflected in operating costs and expenses).

		Mar-31				Jun-30				Sep-30				Dec-31
		2023				2023				2023				2023				Total 2023
SALES AND OPERATING REVENUES:
Coal sales		$	94,602			$	88,574			$	97,420			$	81,330			$	361,926
Electric sales			92,392				71,017				67,403				37,115				267,927
Other revenues			1,340				1,603				945				739				4,627
Total revenue			188,334				161,194				165,768				119,184				634,480
EXPENSES:
Operating expenses			133,521				115,420				119,042				105,407				473,390
Depreciation, depletion and amortization			17,976				17,169				16,230				15,836				67,211
Asset retirement obligations accretion			451				461				468				424				1,804
Exploration costs			206				305				171				222				904
General and administrative			6,947				5,595				6,054				7,563				26,159
Total operating expenses			159,101				138,950				141,965				129,452				569,468
INCOME (LOSS) FROM OPERATIONS			29,233				22,244				23,803				(10,268	)			65,012
Bank debt and other interest			(3,899	)			(3,541	)			(3,030	)			(3,241	)			(13,711	)
Loss on extinguishment of debt			—				—				(1,491	)			—				(1,491	)
Equity method investment income			69				(217	)			(177	)			(227	)			(552	)
INCOME (LOSS) BEFORE INCOME TAXES			25,403				18,486				19,105				(13,736	)			49,258
INCOME TAX EXPENSE (BENEFIT):
Current			432				61				(178	)			(479	)			(164	)
Deferred			2,920				1,510				3,208				(3,009	)			4,629
Total income tax expense (benefit)			3,352				1,571				3,030				(3,488	)			4,465
NET INCOME (LOSS)		$	22,051			$	16,915			$	16,075			$	(10,248	)		$	44,793
NET INCOME (LOSS) PER SHARE:
Basic		$	0.67			$	0.51			$	0.49			$	(0.31	)		$	1.35
Diluted		$	0.61			$	0.47			$	0.44			$	(0.31	)		$	1.25
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			32,983				33,137				33,140				33,245				33,133
Diluted			36,740				36,708				36,848				33,245				36,827

 

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		Mar-31				Jun-30				Sep-30				Dec-31
		2022				2022				2022				2022				Total 2022
SALES AND OPERATING REVENUES:
Coal sales		$	57,010			$	64,161			$	83,562			$	84,643			$	289,376
Electric sales			—				—				—				66,252				66,252
Other revenues			1,897				1,768				1,522				1,176				6,363
Total revenue			58,907				65,929				85,084				152,071				361,991
EXPENSES:
Operating expenses			54,601				51,394				64,557				96,056				266,608
Depreciation, depletion and amortization			9,531				11,164				11,187				14,993				46,875
Asset retirement obligations accretion			246				250				255				259				1,010
Exploration costs			57				215				121				258				651
General and administrative			3,149				3,722				3,569				5,977				16,417
Total operating expenses			67,584				66,745				79,689				117,543				331,561
INCOME (LOSS) FROM OPERATIONS			(8,677	)			(816	)			5,395				34,528				30,430
Bank debt and other interest			(1,710	)			(1,770	)			(2,360	)			(2,438	)			(8,278	)
Amortization and swap related interest			(74	)			(567	)			(995	)			(1,098	)			(2,734	)
Equity method investment income			150				188				168				(63	)			443
INCOME (LOSS) BEFORE INCOME TAXES			(10,311	)			(2,965	)			2,208				30,929				19,861
INCOME TAX EXPENSE (BENEFIT):
Current			—				—				—				—				—
Deferred			(177	)			421				596				916				1,756
Total income tax expense (benefit)			(177	)			421				596				916				1,756
NET INCOME (LOSS)		$	(10,134	)		$	(3,386	)		$	1,612			$	30,013			$	18,105
NET INCOME (LOSS) PER SHARE:
Basic		$	(0.33	)		$	(0.11	)		$	0.05			$	0.91			$	0.57
Diluted		$	(0.33	)		$	(0.11	)		$	0.05			$	0.83			$	0.55
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			30,785				30,785				32,983				32,983				32,043
Diluted			30,785				30,809				33,268				36,428				33,649

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

  

		1st 2017				2nd 2017				3rd 2017				4th 2017				T4Qs
All Mines																						1st 2023				2nd 2023				3rd 2023				4th 2023				T4Qs
Tons produced			1,917				1,647				1,487				1,561				6,612				2,006				1,723				1,594				1,331				6,654
Tons sold			1,555				1,548				1,786				1,685				6,574				1,693				1,714				2,054				1,461				6,922
Coal sales		$	62,555			$	62,829			$	73,896			$	68,922			$	268,202			$	94,602			$	112,171			$	134,400			$	91,714			$	432,887
Average price/ton		$	40.23			$	40.59			$	41.38			$	40.90			$	40.80
Average price per ton																						$	55.88			$	65.44			$	65.43			$	62.77			$	62.54
Wash plant recovery in %			71	%			69	%			70	%			68	%							70	%			67	%			65	%			62	%
Operating costs		$	39,692			$	44,079			$	54,354			$	52,025			$	190,150			$	65,700			$	71,168			$	95,592			$	78,581			$	311,041
Average cost/ton		$	25.53			$	28.47			$	30.43			$	30.88			$	28.92
Average cost per ton																						$	38.81			$	41.52			$	46.54			$	53.79			$	44.94
Margin		$	22,863			$	18,750			$	19,542			$	16,897			$	78,052			$	28,902			$	41,003			$	38,808			$	13,133			$	121,846
Margin/ton		$	14.70			$	12.11			$	10.94			$	10.03			$	11.87
Margin per ton																						$	17.07			$	23.92			$	18.89			$	8.99			$	17.60
Capex		$	5,144			$	6,711			$	9,473			$	7,294			$	28,622			$	12,639			$	14,445			$	11,570			$	17,867			$	56,521
Maintenance capex		$	2,887			$	3,032			$	2,961			$	2,520			$	11,400			$	7,778			$	9,754			$	7,938			$	13,567			$	39,037
Maintenance capex/ton		$	0.54			$	4.25			$	2.52			$	1.50			$	1.73
Maintenance capex per ton																						$	4.59			$	5.69			$	3.86			$	9.29			$	5.64

  

		1st 2016				2nd 2016				3rd 2016				4th 2016				T4Qs
All Mines																						1st 2022				2nd 2022				3rd 2022				4th 2022				T4Qs
Tons produced			1,524				1,448				1,501				1,640				6,113				1,397				1,762				1,663				1,721				6,543
Tons sold			1,629				1,464				1,485				1,739				6,317				1,377				1,595				1,705				1,664				6,341
Coal sales		$	75,795			$	66,274			$	65,360			$	71,495			$	278,924			$	57,010			$	64,161			$	83,563			$	84,641			$	289,375
Average price/ton		$	46.53			$	45.27			$	44.01			$	41.11			$	44.15
Average price per ton																						$	41.40			$	40.23			$	49.01			$	50.87			$	45.64
Wash plant recovery in %			65	%			63	%			68	%			67	%							67	%			71	%			69	%			68	%
Operating costs		$	49,777			$	45,397			$	46,940			$	50,663			$	192,777			$	54,443			$	50,776			$	63,876			$	67,319			$	236,414
Average cost/ton		$	30.56			$	31.01			$	31.61			$	29.13			$	30.52
Average cost per ton																						$	39.54			$	31.83			$	37.46			$	40.46			$	37.28
Margin		$	26,018			$	20,877			$	18,420			$	20,832			$	86,147			$	2,567			$	13,385			$	19,687			$	17,322			$	52,961
Margin/ton		$	15.97			$	14.26			$	12.40			$	11.98			$	13.64
Margin per ton																						$	1.86			$	8.39			$	11.55			$	10.41			$	8.35
Capex		$	6,053			$	1,822			$	3,935			$	8,022			$	19,832			$	9,082			$	13,821			$	15,096			$	12,368			$	50,367
Maintenance capex		$	2,984			$	904			$	1,709			$	5,301			$	10,898			$	4,481			$	7,600			$	6,625			$	5,748			$	24,454
Maintenance capex/ton		$	1.83			$	0.62			$	1.15			$	3.05			$	1.73
Maintenance capex per ton																						$	3.25			$	4.76			$	3.89			$	3.45			$	3.86

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.

		1st 2023				2nd 2023				3rd 2023				4th 2023				2023
MWh sold			1,262				1,043				1,307				612				4,224
Capacity revenue		$	15,970			$	17,155			$	13,012			$	10,018			$	56,155
Delivered energy and PPA revenue			76,422				53,862				54,391				27,097				211,772
Total electric sales			92,392				71,017				67,403				37,115				267,927
Less amortization of contract liability			(33,347	)			(19,555	)			(10,281	)			(7,347	)			(70,530	)
Total electric sales less amortization of contract liability		$	59,045			$	51,462			$	57,122			$	29,768			$	197,397
Average price/MWh of delivered energy and PPA revenue less amortization of contract liability		$	34.13			$	32.89			$	33.75			$	32.27			$	35.18
Operating expenses (on a segment basis)		$	67,682			$	55,996			$	64,172			$	43,710			$	231,560
Less fixed costs			(12,807	)			(11,693	)			(11,858	)			(22,259	)			(58,617	)
Less amortization of contract asset			(17,778	)			(12,962	)			-				-				(30,740	)
Operating expenses less fixed costs and amortization of contract asset		$	37,097			$	31,341			$	52,314			$	21,451			$	142,203
Average variable cost/MWh of operating expenses less fixed costs and amortization of contract asset		$	29.40			$	30.05			$	40.03			$	35.05			$	33.44
Energy and PPA margin less fixed costs and amortization of contract asset and liabilities		$	5,978			$	2,966			$	(8,204	)		$	(1,701	)		$	(961	)
Energy & PPA margin/MWh less fixed costs amortization of contract asset and liabilities		$	4.74			$	2.84			$	(6.28	)		$	(2.78	)		$	(0.23	)

 

2017 v. 2016

For 2017, we sold 6,574,000 tons at an average price of $40.80/ton. For 2016, we sold 6,317,000 tons at an average price of $44.15/ton. The decrease in average price per ton is the result of our contract mix, expiration of contracts, and acquisition of other contracts.

Operating costs and expenses averaged $28.92/ton ($27.59/ton at our operating Oaktown mines) in 2017 compared to $30.52/ton ($28.02/ton at our operating Oaktown mines) in 2016.  The reduction in cost was due to two primary factors. First, we made a conscious effort to increase production in the first half of the year in anticipation of stronger market demand. Second, we added new haulage equipment to some of the units at the Oaktown mines creating production efficiencies of up to 30% to those units. Both of these factors combined led to an 8% increase in production. In Q4 2017, we also opened a new elevator at Oaktown 1 which reduces miner travel time, and we acquired additional haulage equipment which will continue to maintain our low-cost structure.

Our Sunrise Coal employees totaled 736 at December 31, 2017 compared to 742 at December 31, 2016.

SG&A costs increased in 2017 by $4.5 million due primarily to a stock bonus of $3.8 million awarded to executives as reported in our 8-K filed May 17, 2017, increased RSU amortization and employee pay increases in 2017.

37

2016 v. 2015

For 2016, we sold 6,317,000 tons at an average price of $44.15/ton. For 2015, we sold 7,447,000 tons at an average price of $45.59/ton.

Operating costs and expenses averaged $30.52/ton in 2016 compared to $31.95 in 2015.  Our Sunrise Coal employees totaled 742 at December 31, 2016, compared to 740 at December 31, 2015.

SG&A costs were higher in 2015 due to amortization of RSUs and accruals of bonuses related to our Vectren Fuels acquisition in 2014.  SG&A as a percentage of coal revenue remained consistent at 3.8% in 2016 and 3.7% in 2015.

We incurred an asset impairment of $16.6 million due to our decision to seal the north portal of the Carlisle mine. We determined that the North end had deteriorated to the point that it could no longer be safely and profitably mined.

At the beginning of 2016, we changed from the straight-line method to the units-of-production method in computing the depreciation for continuous miners. This change in estimate reduced our DD&A expense for the year ended December 31, 2016, by $2.6 million. This change better reflects the usage of our continuous miners considering our reduced production in 2016. Due to idle equipment at Carlisle, we stopped depreciating specific underground equipment resulting in a $4.4 million reduction in depreciation for the year ended December 31, 2016.

Current Projects

Princeton Rail Loop

Construction began in the fourth quarter of 2017 on the Princeton Loop, a truck to rail coal loading facility that will be located 6 miles west of Princeton, IN, on Highway 64 and 37 miles southwest of our Oaktown mining facility. The facility will include the ability to unload trucks, blend coals, load 135 car unit trains in four hours and store over 4.0 million tons of coal.  The new facility will primarily serve utility coal plants served by the Norfolk Southern Railway Company once the rail facility is completed in the spring of 2018. The rail loop will provide access to new markets and customers.

Hourglass Sands

In February 2018, we formed and made an initial investment of $4 million in Hourglass Sands, LLC, a frac sand mining company in the State of Colorado. We own 100% of the Class A units and will account for Hourglass Sands LLC as a wholly owned subsidiary of Hallador Energy Company. Class A units are entitled to 100% of profit until our capital investment and interest is returned, then 90% of profits are allocated to Class A Units with the remainder to Class B units. A Yorktown company associated with one of our directors also invested $4 million for a royalty interest in the sand project.

We currently control a permitted sand reserve near Colorado Springs. We are negotiating to have a third party wash our sand and expect to truck test shipments to customers in the DJ Basin this summer. We believe we control the only permitted frac sand mine in the State of Colorado. We do not anticipate Hourglass Sands, LLC to be profitable in 2018, but are excited about its growth potential in future years.

MSHA Reimbursements

Some of our legacy coal contracts allow us to pass on to our customers certain costs incurred resulting from changes in costs to comply with mandates issued by MSHA or other government agencies.  We do not recognize any revenue until our customers have notified us that they accept the charges.

