Carbon DioxideGHG Emissions

Combustion of fossil fuels, such as the coal we produce, 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.United States, 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 Although the U.S. would withdrawUnited States had withdrawn from the Paris Agreement, President Biden recommitted the United States in February 2021 and, in April 2021, announced a new, more rigorous nationally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 United States 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.United States 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 United States 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 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-fueled 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 proposedEPA's  New Source Performance Standards (“NSPS”("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 2017,2021, the EPA published notice in the federal registera final significant contribution finding for purposes of regulating source category of GHG emissions, confirming that the agency has initiated a review of the NSPS for new and modified fossil fuel-firedsuch power plants are a source category for such regulations. However, this finding also excludes several sectors 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 willmay, therefore, be subject to legal challenges as well.  Futurerevision, and future implementation of the NSPS is uncertain at this time. The EPA is expected to publish a notice of proposed rulemaking in Spring 2023.

In August 2015, the EPA issued its final Clean Power Plan ("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") 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 is uncertain at this time.   In connection with this proposed repeal,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 issued an Advance Noticehad acted outside the bounds of Proposed Rulemaking ("ANPRM") in December 2017 regarding emission guidelinesthe legal authority granted 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.agency by Congress.

Collectively, theseNotwithstanding the ACE rule, the CPP's requirements haveand impact during the pendency of the litigation led to premature retirements and 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”("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 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, and the discharge of dredged or fill material into the waters of the U.S.  Regular monitoring, as well as compliance with reporting requirements and performance standards, is a precondition for the issuance and renewal of permits governing the discharge of pollutants into water.primarily through permitting. 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 coal mining operations that impact such wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future “fill” permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future.  Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

The U.S.In order for us to conduct certain activities, we may need to obtain a permit for the discharge of fill material from the United States Army Corps of Engineers (“("Corps of Engineers”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 could require more costly water treatment and could adversely affect our coal production.

Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the Clean Water Act. ACWA. Rulemakings to establish the extent of such jurisdiction were finalized in 2015 rulemaking byand 2020, respectively, and both rulemakings have been subject to substantial litigation. Although the EPA and Corps of Engineers did not seek to revisevacate the standard was stayed nationwide by2020 rule on an interim basis, two federal district courts in Arizona and New Mexico vacated the U.S.2020 rule in decisions announced during the third quarter of 2021. In December 2022, the EPA and Corps of Engineers released a final revised definition of "waters of the United States" ("WOTUS") founded upon a pre-2015 definition and including updates to incorporate existing Supreme Court of Appeals fordecisions. However, continued uncertainty remains as to the Sixth Circuit and stayed for certain primarily western states by a United States District Court in North Dakota.government's jurisdictional reach as the rule is likely to be subject to legal challenge. Judicial developments further add to this uncertainty. In January 2018,October 2022, the Supreme Court determined thatheard oral arguments in Sackett v. EPA regarding the circuit courts do not have jurisdiction to hear challenges to 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 datescope and authority 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, EPACWA 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 Court 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 waterWOTUS and is expected to release an opinion in this case in 2023, which could impact the regulatory definition and its implementation. To the extent any decision expands the scope of the United States be promulgated as a result of EPA and the Corps of Engineers' rulemaking process,jurisdiction under the CWA, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.

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 generate waste containing hazardous substances. We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

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 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 in particular because it regulates the disposal of certain coal combustion by-products (“CCB”). 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 soliddisposal of CCB. Under the finalized regulations, CCB 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 CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers’customers' operating costs and potentially reduce their ability to purchase coal. The CCB rule was subject to legal challenge and ultimately remanded to the EPA. On August 28, 2020, the EPA published a final revised rule mandating closure of unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site specific circumstances. Certain provisions of the revised CCB rule were vacated by the D.C. Circuit in 2018. The EPA is expected to finalize additional rules addressing those specific provisions in June 2023. Meanwhile, on January 25, 2022, the EPA published determinations for 9 of 57 CCB facilities who sought approval to continue disposal of CCB and non-CCB waste streams until 2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule. While the EPA issued one conditional approval, the EPA is requiring the remaining facilities to cease receipt of waste within 135 days of completion of public comment or around July 2022. And, in January 2023, the EPA issued six proposed determinations to deny facilities' requests to continue disposal into unlined surface impoundments.  The current determinations, future determinations of the same nature, or similar actions in expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. The combined effect of the CCB rules and Effluent Limitations Guidelines and Standards ("ELG") regulations (discussed below) has compelled power generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot comply with the new standards. Such retirements may adversely affect the demand for our coal.

On November 3, 2015, the EPA published the final rule, Effluent Limitations Guidelines and Standards (“ELG”),ELG,  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 CCRCCB 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. These regulations add costsIn November 2019, the EPA proposed revisions to the operation2015 ELG rule and announced proposed changes to regulations for the disposal 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 plantscoal ash in order to reduce fish impingement and entrainment.  Individually and collectively,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 expects to issue a proposed rule for public comment in the summer of 2023.  It is unclear what impact these regulations could, in turn, impactwill have on the market for our products.  In April 2017, EPA granted petitions for reconsideration 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.