We submitted our incurred costs for 2012 in June 2015 and received $1.75 million from one of our customers in June 2016. We received an additional payment of $1.25 million in Q2 2017 for 2012 costs. We also received payments in 2017 from several customers for smaller regulation changes that went into effect in 2016. As stated above we do not record such reimbursements as revenue until they have been agreed to by our customers.

Incurred costs for 2013 – 2017 will be submitted in 2018. 2013 costs are expected to be between $2.0 million and $2.7 million. Such reimbursable costs for 2014 through 2017 are not expected to be material.

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Income Taxes

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (Tax Act). The Tax Act reduces the corporate tax rate to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 requires the effect of a change in tax laws or rates to be recognized as of the date of enactment, we are required to adjust deferred tax assets and liabilities as of December 22, 2017. Accordingly, we have recorded a deferred income tax benefit of $16.4 million for the year ended December 31, 2017.

Our effective tax rate (ETR) for 2017 was (138)% compared to (48)% for 2016 and 27% for 2015. The negative ETR in 2017 is due primarily to the effects of the Tax Act adjustment to our deferred taxes and prior year tax return reconciliation which were all recorded discretely for the year ended December 31, 2017. The negative ETR in 2016 is due to the combination of the reduction in book income before taxes because of the asset impairment expense, permanent tax benefits of statutory depletion in excess of tax basis in the mining properties, the captive insurance company effects, and stock based compensation expense. The tax rate for the years ended December 31, 2017 and 2016 are not predictive of future tax rates due to the deferred income tax benefit of the Tax Act. The tax rate would have been 9% without the effects of the deferred income tax benefit of the Tax Act and the prior year tax return reconciliation. Historically, our actual effective tax rates have been lower than the statutory effective rate primarily due to the benefit received from statutory depletion allowances. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income taxes.

Critical Accounting Estimates

 

We believe that the estimates of our coal reserves, our business acquisitions, our interest rate swaps, ourasset retirement obligation liabilities, deferred tax accounts, valuation of inventory, treatment of business combinations, and the estimates used in our impairment analysis are our only critical accounting estimates.

 

The reserve estimates are used in the DD&A calculationdepreciation, depletion and inamortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our DD&Adepreciation, 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. 

 

We account for business combinations using the purchase method of accounting. The purchase methodSMCRA 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 determinerestore affected surface areas to approximate the fairoriginal 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 all acquiredtheir 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 including identifiable intangible assetsare amortized using the units-of-production method over estimated recoverable (proven and all assumed liabilities. The totalprobable) 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 acquisitionsreclamation will be recognized as a gain or loss when the obligation is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.

The fair value of our interest rate swaps is determined using a discounted future cash flow model based on the key assumption of anticipated future interest rates.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 willwould 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.

 

New Accounting StandardsInventory 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.  

 

See “Item 8. Financial Statements and Supplementary Data – Note 1. Summary

41

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Table of Significant Accounting Policies” for a discussion of new accounting standards.

39

Contents

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Substantially all our business is conducted in Indiana, so we have no foreign exchange currency risk.

 

We have exposureaccount for business acquisitions as either asset acquisitions or business combination depending on the circumstances as outlined in ASC 805-50. For acquisitions accounted for as a business combination, we record the assets acquired, including identified intangible assets and liabilities assumed at their fair value.  For acquisitions accounted for as asset acquisitions, we allocate the fair value of consideration exchanged in the transaction to price riskeach of the acquired assets based upon their relative fair value.  Fair value in many instances involves estimates based on third-party valuations, such as appraisals, or internal valuations based on discounted cash flow analyses or other valuation techniques. Those estimates are subject to a high degree of uncertainty, thus we typically will retain professionals in the relevant industries of the acquiree to assist us with our analysis and valuations.  See “Item 8. Financial Statements - Note 15 - Acquisition” for suppliesmore information on the Merom Acquisition.

Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are used directly or indirectlylargely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. Management evaluates assets for impairment through an established process in the normal course of coal productionwhich changes to significant assumptions such as steel, electricityprices, volumes and other supplies. We manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations.  We do not utilize any commodity price-hedges or other derivatives related to these risks. The Trump administration recently announced that they would like to assess tariffs on steel imports infuture development plans are reviewed. If, upon review, the future which would add to this risk.

Borrowings under our credit agreement are at variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by changes in interest rates.  As disclosed in Note 3 to our consolidated financial statements we entered into swap agreements to fix the LIBOR componentsum of the interest rate to achieve an effective fixed rate of no greaterundiscounted pre-tax cash flows is less than 5% on the original term loan balance and on $100 million of the revolver. Quarterly, we mark-to-market thecarrying value of the swaps. For 2017,asset group, the change incarrying value was $723,000 and not considered material. As short-term interest rates rise (especiallyis written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the two-year U.S. treasury note) thefair value of impaired assets is typically determined based on the swap increasespresent values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and as they fallrelated fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the value decreases.date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

 

We expect to continue selling a significant portion

42

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Table 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.

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Contents

 

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

  

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)	4244
Consolidated Balance Sheets	4446
Consolidated Statements of Comprehensive IncomeOperations	4547
Consolidated Statements of Cash Flows	48
Consolidated Statement of Cash FlowsStockholders’ Equity	4650
Consolidated Statement of Stockholders' Equity	47
Notes to Consolidated Financial Statements	4851

  

41

  

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting Firm

 

To the Shareholders and Board of Directors and Stockholders

Hallador Energy Company

Denver, Colorado

OPINIONS ON THE FINANCIAL STATEMENTS AND INTERNAL CONTROL OVER FINANCIAL REPORTINGOpinion on the financial statements

 

We have audited the accompanying consolidated balance sheets of Hallador Energy Company (a Colorado corporation) and subsidiaries (the "Company"“Company”) as of December 31, 20172023 and 2016, and2022, the related consolidated statements of income, comprehensive income, stockholders' equity, andoperations, cash flows and stockholders’ equity for each yearof the two years in the three-year period ended December 31, 2017,2023, and the related notes (collectively referred to as the "consolidated financial statements"“financial statements”). We have also audited the Company's internal control over financial reporting as of December 31, 2017, based on the criteria established in Internal Control - Integrated Framework: (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172023 and 2016,2022, and the results of its operations and its cash flows for each yearof the two years in the three-year period ended December 31, 2017,2023, in conformity with accounting principles generally accepted in the United States of America. Also,

We also have audited, in our opinion,accordance with the standards of the Public Company maintained, in all material respects, effectiveAccounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017,2023, based on criteria established in the 2013 Internal Control - —Integrated Framework: (2013)Framework issued by COSO.

the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 14, 2024 expressed an unqualified opinion.

 

BASIS FOR OPINIONSBasis for opinion

 

The Company's management is responsible for these consolidatedThese financial statements for maintaining effective internal control over financial reporting, and for its assessmentare the responsibility of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting.Company’s management. Our responsibility is to express an opinion on the Company's consolidatedCompany’s financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the auditsaudit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

fraud. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

42

DEFINITION AND LIMITATIONS OF INTERNAL CONTROL OVER FINANCIAL REPORTINGopinion.

 

A company's internal control over financial reportingCritical audit matter

The critical audit matter communicated below is a process designedmatter arising from the current period audit of the financial statements that was communicated or required to provide reasonable assurance regardingbe communicated to the reliabilityaudit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial reportingstatements, taken as a whole, and we are not, by communicating the preparationcritical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Asset retirement obligations

As of December 31, 2023, the Company’s asset retirement obligations totaled $16.7 million. As described further in Note 1 to the consolidated financial statements, the Company’s asset retirement obligations are associated with retirement of long-lived assets and recognized at fair value at the time the obligations are incurred.  The Company reviews its asset retirement obligations at least annually and makes necessary adjustments for external purposesrevisions of inputs and assumptions utilized in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertainthe calculations.  The calculation of asset retirement obligations requires significant management judgement due to the maintenanceinherent complexity in estimating the amount and timing of recordsfuture reclamation activities. We identified the accounting for the asset retirement obligations as a critical audit matter.

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The principal consideration for our determination that the accounting for the asset retirement obligations is a critical audit matter is that management utilized significant judgment in reasonable detail, accuratelydetermining the amount of asset retirement obligations.  In particular, the obligations value is estimated based upon a discounted cash flow technique and fairly reflectincludes inputs and assumptions related to reclamation costs and the transactions and dispositionstiming of reclamation activities.  Accordingly, auditing management’s assumptions involved a high degree of subjectivity due to the assetsuncertainty of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the consolidated financial statements.management’s significant judgements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subjectOur audit procedures related to the risk that controls may become inadequate because of changes in conditions, or thataccounting for asset retirement obligations included the degree of compliance with the policies or procedures may deteriorate.following, among others:

 

/s/ EKS&H LLLP

●

We tested the design and operating effectiveness of internal controls over the asset retirement obligations estimation and recognition process.

	●	We assessed the reasonableness of the Company's methodology to calculate asset retirement obligations.
	●	We tested the completeness and accuracy of the underlying data used in management's asset retirement obligations calculation.

March 12, 2018

●

We evaluated the reasonableness of significant judgements including inflation rate, credit-adjusted risk-free rate, reclamation cost estimates and timing of expected reclamation activities.

Denver, Colorado

●

We interviewed the Company's professionals with specialized skill and knowledge regarding the regulatory requirements and mine plans.

/s/ GRANT THORNTON LLP

 

We have served as the Company'sCompany’s auditor since 2003.2022.

Tulsa, Oklahoma

March 14, 2024

 

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PART I - FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Hallador Energy Company

Consolidated Balance Sheets

As of December 31,

(in thousands)

		2023				2022
ASSETS
Current assets:
Cash and cash equivalents		$	2,842			$	3,009
Restricted cash			4,281				3,417
Accounts receivable			19,937				29,889
Inventory			23,075				49,796
Parts and supplies			38,877				28,295
Contract asset - coal purchase agreement			—				19,567
Prepaid expenses			2,262				4,546
Total current assets			91,274				138,519
Property, plant and equipment:
Land and mineral rights			115,486				115,595
Buildings and equipment			537,131				534,129
Mine development			158,642				140,108
Finance lease right-of-use assets			12,346				—
Total property, plant and equipment			823,605				789,832
Less - accumulated depreciation, depletion and amortization			(334,971	)			(309,370	)
Total property, plant and equipment, net			488,634				480,462
Investment in Sunrise Energy			2,811				3,988
Other assets			7,061				7,585
Total assets		$	589,780			$	630,554
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net		$	24,438			$	33,031
Accounts payable and accrued liabilities			62,908				82,972
Current portion of lease financing			3,933				—
Deferred revenue			23,062				35,485
Contract liability - power purchase agreement and capacity payment reduction			43,254				88,114
Total current liabilities			157,595				239,602
Long-term liabilities:
Bank debt, net			63,453				49,713
Convertible notes payable			10,000				10,000
Convertible notes payable - related party			9,000				9,000
Long-term lease financing			8,157				—
Deferred income taxes			9,235				4,606
Asset retirement obligations			14,538				17,254
Contract liability - power purchase agreement			47,425				84,096
Other			1,789				1,259
Total long-term liabilities			163,597				175,928
Total liabilities			321,192				415,530
Commitments and contingencies
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued			—				—
Common stock, $.01 par value, 100,000 shares authorized; 34,052 and 32,983 issued and outstanding, respectively			341				330
Additional paid-in capital			127,548				118,788
Retained earnings			140,699				95,906
Total stockholders’ equity			268,588				215,024
Total liabilities and stockholders’ equity		$	589,780			$	630,554

 The accompanying notes are an integral part of these Consolidated Financial Statements

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Hallador Energy Company

Consolidated Statements of Operations 

For the years ended December 31,

(in thousands, except per share data)

    

		2017				2016
ASSETS
Current assets:
Cash and cash equivalents		$	12,483			$	9,788
Restricted cash (Note 8)			3,811				2,817
Certificates of deposit			1,495				7,315
Marketable securities			1,907				1,763
Accounts receivable			16,762				22,307
Prepaid income taxes			2,899				-
Coal inventory			12,804				10,100
Parts and supply inventory			10,043				10,091
Purchased coal contracts			-				8,922
Prepaid expenses			9,433				9,647
Total current assets			71,637				82,750
Coal properties, at cost:
Land and mineral rights			129,724				126,303
Buildings and equipment			356,911				339,999
Mine development			136,762				126,037
Total coal properties, at cost			623,397				592,339
Less - accumulated DD&A			(203,391	)			(169,579	)
Total coal properties, net			420,006				422,760
Investment in Savoy (Note 11)			8,037				7,577
Investment in Sunrise Energy (Note 11)			3,853				4,122
Other assets (Note 7)			14,660				14,114
Total assets		$	518,193			$	531,323
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net (Note 3)		$	33,171			$	28,796
Accounts payable and accrued liabilities (Note 14)			21,115				19,918
Total current liabilities			54,286				48,714
Long-term liabilities:
Bank debt, net (Note 3)			165,773				204,944
Deferred income taxes			28,728				45,174
Asset retirement obligations (ARO)			13,506				13,115
Other			6,577				2,486
Total long-term liabilities			214,584				265,719
Total liabilities			268,870				314,433
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued			-				-
Common stock, $.01 par value, 100,000 shares authorized; 29,955 and 29,413 shares outstanding, respectively			299				294
Additional paid-in capital			97,873				93,816
Retained earnings			150,236				122,052
Accumulated other comprehensive income			915				728
Total stockholders’ equity			249,323				216,890
Total liabilities and stockholders’ equity		$	518,193			$	531,323

		2023				2022
SALES AND OPERATING REVENUES:
Coal sales		$	361,926			$	289,376
Electric sales			267,927				66,252
Other revenues			4,627				6,363
Total sales and operating revenues			634,480				361,991
OPERATING EXPENSES:
Operating expenses			473,390				266,608
Depreciation, depletion and amortization			67,211				46,875
Asset retirement obligations accretion			1,804				1,010
Exploration costs			904				651
General and administrative			26,159				16,417
Total operating expenses			569,468				331,561
INCOME FROM OPERATIONS			65,012				30,430
Interest expense (1)			(13,711	)			(11,012	)
Loss on extinguishment of debt			(1,491	)			—
Equity method investment (loss) income			(552	)			443
INCOME BEFORE INCOME TAXES			49,258				19,861
INCOME TAX EXPENSE (BENEFIT):
Current			(164	)			—
Deferred			4,629				1,756
Total income tax expense			4,465				1,756
NET INCOME		$	44,793			$	18,105
NET INCOME PER SHARE:
Basic		$	1.35			$	0.57
Diluted		$	1.25			$	0.55
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			33,133				32,043
Diluted			36,827				33,649

See

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(1) Interest Expense:
Interest on bank debt		$	8,636			$	7,563
Other interest			1,842				715
Amortization and swap related interest:
Payments on interest rate swap, net of changes in value			—				(867	)
Amortization of debt issuance costs			3,233				3,601
Total amortization and swap related interest			3,233				2,734
Total interest expense		$	13,711			$	11,012

The accompanying notes.notes are an integral part of these Consolidated Financial Statements

 

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Hallador Energy Company

Consolidated Statements of Comprehensive IncomeCash Flows 

For the years ended December 31,

(in thousands, expect per share data)thousands)

 

		2017				2016				2015
Revenue:
Coal sales		$	268,202			$	278,924			$	339,490
Equity income (loss) - Savoy			460				(1,187	)			(1,532	)
Equity income (loss) - Sunrise Energy			(95	)			(249	)			(74	)
Other (Note 7)			3,066				3,962				2,236
Total revenue			271,633				281,450				340,120
Costs and expenses:
Operating costs and expenses			190,150				192,777				237,897
DD&A			38,495				35,565				43,942
ARO accretion			861				1,029				498
Coal exploration costs			854				1,673				2,039
SG&A			14,978				10,520				12,617
Interest (1)			12,413				14,842				15,557
Asset impairment (Note 2)			-				16,560				-
Total costs and expenses			257,751				272,966				312,550
Income before income taxes			13,882				8,484				27,570
Less income tax expense (benefit)
Current			(2,748	)			(167	)			(14	)
Deferred			(16,446	)			(3,859	)			7,452
Total income tax expense (benefit)			(19,194	)			(4,026	)			7,438
Net income *		$	33,076			$	12,510			$	20,132
Net income per share (Note 9):
Basic and diluted		$	1.08			$	0.42			$	0.68
Weighted average shares outstanding:
Basic and diluted			29,661				29,260				29,031

		2023				2022
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	44,793			$	18,105
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income taxes			4,629				1,756
Equity income (loss) – Sunrise Energy			552				(443	)
Cash distribution - Sunrise Energy			625				—
Depreciation, depletion and amortization			67,211				46,875
Loss on extinguishment of debt			1,491				—
Loss (gain) on sale of assets			398				(264	)
Payments on interest rate swap, net of changes in value			—				(867	)
Amortization of debt issuance costs			3,233				3,601
Asset retirement obligations accretion			1,804				1,010
Cash paid on asset retirement obligation reclamation			(3,384)				(3,162)
Stock-based compensation			3,554				1,269
Provision for loss on customer contracts			—				159
Amortization of contract asset and contract liabilities			(39,791	)			(19,731	)
Change in current assets and liabilities:
Accounts receivable			9,952				(16,305	)
Inventory			15,548				(25,863	)
Parts and supplies			(10,582	)			(6,271	)
Prepaid expenses			1,186				(5,941	)
Accounts payable and accrued liabilities			(18,992	)			24,037
Deferred revenue			(23,423	)			35,485
Other			610				719
Net cash provided by operating activities		$	59,414			$	54,169

 

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*There is no material difference between net income and comprehensive income.

(1)

Included in interest expense is the change in the estimated fair value of our interest rate swaps. Such amounts were $(723), $(637) and $159 for 2017, 2016 and 2015, respectively.

See accompanying notes.

45

Hallador Energy Company

Consolidated StatementStatements of Cash Flows

For the years ended December 31,

(in thousands)

		2017				2016				2015
Operating activities:
Net income		$	33,076			$	12,510			$	20,132
Deferred income taxes			(16,446	)			(3,859	)			7,452
Equity (income) loss – Savoy and Sunrise Energy			(365	)			1,436				1,606
Cash distributions - Savoy and Sunrise Energy			175				3,977				-
DD&A			38,495				35,565				43,942
Asset impairment			-				16,560				-
Loss on sale of assets			45				197				-
Change in fair value of interest rate swaps			(723	)			(637	)			159
Amortization and write off of deferred financing costs			1,829				2,325				1,394
Amortization of purchased coal contracts			8,922				1,593				-
Accretion of ARO			861				1,029				498
Stock-based compensation			7,266				2,539				3,134
Taxes paid on vesting of RSUs			(3,209	)			(1,098	)			(1,029	)
Change in current assets and liabilities:
Accounts receivable			5,533				(5,632	)			10,627
Coal inventory			(2,704	)			4,815				4,807
Parts and supply inventory			48				1,164				3,664
Prepaid income taxes			(3,226	)			5,312				448
Prepaid expenses			(4,823	)			(2,567	)			370
Accounts payable and accrued liabilities			(815	)			(11,193	)			(1,686	)
Other			(2,371	)			(3,118	)			(862	)
Cash provided by operating activities			61,568				60,918				94,656
Investing activities:
Capital expenditures			(28,622	)			(19,832	)			(31,167	)
Proceeds from sale of equipment			506				-				-
Purchase of Freelandville and Log Creek assets			-				(22,358	)			-
Proceeds from maturities of certificates of deposit			5,820				-				-
Purchase of certificates of deposit			-				(7,315	)			-
Other			-				189				641
Cash used in investing activities			(22,296	)			(49,316	)			(30,526	)
Financing activities:
Payments of bank debt			(36,625	)			(34,855	)			(56,875	)
Bank borrowings			-				24,000				-
Deferred financing costs			-				(2,090	)			-
Proceeds from Bulldog property			4,940				-				-
Dividends			(4,892	)			(4,799	)			(4,794	)
Cash used in financing activities			(36,577	)			(17,744	)			(61,669	)
Increase (decrease) in cash and cash equivalents			2,695				(6,142	)			2,461
Cash and cash equivalents, beginning of year			9,788				15,930				13,469
Cash and cash equivalents, end of year		$	12,483			$	9,788			$	15,930
Supplemental cash flow information:
Cash paid for interest		$	11,663			$	12,429			$	14,149
Cash (received) paid for income taxes, net			1,562				(5,594	)			(956	)
Capital expenditures included in accounts payable and prepaid expense			7,615				(1,616	)			804

See accompanying notes.(continued)

  

46

		2023				2022
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		$	(75,352	)		$	(54,020	)
Proceeds from sale of equipment			62				655
Net cash used in investing activities			(75,290	)			(53,365	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt			(59,713	)			(78,225	)
Borrowings of bank debt			66,000				51,700
Proceeds from sale and leaseback arrangement			11,082				—
Issuance of convertible notes payable			—				11,000
Issuance of related party convertible notes payable			—				18,000
Debt issuance costs			(6,013	)			(2,097	)
Distributions to redeemable noncontrolling interests			—				(585	)
ATM offering			7,318				—
Taxes paid on vesting of RSUs			(2,101	)			—
Net cash provided by (used in) financing activities			16,573				(207	)
Increase in cash, cash equivalents, and restricted cash			697				597
Cash, cash equivalents, and restricted cash, beginning of year			6,426				5,829
Cash, cash equivalents, and restricted cash, end of year		$	7,123			$	6,426
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents		$	2,842			$	3,009
Restricted cash			4,281				3,417
		$	7,123			$	6,426
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest		$	9,966			$	8,123
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and finance lease		$	1,882			$	3,440

  

The accompanying notes are an integral part of these Consolidated Financial Statements

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Hallador Energy Company

Consolidated Statement of Stockholders’ Equity

(in thousands)

 

		Shares				Common Stock				Additional Paid-in Capital				Retained Earnings				AOCI*				Total												Additional								Total
Balance January 1, 2015			28,962			$	289			$	90,218			$	99,003			$	365			$	189,875
																										Common Stock Issued								Paid-in				Retained				Stockholders'
																										Shares				Amount				Capital				Earnings				Equity
BALANCE, DECEMBER 31, 2021																											30,785			$	308			$	104,126			$	77,801				182,235
Stock-based compensation																											—				—				1,269				—				1,269
Cancellation of redeemable noncontrolling interests																											—				—				3,415				—				3,415
Stock issued on redemption of convertible note																											232				2				998				—				1,000
Stock issued on redemption of related party convertible notes																											1,966				20				8,980				—				9,000
Net income																											—				—				—				18,105				18,105
BALANCE, DECEMBER 31, 2022																											32,983				330				118,788				95,906				215,024
Stock-based compensation			14				-				3,134				-				-				3,134				—				—				3,554				—				3,554
Stock issued on vesting of RSUs			411				3				-				-				-				3				473				5				(5	)			—				—
Taxes paid on vesting of RSUs			(136	)			-				(1,029	)			-				-				(1,029	)			(198	)			(2	)			(2,099	)			—				(2,101	)
Dividends			-				-				-				(4,794	)			-				(4,794	)
Stock issued in ATM offering																											794				8				7,310				—				7,318
Net income			-				-				-				20,132				-				20,132				—				—				—				44,793				44,793
Other			-				-				(48	)			-				(453	)			(501	)
Balance, December 31, 2015			29,251				292				92,275				114,341				(88	)			206,820
Stock-based compensation			-				-				2,539				-				-				2,539
Stock issued on vesting of RSUs			272				2				-				-				-				2
Taxes paid on vesting of RSUs			(126	)			-				(1,098	)			-				-				(1,098	)
Dividends			-				-				-				(4,799	)			-				(4,799	)
Net income			-				-				-				12,510				-				12,510
Other			16				-				100				-				816				916
Balance December 31, 2016			29,413				294				93,816				122,052				728				216,890
Stock-based compensation			-				-				7,266				-				-				7,266
Stock issued on vesting of RSUs			991				5				-				-				-				5
Taxes paid on vesting of RSUs			(449	)			-				(3,209	)			-				-				(3,209	)
Dividends			-				-				-				(4,892	)			-				(4,892	)
Net income			-				-				-				33,076				-				33,076
Other			-				-				-				-				187				187
Balance, December 31, 2017			29,955			$	299			$	97,873			$	150,236			$	915			$	249,323
BALANCE, DECEMBER 31, 2023																											34,052				341				127,548				140,699				268,588

 

*Accumulated Other Comprehensive Income (loss)The accompanying notes are an integral part of these Consolidated Financial Statements

 

See accompanying notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2023 AND 2022

(1)

Summary of Significant Accounting Policies

(1)     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Basis of Presentation and Consolidation

 

The consolidated financial statements include the accounts of Hallador Energy Company (the Company)(hereinafter, “we”, “our” or “us”) and itsour wholly owned subsidiarysubsidiaries Sunrise Coal, LLC (Sunrise)(“Sunrise”), Hallador Power Company, LLC (“Hallador Power”) and Sunrise’sHourglass Sands, LLC (“Hourglass”), as well as Sunrise and Hallador Power's wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. We areSunrise is engaged in the production of steam coal from mines located in western Indiana.  We ownHallador Power is engaged in the production of coal-fired electric power generation located in Sullivan County, Indiana.

Segment Information

As the result of Hallador Power’s acquisition of the Merom Generating Station one gigawatt power plant in Sullivan County, Indiana (the “Merom Power Plant”) from Hoosier Energy Rural Electric Cooperative, Inc. (“Hoosier”) on October 21, 2022 (the “Merom Acquisition”), as further described in Note 15, beginning in the fourth quarter of 2022, we began to strategically view and manage our operations through two 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” and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC a private entity engaged in natural gas operations in the same vicinity as the Carlisle Mine. We also own 30.6% equity interest in Savoy Energy, L.P.(“Sunrise Energy”), a private oil and gas exploration company that haswith operations in Michigan. We have reached an agreement for Savoy to redeem our entire partnership interest for $8 million,Indiana, which we expectaccount for using the equity method, and our wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River. 

The Coal Operations reportable segment includes currently operating mining complexes Oaktown 1 and Oaktown 2 underground mines, Prosperity surface mine, Freelandville surface mine and Carlisle wash plant. On February 23, 2024, our Sunrise Coal Division undertook an initiative designed to finalizestrengthen our financial and operational efficiency and to create significant operational savings and higher margins in mid-March 2018. Our net after commissions paid will be $7.5 million.our coal segment. For further information, see “Note 19 - Subsequent Events” below.

The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant.

ReclassificationReclassifications

 

To maintain consistency and comparability, certain amountsAmounts in the prior years consolidated financial statements have beenare reclassified whenever necessary to conform to the current year’s presentation. Any reclassification adjustments had no impact on prior year presentation.total assets, liabilities, net income or shareholders’ equity.

 

InventoriesCash and Cash Equivalents

 

CoalCash and cash equivalents include investments with maturities when purchased of three months or less. Cash balances at individual banks may exceed the federally insured limit by the Federal Deposit Insurance Corporation. The Company has not experienced any material losses in such accounts.

Accounts Receivable

The timing of revenue recognition, billings and cash collections results in accounts receivable from customers. Customers are invoiced as coal is shipped or as power is delivered or at periodic intervals in accordance with contractual terms. Invoices typically include customary adjustments for the resolution of price variability, such as coal quality thresholds. Payments are generally received within thirty days of invoicing.  Historically, credit losses have been insignificant. No charges for credit losses were recognized during the years ended December 31,2023 or 2022.

Inventory and Parts and Supplies

Inventory and parts and supplies inventories are valued at the lower of average cost or market. Coal inventorynet realizable value determined using the first-in first-out method. Inventory costs include labor, supplies, operating overhead, and other related costs incurred at or on behalf of the mining location or plant, including depreciation, depletion, and amortization of equipment, costs (including depreciation thereto)buildings, mineral rights, and overhead.mine development costs.

 

AdvanceContract Asset - Coal Purchase Agreement

Contract Asset - Coal Purchase Agreement (as defined in Note 15) is the result of a coal purchase agreement with Hoosier whereby we purchased coal from Hoosier through May 31, 2023, at fixed prices which were below market prices at the date of entry into the agreement. This agreement was entered into as consideration in the Merom Acquisition. The asset was amortized to inventory as coal was purchased over the term of the agreement as the contract was fulfilled. During the years ended December 31, 2023 and 2022, $19.6 million and $14.7 million, respectively, were amortized, of which $30.7 million and $3.6 million, respectively, was recognized in operating expenses on the consolidated statements of operations. The Coal Purchase Agreement term was from October 21, 2022 to May 31, 2023.

Prepaid Expenses

Prepaid expenses include prepaid insurance and other prepaid balances with vendors for various services paid for in advance of use.

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Advanced Royalties

 

Coal leases that require minimum annual or advance payments and are recoverable from future production are generally deferred and charged to expense as the coal is subsequently produced. Advance royalties are included in other assets.

 

CoalMining Properties and Plant Equipment

 

CoalMining properties are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase the productivity of the assets are expensed as incurred. Other than land and most mining equipment, coalmining properties are depreciated using the units-of-production method over the estimated recoverable reserves. Most surface and underground mining equipment is depreciated using estimated useful lives ranging from three to twenty-five years. At

The values of the beginningproperty, plant and equipment acquired as part of 2016, we changedthe Merom Acquisition were recorded at relative fair value based on the consideration paid upon closing of the acquisition of the plant in October 2022. Other equipment is recorded at cost. Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase the productivity of the assets are expensed as incurred. Most power plant equipment is depreciated using estimated useful lives ranging from the straight-line methodfour to the units-of-production method in computing the depreciation for continuous miners. This change in estimate reduced our DD&A expense for the year ended December 31, 2016, by $2.6 million. Due to idle equipment at Carlisle, we stopped depreciating specific underground equipment resulting in a $4.4 million reduction in depreciation for the year ending December 31, 2016.nine years.

 

If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates that the carrying value of the asset will not be recoverable through estimated undiscounted future net cash flows related to the asset over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset to its estimated fair value. See Note 2 for further discussion of impairments.There were no long-lived asset impairments during the years ended December 31, 2023 or December 31, 2022.

 

Mine Development

 

Costs of developing new coal mines, including asset retirement obligation assets, or significantly expanding the capacity of existing mines, are capitalized and amortized using the units-of-production method over estimated recoverable reserves.

 

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Deferred Revenue

 

Deferred revenue includes advance payments on electric capacity payments and prepayments on coal deliveries. The deferred revenue for each will be reversed to revenue on a monthly pro-rata basis for the capacity payments and as coal is delivered for the coal prepayments based upon the underlying contractual terms.  All deferred revenue is expected to be recognized in revenue within one year.

Asset Retirement Obligations (ARO) -– Reclamation

 

At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to mine development. Obligations are typically incurred when we commence development of underground and surface mines and include reclamation of support facilities, refuse areas and slurry ponds.

 

Obligations are reflected at the present value of their future cash flows. 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 (proved(proven and probable) reserves. We are usinguse credit-adjusted risk-free discount rates ranging from 5.0%7% to 10%. to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Federal and state laws require that mines be reclaimed in accordance with specific standards and approved reclamation plans, as outlined in mining permits. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.

 

We review our ARO at least annually and reflect revisions for permit changes, changes in our estimated reclamation costs and changes in the estimated timing of such costs. The change in estimate for the year ended December 31, 2023, was a result of a change in timing and acreage of expected reclamation of the Merom Power Plant. In the event we are not able to perform reclamation, we have surety bonds at December 31, 2023 totaling $25$37.5 million to cover ARO. The undiscounted asset retirement obligation was $26.6 million and $27.0 million at December 31, 2023 and 2022, respectively.

 

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The table below (in thousands) reflects the changes to our ARO:ARO for the periods presented: 

 

										Year Ended December 31,
		2017				2016				2023				2022
Balance, beginning of year		$	13,260			$	12,231			$	20,834			$	14,125
Merom acquisition											—				7,230
Freelandville addition											—				1,631
Accretion			861				1,029				1,804				1,010
Revisions			(112	)			-
Change in estimate											(2,566	)			—
Payments			(203	)			-				(3,384	)			(3,162	)
Balance, end of year			13,806				13,260				16,688				20,834
Less current portion			(300	)			(145	)			(2,150	)			(3,580	)
Long-term balance, end of year		$	13,506			$	13,115			$	14,538			$	17,254

  

Statement of Cash FlowsContract Liabilities - Power Purchase Agreement and Capacity Payment Reduction

 

Cash equivalents include investmentsContract Liabilities - Power Purchase Agreement and Capacity Payment Reduction (both as defined in Note 15) are the result of a power purchase agreement with maturities, when purchased,Hoosier whereby Hallador Power is selling power to Hoosier through 2025 at fixed prices which were below market prices at the date the parties entered into the agreement. Hallador Power also agreed to a reduction in future capacity payments as part of three months or less.the acquisition consideration. These agreements were entered into as consideration in the Merom Acquisition. The power purchase agreement liability is amortized to electric sales revenue pro-rata over the term of the agreement as the contract is fulfilled. During the years ended December 31, 2023 and 2022, amortization of the power purchase agreement contract liability totaled $70.5 million and $23.3 million, respectively. The Power Purchase Agreement term is from October 21, 2022 to December 31, 2025. The Capacity Payment Reductions occurred on May 31, 2023 and November 30, 2023 in the amount of $7.5 million each.

 

Interest Rate Swaps

We have historically utilized derivative instruments to manage exposures to interest rate risk on long-term debt. We enter interest rate swaps in order to achieve a mix of fixed and variable rate debt that it deems appropriate. These interest rate swaps have not been designated as hedging instruments and were accounted for as an asset or a liability in the accompanying consolidated balance sheets at their fair value. Realized and unrealized gains and losses are classified as operating activities in the accompanying consolidated statements of cash flows. As of December 31, 2023 and 2022, we were not a party to any interest rate swaps.

Commitments and Contingencies

From time to time, we are involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. We have concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on our business, financial position, results of operations or liquidity.

Income Taxes

 

Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on pretax financial income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting and principally relate to differences in the tax basis of assets and liabilities and their reported amounts, using enacted tax rates in effect for the year in which differences are expected to reverse.

 

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Net Income per Share

 

Basic net incomeearnings per share is(“EPS”) are computed on the basis ofby dividing net earnings by the weighted average number of shares of common stock outstanding during the period using the two-class method for our common shares and RSUs which share inoutstanding for the Company’s earnings. period.

Diluted net income per shareEPS attributable to common shareholders is computed on the basis ofby adjusting net earnings by the weighted average number of common shares of common stock plus the effect of dilutiveand potential common shares outstanding (if dilutive) during theeach period. Dilutive potentialPotential common shares include shares of restricted stock units as if the units issued by us were vested and convertible debt. We apply the treasury stock method to account for the dilutive impact of its restricted stock units and the if converted method for its convertible notes. Anti-dilutive securities are includedexcluded from diluted EPS. As a result of determining the effect of potentially dilutive securities, in certain periods, diluted net loss per share is the same as the basic net incomeloss per share usingfor the two-class method.periods presented.

 

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Use of Estimates in the Preparation of Financial Statements

 

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual amounts could differ from those estimates. The most significant estimates included in the preparation of the financial statements relate to: (i) fair value estimates relating to business combinations, (ii) deferred income tax accounts, (iii)(ii) coal reserves, (iv)(iii) depreciation, depletion, and amortization, and(iv) estimates related to the Merom Acquisition, (v) estimates used in our impairment analysis.analysis, and (vi) estimates used in the calculation of ARO.

 

Business Combinations

We account for business combinations using the purchase method of accounting. The purchase method requires us to determine the fair value of all acquired assets, including identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires management's judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.

Revenue Recognition

We recognize revenue from coal sales at the time title and risk of loss passes to the customer at contracted amounts and amounts are deemed collectible. Some coal supply agreements provide for price adjustments based on variations in quality characteristics of the coal shipped and are recorded in the period of shipment. As discussed below, we do not expect the new revenue recognition standard introduced by ASU 2014-09, Revenue from Contracts with Customers (ASU 2014-09) will result in a material change to our pattern of revenue recognition when it becomes effective.

Long-term Contracts

 

As of December 31, 2017,2023, we are committed to supplying ourthird-party customers up to a maximum of 26.19.2 million tons of coal through 20242027, of which 13.56.2 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.

 

For 2017,2023, we derived 92%93% of ourthird-party coal sales from five customers, each representing at least 10% of coal sales. At December 31, 2023, 85% of our coal sales. 83% of ouroperations accounts receivable werewas from four of these customers, each representing more than 10% of. For the year ended December 31, 2017 balance.2023,100% of our electric sales and accounts receivable were with two customers.

 

For 2016,2022, we derived 90% of our coal sales from five customers, each representing at least 10% of our coal sales. 78%At December 31, 2022, 86% of our coal operations accounts receivable werewas from four of these customers, each representing more than 10% of. For the year ended December 31, 2016 balance.2022, 100% of our electric sales and accounts receivable was with one customer.

 

For 2015,2023, 100% of our delivered energy generation revenue was sold to Hoosier or the Midcontinent Independent System Operator ("MISO") wholesale market. MISO is the independent system operator managing the flow of high-voltage electricity across 15 U.S. states and the Canadian province of Manitoba. For 2023, we derived 82%91% of our coalcapacity sales revenue from fourthree customers, each representing at least 10% of capacity sales revenue. As of December 31, 2023, we are committed to supply approximately 22% of the plant’s energy generation output and approximately 32% of the plant’s capacity to Hoosier from June 1, 2023, through May 31, 2028.  Additionally, as of December 31, 2023, we are committed to supply to other customers approximately 47% to 55% of the plant’s capacity during the years ending December 31, 2024, through 2026 and approximately 28% of the plant’s capacity during the years ending December 31, 2027, through 2028. For 2022, we derived 100% of our coal sales.electric delivered energy generation and capacity sales revenue from Hoosier.

 

We are paid every two to four weeks and do not expect any credit losses.

Stock-based Compensation

 

Stock-based compensation for restricted stock units is measured at the grant date based on the fair value of the award and is recognized as expense over the applicable vesting period of the stock award (generally two to four years) using the straight-line method.

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NewRecent Accounting Standards Issued andPronouncements Not Yet Adopted

 

In July 2015, November 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures ("ASU 2023-07"). ASU 2023-07 primarily requires enhanced disclosures about significant segment expenses regularly provided to the chief operating decision maker ("CODM"), the amount and composition of other segment items, and the title and position of the CODM. ASU 2023-07 is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU 2023-07, but do not expect it to have a material effect on our consolidated financial statements.  

In December 2023, the FASB issued ASU 2015-11, Inventory2023-09, Income Taxes (Topic 330)740): Simplifying the Measurement of Inventory (ASU 2015-11)Improvements to Income Tax Disclosures ("ASU 2023-09"). ASU 2015-11 simplifies2023-09 primarily requires enhanced disclosures to (1) disclose specific categories in the subsequent measurementrate reconciliation, (2) disclose the amount of inventory.  It replacesincome taxes paid and expensed disaggregated by federal, state, and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the current lowerimpact of cost or market test with theadopting ASU 2023-09, but do not expect it to have a material effect on our consolidated financial statements.

(2)     INVENTORY

Inventory is valued at lower of cost or net realizable value test.  Net realizable value is defined as the estimated selling prices in the ordinary course(“NRV”). As of business, less reasonably predictable costsDecember 31, 2023, and 2022, coal inventory includes NRV adjustments of completion, disposal,$2.0 million and transportation.  The new standard was applied prospectively and effective for annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods.  The adoption of ASU 2015-11 did not have a material impact on our consolidated financial statements.$4.9 million, respectively.

 

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New Accounting Standards Issued and Not Yet Adopted(3)     OTHER LONG-TERM ASSETS (IN THOUSANDS)

		December 31,
		2023				2022
Advanced coal royalties		$	5,521			$	5,967
Other			1,540				1,618
Total other assets		$	7,061			$	7,585

(4)     BANK DEBT

 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (ASU 2016-02).  ASU 2016-02 increases transparency and comparability among organizations by requiring lessees to record right-to-use assets and corresponding lease liabilities on the balance sheet and disclosing key information about lease arrangements.  The new guidance will classify leases as either finance or operating (similar to current standard’s “capital” or “operating” classification), with classification affecting the pattern of income recognition in the statement of income.  ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.  We are currently in the process of accumulating all contractual lease arrangements in order to determine the impact on our financial statements and do not believe we have significant amounts of off- balance sheet leases; accordingly, we do not expect the adoption of ASU 2016-02 to have a material impact on our consolidated financial statements. We continue to monitor closely the activities of the FASB and various non-authoritative groups with respect to implementation issues that could affect our evaluation.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 is a comprehensive revenue recognition standard that will supersede nearly all existing revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach for determining revenue recognition. ASU 2014-09 will require that companies recognize revenue based on the value of transferred goods or services as they occur in the contract. The ASU also will require additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 is effective for interim and annual periods beginning after December 15, 2017. We have adopted the new standard as of January 1, 2018. Entities will be able to transition to the standard either retrospectively or as a cumulative-effect adjustment as of the date of adoption.

Our primary source of revenue is from the sale of coal through both short-term and long-term contracts with utility companies whereby revenue is currently recognized when risk of loss has passed to the customer. Under the new standard, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. As part of our assessment process, we applied the five-step analysis outlined in the new standard to certain contracts representative of the majority of our coal sales contracts and determined that our pattern of recognition is consistent between the new and existing standards. We also reviewed the expanded disclosure requirements under the new standard and have determined the additional information to be disclosed. In addition, we reviewed our business processes, systems and internal controls over financial reporting to support the new recognition and disclosure requirements under the new standard. Upon adoption of this new standard, we believe that the timing of revenue recognition related to our coal sales will remain consistent with our current practice, but expanded disclosures including presenting revenue for all periods presented and expected revenue by year for performance obligations that are unsatisfied or partially unsatisfied as of the date of presentation will be required. We have elected the modified retrospective transition method which allows a cumulative effect adjustment to equity as of the date of adoption. Because we do not anticipate a change in our pattern of revenue recognition, we anticipate that the transition will not have a material impact on our consolidated financial statements. Although we don’t consider it material, one source of variable consideration we receive relates to reimbursement from certain customers for expenses incurred for new government impositions adopted, which we may recognize sooner than our current recognition practice.

In November 2016, the FASB issued guidance regarding the presentation of restricted cash in the statement of cash flows (ASU 2016-18). This update is effective for annual reporting periods beginning after December 15, 2017, and early adoption is permitted. We have adopted the new standard as of January 1, 2018.

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In January 2017, the FASB issued new guidance to assist in determining if a set of assets and activities being acquired or sold is a business (ASU 2017-01). It also provided a framework to assist entities in evaluating whether both an input and a substantive process are present, which at a minimum, must be present to be considered a business. This update is effective for annual reporting periods beginning after December 15, 2017, and early adoption is permitted in most circumstances. The standard does not have an impact to the Company’s historical recognition of asset acquisitions and business combinations. However, we expect there will be an impact to how the Company accounts for assets acquired in the future.

Subsequent Events

In January 2018, we declared a dividend of $.04 per share to shareholders of record as of January 31, 2018. The dividend was paid on February 16, 2018.

In February 2018, we formed and made an initial investment of $4 million in Hourglass Sands, LLC, a frac sand mining company in the State of Colorado.  We own 100% of the Class A units and will account for Hourglass Sands LLC as a wholly owned subsidiary of Hallador Energy Company.  Class A units are entitled to 100% of profit until our capital investment and interest is returned, then 90% of profits are allocated to Class A Units with the remainder to Class B units.  A Yorktown company associated with one of our directors also invested $4 million for a royalty interest in the sand project.

We currently control a permitted sand reserve near Colorado Springs.  We are negotiating to have a third party wash our sand and expect to truck test shipments to customers in the DJ Basin this summer.  We believe we control the only permitted frac sand mine in the State of Colorado.  We do not anticipate Hourglass Sands, LLC to be profitable in 2018, but are excited about its growth potential in future years.

We have reached an agreement for Savoy Energy L.P. to redeem our entire partnership interest for $8 million, which we expect to finalize in mid-March 2018. Our net after commissions paid will be $7.5 million.

(2)

Asset Impairment Review

Carlisle Mine

In December 2016, the deterioration of the North End of the Carlisle Mine (the North End), coupled with lower coal prices led us to determine that the North End could no longer be mined safely and profitably. The sealing of the North End was completed in On March 2017. In connection therewith, we identified specific assets totaling $16.6 million ($15.1 million of property and equipment and $1.5 million of advanced royalties) that were written off in 2016.

With the Carlisle Mine remaining in hot idle status, we conducted a review of the Carlisle Mine assets as of December 31, 2017, based on estimated future net cash flows, and determined that no further impairment was necessary.

The Carlisle Mine assets had an aggregate net carrying value of $110 million at December 31, 2017.  If in future periods we reduce our estimate of the future net cash flows attributable to the Carlisle Mine, it may result in future impairment of such assets and such charges could be significant.

Bulldog Reserves

In October 2017, we entered into an agreement to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase the property for 8 years. Because of the likelihood of exercising the repurchase option, we are accounting for the sale as a financing transaction. The Bulldog Mine assets had an aggregate net carrying value of $15 million at December 31, 2017. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. The permit will be issued upon submittal of a fee and bond which are required within 12 months of the notification. We have determined that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.

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(3)

Bank Debt

On March 18, 2016, 25, 2022, we executed an amendment to our credit agreement with PNC Bank, National Association (in its capacity as administrative agent, “PNC”), administrative agent for ourits lenders for theunder its credit agreement. The primary purpose of increasing liquiditythe amendment was to return the allowable leverage ratio and maintaining compliancedebt service coverage ratio to December 31, 2021 levels throughSeptember 30, 2022, with the debt service coverage waived for March 31, 2022.

On May 20, 2022, we executed an additional amendment to our credit agreement with PNC. The primary purpose of this amendment was to modify the allowable leverage ratio and debt service coverage ratio through June 30, 2022, to provide relief for current and anticipated covenant violations.

On August 5, 2022, we executed an additional amendment to our credit agreement with PNC. The primary purpose of this amendment was to modify the allowable leverage ratio and debt service coverage ratio through September 30,2022, to provide relief for anticipated covenant violations.

On March 13, 2023, we executed an additional amendment to our credit agreement with PNC. The primary purpose of the amendment was to convert $35 million of the outstanding balance on the revolver into a new term loan with a maturity date of March 31, 2024, and extend the maturity date of the revolver to May 31, 2024. The amendment also reduced the total capacity under the revolver to $85 million and waived the maximum annual capital expenditure covenant for 2022 and increased the covenant for 2023 to $75 million. Subsequent to December 31, 2022, and prior to the effective date of this amendment, we had borrowed an additional $17 million under the revolver. Additionally, this amendment provided for the transition in interest rates from the London Interbank Offered Rate (“LIBOR”) to the Secured Overnight Financing Rate (“SOFR”) based pricing with ranges from SOFR plus 4.00% to SOFR plus 5.00%, depending on our leverage ratio.

On August 2, 2023, we executed an additional amendment to our credit agreement with PNC, which was accounted for as a debt extinguishment. The primary purpose of the amendment was to convert $65 million of the outstanding funded debt into a new term loan with a maturity of March 31, 2026, and enter into a revolver of $75 million with a maturity of July 31, 2026. The amendment increased the maximum annual capital expenditure limit to $100 million.

Prior to the March 13, 2023 amendment, bank debt was comprised of term debt ($5.5 million as of December 31, 2022) and a $120 million revolver ($79.7 million borrowed as of December 31, 2022). The term debt amortization was to conclude with the final payment of $5.5 million in August 2019.  March 2023. The revolver was reduced from $250to mature in September 2023. Under the provision of the March 13, 2023 amendment, bank debt was comprised of term debt ($35.0 million to $200as of March 13, 2023) and an $85 million revolver ($40.2 million borrowed as of March 13, 2023). The term debt required payment of $10 million in June 2023 each quarter thereafter in 2023 and $5.0 million by March 31, 2024. Under the August 2, 2023 amendment, bank debt was comprised of term debt ($58.5 million borrowed as of December 31, 2023) and a $75 million revolver ($33.0 million borrowed as of December 31, 2023. The term debt requires payments of $6.5 million beginning April 2024 through March 2026.

Bank debt increased by $6.3 million and was reduced by $26.5 million during the $175 million term loan remained the same. years ended December 31, 2023 and 2022, respectively.

Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is collateralized primarily by our assets.

Liquidity

As of December 31, 2017, was $202 million (term-$71 million, revolver-$131 million). As of December 31, 2017, 2023, we had additional borrowing capacity of $69$23.4 million under the revolver and total liquidity of $85$26.2 million. Our additional borrowing capacity is net of $18.6 million in outstanding letters of credit as of December 31, 2023 that were required to maintain surety bonds. Liquidity consists of additional borrowing capacity and cash and cash equivalents.

 

BankFees

Unamortized bank fees and other costs incurred in connection with the initial facility and subsequent amendments totaled $2.5 million as of December 31, 2022. Additional costs incurred with the March 13,2023 and August 2, 2023 amendments totaled $1.6 million and $4.3 million, respectively. During 2023 we recognized a loss on extinguishment of debt of $1.5 million for the write-off of unamortized loan fees related to the August 2, 2023 amendment were $9.1 million,to our credit agreement, which was accounted for as a debt extinguishment. The remaining costs were deferred and are being amortized over five years. The credit facilitythe term of the loan. Unamortized costs as of December 31, 2023, and December 31, 2022 were $3.6 million and $2.5 million, respectively. 

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Bank debt, less debt issuance costs, is collateralized by substantially all of Sunrise’s assets, and we are the guarantor.presented below (in thousands):

		December 31,
		2023				2022
Current bank debt		$	26,000			$	35,500
Less unamortized debt issuance cost			(1,562	)			(2,469	)
Net current portion		$	24,438			$	33,031
Long-term bank debt		$	65,500			$	49,713
Less unamortized debt issuance cost			(2,047	)			—
Net long-term portion		$	63,453			$	49,713
Total bank debt		$	91,500			$	85,213
Less total unamortized debt issuance cost			(3,609	)			(2,469	)
Net bank debt		$	87,891			$	82,744

Covenants

 

The amended credit facility increased theincludes a Maximum Leverage Ratio (Sunrise total(consolidated funded debt/debt / trailing 12twelve months adjusted EBITDA), calculated as of the end of each fiscal quarter for the trailing twelve months, not to those listed below:exceed 2.25 to 1.00.

 

Fiscal Periods Ending		Ratio
December 31, 2017 and March 31, 2018			4.25	X
June 30, 2018 and September 30, 2018			4.00	X
December 31, 2018			3.75	X
March 31, 2019 and June 30, 2019			3.50	X

As of December 31, 2023, our Leverage Ratio of 1.32 was in compliance with the requirements of the credit agreement.

 

The amendedBeginning December 31, 2022, the credit facility also requires a Minimum Debt Service Coverage Ratio minimum(consolidated adjusted EBITDA/annual debt service) calculated as of 1.25Xthe end of each fiscal quarter for the trailing 12 months of 1.25 to 1.00 through the maturity of the credit facility. The amendment defines the Debt Service Coverage Ratio as trailing 12 months adjusted EBITDA/annual debt service.

 

At As of December 31, 2017, our Leverage Ratio was 2.40 and2023, our Debt Service Coverage Ratio of 3.30 was 1.90. Therefore, we were in compliance with these two debt covenant ratios.the requirements of the credit agreement.

 

Interest Rate

The interest rate on the facility ranges from LIBORSOFR plus 2.25%4.00% to LIBORSOFR plus 4%5.00%, depending on our leverage ratio. Leverage Ratio. As of  December 31, 2023, we were paying SOFR plus  4.25% on the outstanding bank debt.

Future Maturities (in thousands):
2024			26,000
2025			26,000
2026			39,500
Total		$	91,500

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(5)     ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (IN THOUSANDS)

		December 31,
		2023				2022
Accounts payable		$	43,636			$	62,306
Accrued property taxes			2,987				1,917
Accrued payroll			6,575				5,933
Workers' compensation reserve			3,629				3,440
Group health insurance			2,300				2,250
Asset retirement obligation - current portion			2,150				3,580
Other			1,631				3,546
Total accounts payable and accrued liabilities		$	62,908			$	82,972

(6)   REVENUE

Revenue from Contracts with Customers

We entered into swap agreementsaccount for a contract with a customer when the parties have approved the contract and are committed to fixperforming their respective obligations, the LIBOR componentrights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all of the interest rateconsideration will be collected. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to achieve an effective fixed ratea customer.

Coal operations

Our coal revenue is derived from sales to customers of ~5%coal produced at its facilities. Our customers typically purchase coal directly from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the original term loan balanceprevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.

Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on $100quality standards that are specified in the coal sales agreement, such as British thermal unit (“Btu”) factor, moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.

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Electric operations

We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), is met at the time a PPA is executed by the parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not determined to be a lease or derivative constitutes a valid contract under ASC 606.

We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract capacity performance obligations and daily, based on an output method of MWh of electricity delivered.

For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier.  For the delivered energy to all other customers, we recognize revenue daily for the actual delivered electricity.

Disaggregation of Revenue

Revenue is disaggregated by primary geographic markets for our coal operations and by revenue source for our electric operations, as we believe this best depicts how the nature, amount, timing, and uncertainty of its revenue and cash flows are affected by economic factors.

Coal operations

For the years ended December 31, 2023 and 2022, 33% and 74%, respectively, of our coal revenue was sold to customers in the State of Indiana with the remainder sold to customers in Florida, North Carolina, Georgia, and Alabama.

Electric operations

For the year ended December 31, 2023, electric sales revenue from delivered energy generation and capacity sales revenue was $211.8 million and $56.1 million, respectively. For the year ended December 31, 2022, electric sales revenue from delivered energy generation and capacity sales revenue was $53.9 million and $12.3 million, respectively.

Performance Obligations

Coal operations

A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.

We recognize revenue at a point in time as the customer does not have control over the asset at any point during the fulfillment of the contract. For substantially all of our customers, this is supported by the fact that title and risk of loss transfer to the customer upon loading of the truck or railcar at the mine. This is also the point at which physical possession of the coal transfers to the customer, as well as the right to receive substantially all benefits and the risk of loss in ownership of the coal.  

We have remaining coal sales performance obligations relating to fixed priced contracts to third-party customers of approximately $324 million, which represent the average fixed prices on our committed contracts as of December 31, 2023. We expect to recognize approximately 55% of this coal sales revenue in 2024, with the remainder recognized through 2027.

We have remaining performance obligations relating to coal sales contracts with price reopeners of approximately $155 million, which represents our estimate of the expected re-opener price on committed contracts as of December 31, 2023. We expect to recognize all of this coal sales revenue beginning in 2024 through 2027.

The coal tons used to determine the remaining performance obligations are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.

Electric operations

We concluded that each megawatt hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the customer.

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In accordance with the APA, as defined in Note 15. Merom Acquisition, with Hoosier, Hallador Power shall sell, and Hoosier shall buy, at least 70% of the delivered energy quantities through 2025 at the contract price, which is $34.00 per MWh. We have remaining delivered energy obligations to Hoosier totaling $115.6 million through 2025 as of December 31, 2023. The agreement was amended August 31, 2023 to extend through 2028 with additional obligations to Hoosier of $186.6 million as of December 31, 2023.

In addition to delivered energy, under the APA, Hallador Power shall provide a stand-ready obligation to provide electricity, also known as contract capacity. The contract capacity that Hallador Power shall provide to Hoosier is 917 megawatts (“MW”) for contract year one, and 300 MW for contract years two to four. Hoosier shall pay Hallador Power the capacity price of $5.80 per kilowatt month for the contract capacity. We have remaining capacity obligations to Hoosier through 2025 totaling $41.6 million as of December 31, 2023.  The agreement was amended August 31, 2023 to extend through 2028 with additional capacity obligation to Hoosier of $60.9 million as of December 31, 2023. 

We also have capacity obligations outside of the APA to customers through 2028 totaling $144.6 million as of December 31, 2023. The Company has $23.1 million of the revolver. The revolver swap notional value steps down 10% each quarter which commenced on March 31, 2016. At deferred revenue as of December 31, 2017,2023, related to these two interest rate swaps hadobligations.

Contract Balances

Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an estimated net fair valueentity’s right to consideration that is unconditional.

Under the typical payment terms of $.5 millionour contracts with customers, the customer pays us a base price for the coal, increased or decreased for any quality adjustments, electricity, or capacity. Amounts billed and due are recorded as trade accounts receivable and included in other assets onaccounts receivable in our consolidated balance sheet. Notional valuessheets. As of the two interest rate swaps were $96 million and $30 million as of December 31, 2017.

At December 31, 2017, we were paying LIBOR at 1.57% plus 3%2023, accounts receivable for a total interest rate of 4.57%.

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New accounting standards adopted in 2016 required that our debt issuance costs be presented as a direct reduction from the related debt rather than as an asset.  Our debt at December 31 is presented below (in thousands):

		2017				2016
Current debt		$	35,000			$	30,625
Less debt issuance cost			(1,829	)			(1,829	)
Net current portion		$	33,171			$	28,796
Long-term debt		$	166,992			$	207,992
Less debt issuance cost			(1,219	)			(3,048	)
Net long-term portion		$	165,773			$	204,944

Future Maturities (in thousands):
2018		$	35,000
2019			166,992
Total		$	201,992

(4)

Income Taxes (in thousands)

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referredcoal sales billed to as the Tax Cuts and Jobs Act (Tax Act). The Tax Act makes broad and complex changes to the U.S. tax code including, but not limited to, (1) bonus depreciation that will allow for full expensing of qualified property; (2) reduction of the U.S. federal corporate tax rate; (3) elimination of the corporate alternative minimum tax; (4) a new limitation on deductible interest expense; (5) the repeal of the domestic production activity deduction; (6) limitations on the deductibility of certain executive compensation; and (7) limitations on net operating losses generated after December 31, 2017, to 80 percent of taxable income.

The SEC staff issued SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. To the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the tax laws that were in effect immediately before the enactment of the Tax Act. As we are not subject to either the international changes of the Tax Act or other applicable provisions, we believe that the income tax effects of the Tax Act applicable to our accounting under ASC 740 is substantially complete for the year ended December 31, 2017. Additional information that may affect the accounting under ASC 740 would include further clarification and guidance on how the Internal Revenue Service and state taxing authorities will implement the Tax Act.customers was $14.3 million. We do not believe potential adjustments currently have any other contracts in future periodsplace where it would materially impacttransfer coal, electricity or capacity in advance of knowing the Company’s financial condition or resultsfinal price, and thus do not have any other contract assets recorded. Contract liabilities also arise when consideration is received in advance of operations.

The Tax Act reduces the corporate tax rate to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 requires the effect of a change in tax laws or rates to be recognized as of the date of enactment, we are required to adjust deferred tax assets and liabilities as of December 22, 2017. Accordingly, we have recorded a decrease related to our net deferred tax liability of $16.4 million, with a corresponding net adjustment to deferred income tax benefit of $16.4 million for the year ended December 31, 2017.performance.

 

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(7)     INCOME TAXES

 

Our income tax is different than the expected amount computed using the applicable federal and state statutory income tax rates.rate of 21%. The reasons for and effects of such differences for the years ended December 31 are below:below (in thousands):

  

		2017				2016				2015				2023				2022
Expected amount		$	4,868			$	2,966			$	9,653			$	10,344			$	4,171
Adjustment to deferred taxes from the Tax Act rate reduction			(17,974	)
Change in Indiana rate											(85	)
State income taxes, net of federal benefit			115				(387	)			612				1,246				391
Percentage depletion			(4,128	)			(6,021	)			(2,606	)			(3,348	)			(2,081	)
Change in valuation allowance															(3,681	)			(970	)
Stock-based compensation			(204	)			(238	)							(844	)			—
Captive insurance			(379	)			(418	)			(419	)
Adjustments to NOL carryforwards			(1,038	)
Return to provision adjustments			(205	)											159				153
Other			(249	)			72				283				589				92
		$	(19,194	)		$	(4,026	)		$	7,438
Total income tax expense														$	4,465			$	1,756

  

The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following at December 31: 31 (in thousands):

 

		2017				2016
Long-term deferred tax assets:
Stock-based compensation		$	251			$	512
Investment in Savoy			781				1,031
Net operating loss			13,626				14,908
Alternative minimum tax credit			2,705				4,221
Other			943				564
Total long-term deferred tax assets			18,306				21,236
Long-term deferred tax liabilities:
Coal properties			(47,034	)			(50,439	)
Oil and gas properties			-				(15,971	)
Total long-term deferred tax liabilities			(47,034	)			(66,410	)
Net deferred tax liability		$	(28,728	)		$	(45,174	)

 

		2023				2022
Deferred tax assets:
Net operating loss		$	20,029			$	26,570
Power contracts			23,302				34,233
Compensation			2,287				1,344
Accrued liabilities			570				556
Other			2,016				471
Total deferred tax assets			48,204				63,174
Valuation allowance			—				(3,681	)
Deferred tax assets, net of valuation allowance			48,204				59,493
Deferred tax liabilities:
Coal properties			(25,764	)			(27,700	)
Power properties			(31,126	)			(35,702	)
Investment partnerships			(549	)			(494	)
Other			—				(203	)
Total deferred tax liabilities			(57,439	)			(64,099	)
Net deferred tax liability		$	(9,235	)		$	(4,606	)

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Our effective tax rate (ETR)(“ETR”) for 20172023 and 2022 was (138)% compared to (48)% for 2016 and 27% for 2015.approximately 9%. The negative ETR in 2017 is due primarily to the effects of the Tax Act adjustment to our deferred taxes and prior year tax return reconciliation which were all recorded discretelyrate for the yearyears ended December 31, 2017. The negative2023 and 2022 are not predictive of future tax rates. Our ETR in 2016 isdiffers from the statutory rate due to the combination of the reduction in book income before taxes because of the asset impairment expense, permanent tax benefits of statutory depletion in excess of tax basis, return to provision adjustments, stock-based compensation and changes in the mining properties, the captive insurance company effects, and stock based compensation expense. The tax rate for the years ended December 31, 2017 and 2016 are not predictive of future tax rates due to the deferred income tax benefit of the Tax Act. The tax rate would have been 9% without the effects of the deferred income tax benefit of the Tax Act and the prior year tax return reconciliation. Historically, our actual effective tax rates have been lower than the statutory effective rate primarily due to the benefit received from statutory depletion allowances.valuation allowance. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income taxes.

We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations. Due to historical cumulative earnings over the prior three years as well as projected earnings into the future, we believe that it is more likely than not that the benefit from certain federal and state deferred tax assets will be realized. As such, we released the valuation allowance as of December 31, 2023. 

The federal NOLs generated in pre-2018 years and remaining of $13.4 million can offset 100% of future years' taxable income. The federal NOLs generated in post 2017 years of $60.7 million can offset 80% of future years' taxable income. The pre-2018 federal NOLs will expire in varying amounts from 2035 to 2037 if they are not utilized. Indiana NOLs have a 20-year carryforward period and will expire in the years 2034 to 2041 if they are not utilized. 

 

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions, to determine whether the positions will be more likely than not be sustained by the applicable tax authority. Tax positions not deemed to meet the more-likely-than-notmore-likely-than-not threshold are not recorded as a tax benefit or expense in the current year. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deduction will be sustained on audit and do not anticipate any adjustments that will result in a material change to ourits consolidated financial position. While not material, we record any penalties and interest as SG&A.general and administrative expense. Tax returns filed with the IRS for the years 2014 through 2016 along with tax returns filed with numerousInternal Revenue Service and state entities generally remain subject to examination.

examination for three years after filing.

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(8)     STOCK COMPENSATION PLANS

(5)

Stock Compensation Plans

 

Restricted Stock Units (RSUs)

On May 16, 2017, our Compensation Committee authorized the issuance and immediate vesting of 495,000 RSUs to our Chairman, President, and CFO. These shares were valued at $3.8 million, based on the May 16, 2017, closing stock price of $7.74.

By shareholder approval on May 25, 2017, our 2008 Restricted Stock Unit Plan (RSU Plan) was amended and restated to add 1,000,000 shares and extend its term through May 25, 2027.

On June 6, 2017, our Compensation Committee approved a Four-Year Compensation Plan for our Chairman, President, and CFO that granted them 645,000 RSUs. Beginning December 16, 2018, these RSUs will vest/lapse 25% annually through December 16, 2021, or earlier based on the terms of the RSU Plan and the applicable award agreements.   The closing stock price on the date of grant was $8.23.

 

The table below shows the number of RSUs available for issuance at December 31, 2017:2023:

 

Total authorized RSUs in Plan approved by shareholders			4,850,000
Stock issued out of the Plan from vested grants			(2,512,4323,540,178	)
Non-vested grants			(944,500858,363	)
RSUs available for future issuance			1,393,068451,459

Non-vested grants at January 1, 2015			1,042,000
Granted – share price on grant date was $11.52			2,000
Vested – weighted average share price on vesting date was $7.42			(410,500	)
Forfeited			(27,000	)
Non-vested grants at December 31, 20152021			606,500183,000
Granted – weighted average share price on grant date was $6.84$6.74			414,000881,437
Vested – weighted average share price on vesting date was $8.72			—
Forfeited			(271,5007,500	)
Forfeited			(16,000	)
Non-vested grants at December 31, 20162022			733,0001,056,937
Granted – weighted average share price on grant date was $7.98$9.30			1,211,500312,147
Vested – weighted average share price on vesting date was $7.22			(990,500472,721	)
Forfeited			(9,50038,000	)
Non-vested grants at December 31, 2017 (1)2023			944,500858,363

 

RSU Vesting Schedule

Vesting Year		RSUs Vesting
2024			319,419
2025			538,944

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(1)

RSU Vesting Schedule

Vesting Year		No. RSUs Vesting
2018			178,250
2019			373,750
2020			231,250
2021			161,250
			944,500

Vested sharesShares vested in 2023 had a value of $7.1$5.0 million for 2017, $2.4 million for 2016, and $3.0 million for 2015based on the share price of $10.69 on their vesting dates. Under our RSU plan, participants are allowed to relinquish shares to pay for their required statutory income taxes.

 

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The outstanding RSUs have a value of $6.2$7.2 million based on the March 9, 2018, 8, 2024 closing stock price of $6.53.$8.39.

 

For the years ended December 31, 2017, 2016 2023 and 2015 stock based2022, stock-based compensation was $7.3 million, $2.5$3.6 million and $3.1$1.3 million, respectively. For 2018, based on existing RSUs outstanding, stock-based

As of December 31, 2023, unrecognized stock compensation expense is estimated to be $2.0 million.was $4.1 million, and we had 451,459 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered non-participating securities.

 

Stock Options

 

We have no stock options outstanding.

 

Stock Bonus Plan(9)     EMPLOYEE BENEFITS

Our stock bonus plan was authorized in late 2009 with 250,000 shares. Currently, we have 86,383 shares available for future issuance.

(6)

Employee Benefits

We have no defined benefit pension plans or post-retirement benefit plans. We offer our employees a 401(k) Plan, where we match 100% of the first 4% that an employee contributes and a discretionary Deferred Bonus Plan for certain key employees.  We also offer health benefits to all employees and their families.  We have 2,289 participants in our employee health plan. The plan does not cover dental, vision, short-term or long-term disability. These coverages are available on a voluntary basis.  We bear some of the risk of our employee health plans. Our health claims are capped at $200,000 per person with a maximum annual exposure of $14.4 million, not including premiums.

 

Our employee benefit expenses for the years ended December 31 are below (in thousands):

 

		2017				2016				2015				2023				2022
Health benefits, including premiums		$	13,311			$	12,672			$	13,400			$	18,483			$	14,607
401(k) matching			1,892				1,458				2,267				2,910				2,549
Deferred bonus plan			677				588				445				687				809
Total		$	15,880			$	14,718			$	16,112			$	22,080			$	17,965

 

Of the amounts in the above table, $15.5 million, $13.8$21.5 million and $15.2$17.4 million for 2017, 2016, and 2015, respectively are recorded in operating costsexpenses in the consolidated statements of operations for the years ended December 31, 2023 and expenses2022, respectively, with the remainder in SG&A.general and administrative.

 

Our mine employees are also covered by workers’ compensation and such costs for 2017, 2016 and 2015 were approximately $2.8$4.9 million $2.3 millionfor 2023 and $4.6 million, respectively, of which $2.5 million, $2.3 million,2022, and $4.6 million, respectively are recorded in operating costs and expenses within the remainder in SG&A.consolidated statements of operations. Workers’ compensation is a no-faultno-fault system by which individuals who sustain work relatedwork-related injuries or occupational diseases are compensated. Benefits and coverage are mandated by each state which includes disability ratings, medical claims, rehabilitation services, and death and survivor benefits. OurWe are partially self-insured for such claims, however, its operations are protected from these perils through stop-loss insurance policies. Our maximum annual exposure is limited to $1$1.0 million per occurrence with a $4$4.0 million aggregate deductible.  Based on discussions

(10)     LEASES

We determine if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an operating lease, we record a right-of-use (“ROU”) asset and representations fromcorresponding liability reflecting the total remaining present value of fixed lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or terminate the lease when it is reasonably certain that we will exercise that option. If our insurance carrier,lease does not provide an implicit rate in the contract, we believe thatuse our reserve for our workers’ compensation benefits is adequate.incremental borrowing rate when calculating the present value. We have 2operating leases for office space and processing facilities with remaining lease terms ranging from less than one year to approximately five years. As most of the leases do not provide an implicit rate, we calculate the ROU assets and lease liabilities using our secured incremental borrowing rate at the lease commencement date. At December 31, 2023 and 2022, respectively, we had approximately $0.7 and $0.2 million of ROU operating lease assets recorded within buildings and equipment on the consolidated balance sheets. Operating lease expense associated with ROU assets is recognized on a safety conscious workforce,monthlybasis over the lease term in operating costson the consolidated statements of operation.

We entered into three finance leases during 2023, which are accounted for as failed sale-leaseback transactions. Finance lease assets are included in finance lease right-of-use assets on the consolidated balance sheets and basedthe associated finance lease liabilities are reflected within current portion of lease financing and long-term lease financing on the consolidated balance sheets as applicable. Depreciation on our experience modifier,finance lease assets was $2.3 million for the year ended December 31, 2023. Imputed interest expense on our claims are averaging 27% below thatlease liabilities was $0.1 million for the year ended December 31, 2023. We deferred financing fees of $0.1 million in connection with entry into the finance leases. These deferred financing fees will be amortized on a straight-line basis over the term of the finance leases. For the year ended December 31, 2023, the amortization of finance lease deferred financing fees was immaterial. 

Information related to leases was as follows as of December 31 (in thousands): 

		December 31,
		2023				2022
Operating lease information:
Operating cash outflows from operating leases		$	208			$	218
Weighted average remaining lease term in years			8.50				1.30
Weighted average discount rate			9.5	%			6.0	%
Finance lease information:
Financing cash outflows from finance leases		$	—			$	—
Proceeds from sale and leaseback arrangement			11,082				—
Weighted average remaining lease term in years			3.00				—
Weighted average discount rate			8.5	%			—	%

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We recognized the following costs related to our peersleases in underground coal mining in the stateour consolidated balance sheets:

	Classification on Consolidated Balance Sheets		December 31,
			2023				2022
			(in thousands)
Operating lease assets	Buildings and equipment		$	712			$	230
Operating lease liabilities:
Current operating lease liabilities	Accounts payable and accrued liabilities		$	58			$	173
Non-current operating lease liabilities	Other long-term liabilities		$	654			$	57
Total operating lease liabilities			$	712			$	230
Finance lease assets	Finance lease right-of-use assets		$	12,346			$	—
Finance lease liabilities:
Current finance lease liabilities	Current portion of lease financing		$	3,933			$	—
Non-current finance lease liabilities	Long-term lease financing		$	8,157			$	—
Total finance lease liabilities			$	12,090			$	—

Future minimum lease payments under non-cancellable leases as of Indiana.December 31, 2023, were as follows:

Year		Operating Leases				Finance Leases
		(in thousands)
2024		$	58			$	4,947
2025			118				4,645
2026			122				4,333
2027			125				—
2028			129				—
Thereafter			483				—
Total minimum lease payments		$	1,035			$	13,925
Less imputed interest and deferred finance fees			(323	)			(1,835	)
Total lease liability		$	712			$	12,090

 

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(11)     SELF INSURANCE

(7)

Other Long-Term Assets and Other Income (in thousands)

		2017				2016
Long-term assets
Advanced coal royalties		$	9,720			$	9,296
Marketable equity securities available for sale,
at fair value (restricted)*			2,148				2,036
Other			2,792				2,782
Total other assets		$	14,660			$	14,114

*Held by Sunrise Indemnity, Inc., our wholly owned captive insurance company.

		2017				2016				2015
Other income:
MSHA reimbursements**		$	1,725			$	1,753			$
Miscellaneous			1,341				2,209				2,236
		$	3,066			$	3,962			$	2,236

**See “MSHA Reimbursements” in the MD&A section for a discussion of these amounts.

(8)

Self Insurance

 

We self-insure ournon-leased underground mining equipment. Such equipment is allocated among 10seven mining units spread outdispersed over 2211 miles. The historical cost of such equipment is about $258 million.was approximately $262 million and $280 million as of December 31, 2023 and 2022, respectively. 

 

AsRestricted cash of $4.3 million and $3.4 million as of December 31, 2017, 2023 and 2016, restricted cash of $3.8 million and $2.8 million,2022, respectively, represents cash held and controlled by a third party and is restricted for future workers’ compensation claim payments.

  

(9)

Net Income per Share

We compute net income per share using the two-class method, which is an allocation formula that determines net income per share for common stock and participating securities, which for us are our outstanding RSUs.(12)     NET INCOME PER SHARE

 

The following table (in thousands, except per share amounts) sets forth the computation of net incomebasic earnings per share:share for the periods presented:  

		2017				2016				2015
Numerator:
Net income		$	33,076			$	12,510			$	20,132
Less earnings allocated to RSUs			(1,028	)			(305	)			(450	)
Net income allocated to common shareholders		$	32,048			$	12,205			$	19,682
Denominator:
Weighted average number of common shares outstanding			29,661				29,260				29,031
Net income per share:
Basic and diluted		$	1.08			$	0.42			$	0.68

		Year Ended December 31,
		2023				2022
Basic earnings per common share:
Net income - basic		$	44,793			$	18,105
Weighted average shares outstanding - basic			33,133				32,043
Basic earnings per common share		$	1.35			$	0.57
The following table (in thousands, except per share amounts) sets forth the computation of diluted net income per share:
		Year Ended December 31,
		2023				2022
Diluted earnings per common share:
Net income - basic		$	44,793			$	18,105
Add: Convertible Notes interest expense, net of tax			1,201				527
Net income - diluted		$	45,994			$	18,632
Weighted average shares outstanding - basic			33,133				32,043
Add: Dilutive effects of if converted Convertible Notes			3,164				1,398
Add: Dilutive effects of Restricted Stock Units			530				208
Weighted average shares outstanding - diluted			36,827				33,649
Diluted net earnings per share		$	1.25			$	0.55

  

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(13)     FAIR VALUE MEASUREMENTS

(10)

Fair Value Measurements

 

We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:

 

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our marketable securities areWe have no Level 1 instruments.

 

Level 2: Quoted prices in markets that are not active, or inputs whichthat are observable, either directly or indirectly, for substantially the full term of the asset or liability. We have no Level 2 instruments.

 

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). OurARO liabilities use Level 3 instruments are comprised non-recurring fair value measures as further discussed in Note 1. Lastly, Level 3 fair value measurements were also used in the determination of interest rate swaps. Thethe fair values of our swaps were estimated using discounted cash flow calculations based upon forward interest-rate yield curves.  Although we utilize third party broker quotes to assessassets acquired, liabilities assumed, and considerations exchanged as part of the reasonableness of our prices and valuation, we do not have sufficient corroborating market evidence to support classifying these assets and liabilities as Level 2.Merom Acquisition.

(14)     EQUITY METHOD INVESTMENTS

 

The following table summarizes our financial assets and liabilities measured on a recurring basis at fair value at December 31, 2017 and 2016 by respective level of the fair value hierarchy:Sunrise Energy, LLC

		Level 1				Level 2				Level 3				Total
		(in thousands)
December 31, 2017
Assets:
Marketable securities		$	1,907			$	-			$	-			$	1,907
Marketable securities - restricted			2,148				-				-				2,148
Interest rate swaps			-				-				543				543
		$	4,055			$	-			$	543			$	4,598
December 31, 2016
Assets:
Marketable securities		$	1,763			$	-			$	-			$	1,763
Marketable securities - restricted			2,036				-				-				2,036
Interest rate swaps			-				-				296				296
		$	3,799			$	-			$	296			$	4,095
Liabilities:
Interest rate swaps		$	-			$	-			$	476			$	476

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The table below highlights the change in fair value of the interest rate swaps:

		Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
		Interest Rate Swaps
		(in thousands)
Ending balance, December 31, 2015		$	(817	)
Change in estimated fair value			637
Ending balance, December 31, 2016			(180	)
Change in estimated fair value			723
Ending balance, December 31, 2017		$	543

(11)

Equity Method Investments

 

We own a 50% interest in Sunrise Energy, LLC, which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our underground coal reserves. We received distributions totaling $175,000 and $375,000 forThe carrying value of the years ended investment included in the consolidated balance sheets as of December 31, 2017 2023 and 2016,2022 was $2.8 million and $4.0 million, respectively.

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(15)     MEROM ACQUISITION

 

We ownOn February 14, 2022, Hallador Power signed an Asset Purchase Agreement (“APA”), with Hoosier, a 30.6% interest in Savoy Energy, L.P., a private company engaged inrural electric membership corporation organized and existing under the oil and gas business primarily inlaws of the state of Michigan.Indiana.

Under the APA, Hallador Power acquired the Merom power plant, along with: equipment and machinery in the power plant; materials inventory; a coal purchase agreement; a coal combustion certified coal ash landfill, certain generation interconnection agreements, and coal inventory (collectively, the “Acquired Assets”). Additionally, contemporaneous with entering into the APA, Hallador Power entered into three other agreements with Hoosier comprised of (1) a Power Purchase Agreement (the “PPA”), (2) a Coal Supply Purchase Agreement (the “Coal Purchase Agreement”), and (3) a Closing Side Letter agreeing to a reduction in future capacity payments of $15.0 million (“Capacity Payment Reduction”). The purchase price for the Acquired Assets also consisted of the assumption of the power plant’s closure and post-closure remediation, valued at approximately $7.2 million; no cash was paid by Hallador Power to Hoosier to effectuate the APA other than payments totaling approximately $17.0 million for coal inventory on hand, with an initial payment of $5.4 million and subsequent periodic payments over time, subject to post-close adjustments based on actual on-site inventories. The acquisition closed on October 21, 2022.

The acquisition was accounted for as an asset acquisition under ASC Topic 805-50,Business Combinations as substantially all of the fair value of the gross assets acquired are concentrated in a group of similar identifiable assets. As such, the total purchase consideration (which includes $2.9 million of transaction costs) is allocated to the assets acquired on a relative fair value basis.

The following table summarizes the final relative fair value allocation of assets acquired and liabilities assumed and incurred as of the Merom Acquisition date.

Consideration:			(in thousands)
Direct transaction costs		$	2,855
Contract liability - PPA			184,500
Contract liability - Capacity payment reduction			11,000
Contract asset - Coal purchase agreement			(34,300	)
Coal inventory purchased			5,400
Deferred coal inventory payment			11,600
Total consideration		$	181,055
Relative fair value of assets acquired:
Plant		$	165,816
Materials and supplies			12,009
Coal inventory			10,460
Amount attributable to assets acquired		$	188,285
Fair value of liabilities assumed:
Asset retirement obligations		$	7,230
Amount attributable to liabilities assumed		$	7,230

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(16)     CONVERTIBLE NOTES

 

On November 3, 2016, Lubar Equity Fund, LLC acquired a 25% interestMay 2, 2022, and May 20, 2022, we issued senior unsecured convertible notes (the “Notes”) to five parties, in Savoy for $9.5the aggregate principal amount of $10 million, in cash. Accordingly, our ownership interest was reduced from 40.8%with $9 million being issued to 30.6%. At closing, Savoy made a cash distribution of $4.4 million of which our share was $1.8 million and per our credit agreement was applied to our bank debt. Mr. Lubar, onerelated parties affiliated with independent members of our board of directors and the remainder to a non-affiliated party. The Notes were scheduled to mature on December 29, 2028, and accrue interest at 8% per annum, with interest payable on the date of maturity. Pursuant to the terms of the Notes, the holders of the Notes may convert the entire principal balance and all accrued and unpaid interest then outstanding during the period beginning June 1, 2022, and ending on May 31, 2027, into shares of the Company's common stock at a conversion price the greater of (i) $3.33 and (ii) the 30-day trailing volume-weighted average sales price for the common stock on the Nasdaq Capital Market ending on and including the date on which this Note is affiliatedconverted. At any time on or after June 1, 2025, we may, at our option and upon 30 days' written notice provided to the holders, elect to redeem the Notes (in whole and not in part) and the holders shall be obligated to surrender the Notes, at a redemption price equal to 100% of the outstanding principal balance, together with Lubar Equity Fund, LLC.any accrued but unpaid interest thereon to the redemption date. After receipt of such redemption notice from us, the holder may, at its option, elect to convert the principal balance and accrued interest into the Company's common stock by giving written notice of such election to us no later than 5 days prior to the date fixed for redemption.

 

We did not receive any distributions in 2017In June 2022, the four holders of the $9 million related party notes converted them into 1,965,841 shares of common stock of the Company and received two distributions in 2016 totaling $3.6the one holder of the $1 million from Savoy. Both distributions were appliedNotes converted it into 231,697 shares of common stock pursuant to our bank debt as required under our agreement.

Savoy also recorded impairmentsthe terms of $1.0 million, $2.0 million,the Notes and $2.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.their related agreements.

We have reached an agreement for Savoy to redeem our entire partnership interest for $8 million, which we expect to finalize in mid-March 2018. Our net after commissions paid will be $7.5 million.

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(12)

Freelandville and Log Creek Purchases

 

On March 22, 2016, July 29, 2022, we completedissued an additional $5 million senior unsecured convertible note to a related party affiliated with an independent member of our board of directors. The Note carries an interest rate of 8% per annum with a maturity date of December 29, 2028. For the purchaseperiod August 18, 2022 through August 17, 2024, the holder has the option to convert the Note into shares of our common stock at a conversion price of $6.254. Beginning August 18, 2025, we may elect to redeem the Note and the holder shall be obligated to surrender the note at 100% of the Freelandville coal reserves, advanced royalties,outstanding principal balance together with any accrued unpaid interest.  Upon receipt of the redemption notice from us, the holder may elect to convert the principal balance and coal sales agreement for $18.25 million from Triad Mining LLC. These reserves totaled 14.2 million tons of fee and leased coal and will be mined from our Oaktown 1 portal. This purchase allowed us access to another 1.6 million tons of our own leased reserves that were previously inaccessible. The purchased coal sales agreement totaled 1,435,000 tons and was fulfilled in 2017. The purchase price allocation foraccrued interest into the acquisition was as follows (in thousands):Company's common stock.

Purchased coal contract		$	6,407
Advanced coal royalties			1,690
Mineral rights and leases			10,153
Total		$	18,250

 

On August 8, 2022, we issued an additional $4 million of senior unsecured convertible notes to related parties affiliated with independent members of our board of directors. The Notes carry an interest rate of 8% per annum with a maturity date of December 12, 2016, 29, 2028. For the period August 18, 2022 through August 17, 2024, the holder has the option to convert the Notes into shares of our common stock at a conversion price of $6.254. Beginning August 8, 2025, we completed a second transactionmay elect to redeem the Notes and the holder shall be obligated to surrender the Notes at 100% of the outstanding principal balance together with Triad,any accrued unpaid interest.  Upon receipt of the purchase of their Log Creek coal sales agreement for $4.1 million. The purchased coal sales agreement included 557,000 tons that were delivered in 2016redemption notice from us, the holder may elect to convert the principal balance and 2017.accrued interest into the Company's common stock.

 

(13)

Quarterly Financial Data (Unaudited)

On August 12, 2022, we issued an additional $10 million senior unsecured convertible note to an unrelated party. The Note carries an interest rate of 8% per annum with a maturity date of December 31, 2026. For the period August 18, 2022, through the maturity date, the holder has the option to convert the Note into shares of our common stock at a conversion price of $6.15. Beginning August 12, 2025, we may elect to redeem the Note and the holder shall be obligated to surrender the Note at 100% of the outstanding principal balance together with any accrued unpaid interest. Upon receipt of the redemption notice from us, the holder may elect to convert the principal balance and accrued interest into the Company's common stock.

 

Summarized quarterly financial data is as follows:

		Three Months Ended
		Dec-31				Sep-30				Jun-30				Mar-31
		(In thousands, except per share data)
2017
Revenue		$	69,300			$	74,468			$	64,312			$	63,553
Operating income			3,921				7,155				4,065				11,154
Net income (loss) *			21,357				3,916				389				7,414
Basic income per common share		$	0.69			$	0.13			$	0.01			$	0.25
2016
Revenue		$	71,234			$	65,767			$	68,564			$	75,885
Operating income			7,972				7,686				10,732				13,496
Net income (loss) *			(3,827	)			4,322				5,853				6,162
Basic income per common share		$	(0.13	)		$	0.14			$	0.19			$	0.21

*SeeThe funds received from the issuance of the various Notes described above in this Note 2 related16 were used to asset impairment taken in December 2016 and Note 4 relatedprovide additional working capital to the effectsCompany. The conversion price and number of shares of our common stock issuable upon conversion of the Tax Act in December 2017.above notes are subject to adjustment from time to time for any subdivision or consolidation of our shares of common stock and other standard dilutive events.

 

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(17)     AT MARKET AGREEMENT

(14)

Accounts Payable and Accrued Liabilities

		2017			2016
Accounts payable	$	4,008		$	4,829
Goods received not yet invoiced		5,574			3,072
Accrued property taxes		2,751			2,992
Workers' compensation reserve and IBNR		2,969			2,658
Other		5,813			6,367
Total accounts payable and accrued liabilities	$	21,115		$	19,918

ITEM 9:

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

 

Not applicable.On December 18,2023, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with B. Riley Securities, Inc. (the “Agent”), pursuant to which we may issue and sell, from time to time, shares (the “Shares”) of our common stock, par value $0.01 per share (the “Common Stock”), with aggregate gross proceeds of up to $50 million through an “at-the-market” equity offering program under which the Agent will act as sales agent (the “ATM Program”). Under the Sales Agreement, each of us and the Agent have the right, by giving five (5) days’ notice, to terminate the Sales Agreement in its sole discretion. The Agent may also terminate the Agreement, by notice to us, upon the occurrence of certain events described in the Sales Agreement.

 

ITEM 9A.

CONTROLS AND PROCEDURES.

During December 2023, we issued 794,000 shares of Common Stock under the ATM Program for net proceeds of $7.3 million. For the period January 1, 2024, to March 14, 2024, we issued 710,623 shares of Common Stock under the ATM Program for net proceeds of $6.6 million. 

(18)     SEGMENTS OF BUSINESS

At December 31, 2023, our operations are divided into two primary reportable segments, the Coal Operations and Electric Operations segments. 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 and Eliminations” and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, which is accounted for using the equity method and our wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

Year Ended December 31, (in thousands)		2023				2022
Operating Revenues
Coal Operations		$	435,425			$	293,344
Electric Operations		$	268,341			$	66,316
Corporate and Other and Eliminations		$	(69,286	)		$	2,331
Consolidated Operating Revenues		$	634,480			$	361,991
Income (Loss) from Operations
Coal Operations		$	63,600			$	3,736
Electric Operations		$	12,552			$	31,505
Corporate and Other and Eliminations		$	(11,140	)		$	(4,811	)
Consolidated Income (Loss) from Operations		$	65,012			$	30,430
Depreciation, Depletion and Amortization
Coal Operations		$	48,365			$	43,612
Electric Operations		$	18,739			$	3,117
Corporate and Other and Eliminations		$	107			$	146
Consolidated Depreciation, Depletion and Amortization		$	67,211			$	46,875
Assets
Coal Operations		$	376,387			$	376,228
Electric Operations		$	208,331			$	266,730
Corporate and Other and Eliminations		$	5,062			$	(12,404	)
Consolidated Assets		$	589,780			$	630,554
Capital Expenditures
Coal Operations		$	56,521			$	50,367
Electric Operations		$	18,831			$	3,653
Corporate and Other and Eliminations		$	-			$	-
Consolidated Capital Expenditures		$	75,352			$	54,020

(19)     SUBSEQUENT EVENTS

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. We also focused our seven units of underground equipment on four units of our lowest cost production at our Oaktown Mine. Increasing the run time of these four lower cost units from five and a half days per week to seven days per week is intended to further improve the overall cost structure of the coal segment. As part of the initiative, the Company reduced its workforce by approximately 110 employees.

In the first quarter of 2024, Hallador borrowed $5 million from certain members of the Company’s Board of Directors. The notes are unsecured, mature in February 2025 and accrue interest at 12% annually, with interest to be paid quarterly beginning on May 31, 2024.

In February 2024, the Company elected to pay the semi-annual interest due on the $19 million senior unsecured convertible notes with common stock as allowed in the note agreements. The amount of stock issued for the interest payments was 122,600 shares.

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ITEM 9:  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

 

ITEM 9A.  CONTROLS AND PROCEDURES.

Disclosure Controls

 

We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC'sSEC’s rules and forms, and that such information is accumulated and communicated to our CEO and CFO as appropriate to allow timely decisions regarding required disclosure.

 

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.

 

Management's Annual Report on Internal Control Overover Financial Reporting (ICFR)(ICFR)

 

Our management, including our CEO and CFO, is responsible for establishing and maintaining adequate ICFR. Our ICFR is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Management evaluated the effectiveness of our ICFR based on the framework in “Internal Control – IntegratedControl-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in 2013.

 

Our management evaluated, with the participation of our CEO and CFO, the effectiveness of our ICFR as of December 31, 2017.2023.  Based on that evaluation, our management concluded that our ICFR was effective at December 31, 2017. EKS&H LLLP2023.  

Grant Thornton LLP, an independent registered public accounting firm, has audited and reported onmade an independent assessment of the effectiveness of our internal control over financial statements and our ICFRreporting as of December 31, 2017. Their2023, as stated in their report that is contained in this Form 10-K.included herein.

 

There were no significant changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2017,2023, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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ITEM 9B.

OTHER INFORMATION       None.

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Hallador Energy Company

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Hallador Energy Company (a Colorado corporation) and subsidiaries (the “Company”) as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2023, and our report dated March 14, 2024 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

March 14, 2024

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ITEM 9B.OTHER INFORMATION 

Item 9C.  Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

None.

 

PART III

 

ThePursuant to paragraph 3 of General Instruction G to Form 10-K, the information required forby Items 10-1410 through 14 of Part III of this Report is hereby incorporated by reference to that certain information infrom our Proxy Statementdefinitive proxy statement, which is to be filed withpursuant to Regulation 14A within 120 days after the SEC during April 2018.end of our fiscal year ended December 31, 2023.

 

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

ITEM 11.

EXECUTIVE COMPENSATION

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES.

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ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

See Item 8 for an index of our financial statements.

 

Our exhibit index is as follows:

 

3.1	1.1	At Market Issuance Sales Agreement, dated December 18, 2023, between Hallador Energy Company and B. Riley Securities, Inc. (21)
3.1	Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009.2009 (1)
3.2		By-laws of Hallador Energy Company, effective December 24, 2009 (1)(2)
10.2 4.1		2009 Stock Bonus Plan (2)*Description of Securities (3)
10.3 10.2		SecondThird Amended and Restated Credit Agreement – August 29, 2014 (3)dated May 21, 2018 (5)
10.4	10.3	FirstSecond Amendment to the SecondThird Amended and Restated Credit Agreement and Waiver dated September 30, 2019 (6)
10.4	Third Amendment to the Third Amended and Restated Credit Agreement and Waiver (7)
10.5	Sixth Amendment to the Third Amended and Restated Credit Agreement dated March 18, 2016 (4)25, 2022 (10)
10.	Seventh Amendment to the Third Amended and Restated Credit Agreement dated May 20, 2022 (12)
10.6	Eighth Amendment to the Third Amended and Restated Credit Agreement dated August 5, 2022 (14)
10.7	Ninth Amendment to the Third Amended and Restated Credit Agreement dated September 28, 2022 (16)
10.8	Tenth Amendment to the Third Amended and Restated Credit Agreement dated March 13, 2023 (19)
10.5	10.9	Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement* (5)Amendment and Restated Loan Agreement dated August 2, 2023 (20)
10.6 10.10		Amended and Restated Hallador Energy Company 2008 Restricted Stock Unit Plan (6)(8)
10.7 10.11		Form of Hallador Energy Company Four-Year Plan* (7)Restricted Stock Unit Issuance Agreement (8)
14 10.13	2022 Executive Officer Compensation Plan**(17)
10.14	Asset and Purchase Agreement dated February 14, 2022 (9)
14.1	Code of Ethics for Senior Financial Officers. (8)*Officers (18)
21.1		List of Subsidiaries (9)Subsidiaries*
23.1		Consent of EKS&H LLLP (9)Grant Thornton LLP*
23.2	31Consent of John T. Boyd Company*
31.1	SOX 302 Certification - President and CEO*
31.2	SOX 302 Certifications (9)- CFO*
32	SOX 906 Certification*
95	Mine Safety Disclosure*
97.1	Hallador Energy Company Policy for the Recovery of Erroneously Awarded Compensation*
99.1	Technical Report Summary (Coal Resources and Coal Reserves, Oaktown Mining Complex), dated October 2023(22)
32	99.2	SOX 906 Certification (9)Letter from Boyd and Company, dated January 29, 2024*
95		Mine Safety Disclosure (9)
101		Interactive data files. (9)

 

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(1) 101.INS*	Inline XBRL Instance Document
101.SCH*	Inline XBRL Schema Document
101.CAL*	Inline XBRL Calculation Linkbase Document
101.LAB*	Inline XBRL Labels Linkbase Document
101.PRE*	Inline XBRL Presentation Linkbase Document
101.DEF*	Inline XBRL Definition Linkbase Document
104*	Cover Page Interactive Data File (embedded within the Inline XBRL and contained in Exhibit 101)

(1)	IBR to Form 8-K dated December 31, 2009
(2)	IBR to Form S-8 dated December10-K/A amendment 1, 2009filed June 12, 2020
(3)	IBR to Form 10-Q dated November 10, 201410-K filed March 9, 2020
(4)	IBR to Form 10-Q dated Mayfiled August 6, 20162018
(5)	IBR to Form 8-K dated May 17, 201710-Q filed November 4, 2019
(6)	IBR to Form 10-Q dated August 8, 2017filed May 11, 2020
(7)	IBR to Form 10-QDEF 14A dated May 6, 2016April 11, 2017
(8)	IBR to the 2005 Form 10-KSB.8-K/A filed February 18, 2022
(9)	IBR to Form 10-K filed March 28, 2022
(10)	IBR to Form 10-Q filed May 23, 2022
(11)	IBR to Form 8-K filed August 11, 2022
(12)	IBR to Form 8-K filed October 4, 2022
(13)	IBR to Form 10-Q filed November 14, 2022
(14)	IBR to Form 10KSB dated April 14, 2006
(15)	IBR to Form 10-K filed on March 16, 2023
(16)	IBR to Form 10-Q filed on August 7, 2023
(17)	IBR to Form 8-K filed on December 18, 2023
(18)	IBR to Form 10-K/A amendment 1, filed November 1, 2023
*	Filed herewith.

  

**    Management Agreements

 

ITEM 16.

Form 10-K Summary.

ITEM 16.  FORM 10-K SUMMARY.

 

As this item is optional, no summary is presented.

 

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SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

	HALLADOR ENERGY COMPANY
Date: March 14, 2024	/s/LAWRENCE D. MARTIN
	Lawrence D. Martin, CFO (Principal Financial Officer and Principal Accounting Officer)
Date: March 12, 2018	/s/ LAWRENCE D. MARTIN
	Lawrence D. Martin, CFO and CAO

  

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

  

/s/  /s/DAVID HARDIE
David Hardie		Director		March 12, 201814, 2024
/s/ BRYAN LAWRENCE
/s/BRYAN LAWRENCE
Bryan Lawrence		Director		March 12, 201814, 2024
/s/ BRENT BILSLAND
/s/BRENT BILSLAND
Brent Bilsland		Board Chairman, President and CEO		March 12, 201814, 2024
/s/ SHELDON B. LUBAR
Sheldon B.
/s/DAVID J.  LUBAR
David J.  Lubar		Director		March 12, 201814, 2024

  

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