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 LIHEAP 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, 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. Coal Industry

The major coal production basins in the U.S. include Central Appalachia (CAPP), Northern Appalachia (NAPP), Illinois Basin (ILB), Powder River Basin (PRB), and the Western Bituminous region (WB). CAPP includes eastern Kentucky, Tennessee, Virginia and southern West Virginia. NAPP includes Maryland, Ohio, Pennsylvania, and northern West Virginia. The 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, through its wholly-owned subsidiary Sunrise Coal, LLC, 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 States 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, 2022, Hallador Energy Company and its subsidiaries employed 980 full-time employees and temporary miners.  930 of which 736those employees and temporary miners are directly involved in the coal mining or coal washing process.   Our workforce is entirely union-free.  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 Energy’s wholly owned subsidiary, Sunrise Coal, employees.LLC.   With a robust safety department and safety standards that exceed mandated guidelines, we make safety the foundation of everything we do.  While every precaution is taken to prevent mine emergencies, Sunrise Coal has its own private mine rescue team.  This team is trained and ready to manage any emergency at a Sunrise Coal, LLC 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 95.1 to this Annual Report on Form 10-K.

While other companies have moved to high deductible health plans, Hallador Energy 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 Energy 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 Denver office is located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504 and Sunrise Coal's corporate office is located at 1183 East Canvasback Drive, Terre Haute, Indiana, 47802, phoneas well as Sunrise Coal and Hallador Power's corporate offices. 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%2022, the vast majority of our 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 utilities 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 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 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.

During 2017,2022, we derived 92%90% of our coal revenue from five 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 customers may result  Our electric operations revenue for 2022 was generated entirely by one customer as a condition of the Asset Purchase Agreement upon the closing of the acquisition of Hoosier Energy's Merom Generation Station ("Merom") in substantial costs, liabilities, and loss of revenue.October 2022.

From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract.  Disputes 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 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.

Our mining operations arerecent acquisition of Merom may not achieve its intended results.

On October 21, 2022, the Company, through its subsidiary Hallador Power Company, LLC, completed its acquisition of the one Gigawatt Merom Generating Station located in Sullivan County, Indiana pursuant to an Asset Purchase Agreement with Hoosier Energy.  The Company entered into the Asset Purchase Agreement with the expectation that the acquisition of Merom would result in various benefits, including, among other things, securing future demand for a material portion of the Company’s coal production and also providing a path for Merom’s transition to renewable energy when the coal plant is eventually retired. Achieving the anticipated benefits of the acquisition (including the eventual transition to renewable energy) is subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.

We are subject to numerous federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restorationa number of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability.  Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct.uncertainties. Failure to comply withachieve these laws and regulations mayanticipated benefits could result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limitinglower-than-expected revenues or prohibiting the performance of operations.  Complying with these laws and regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations.  The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers’ use of coal.  Please read “Item 1. Business—Regulations and Laws.”

State and federal laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations.  Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards.  Implementing and complying with these laws and regulations has increased and will continue to increase our operational expense and to have an adverse effect on our results of operation and financial position.  For more information, please read “Item 1. Business—Regulation and Laws—Mine Health and Safety Laws.”

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

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining.  The permitting rules are complex and can change over time.  Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance.  The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention.  Accordingly, permits required to conduct our operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations.  Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability.  Please read “Item 1. Business—Regulations and Laws—Mining Permits and Approvals.”

The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA.  Various initiativesincome generated by the EPA regarding these permits have increased thecombined businesses and diversion of management’s time required to obtain and the costs of complying with such permits.  In addition, the EPA previously exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia.  The EPA’s action was ultimately upheld by a federal court. As a result of these developments, we may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for our operations, whichenergy and could have an adverse effect on ourthe Company’s business, financial results of operation and financial position.  Please read “Item 1. Business—Regulations and Laws—Water Discharge.”

prospects.  In addition, some of our permits could be subject to challenges fromin connection with the public, which could result in additional costs or delays inAsset Purchase Agreement, the permitting process, or even an inability to obtain permits, permit modifications or permit renewals necessary for our operations.

Fluctuations in transportationCompany assumed certain decommissioning costs and the availability or reliability of transportation could reduce revenue by causing us to reduce our production or by impairing our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision.  Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources.  Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers.  Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenue.  If there are disruptions of the transportation services provided by our primary rail carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country.  For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S.  Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets.  Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers.environmental responsibilities.  In the event of further reductions in transportationthese assumed costs from western coal producing areas,and responsibilities exceed the increased competition with certain eastern coal markets could have a material adverse effect on our business, financial condition and results of operations.

It is possibleCompany’s estimates, the Company may incur additional liabilities that states in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads.  Such legislation and enforcement efforts could result in shipment delays and increased costs.  An increase in transportation costs could have an adverse effect on our abilitythe Company’s business, financial results and prospects.

The operation and maintenance of the Merom facilities or future investment in the Merom facilities are subject to increase or to maintain production andoperational risks that could adversely affect revenue.

We may not be able to successfully grow through future acquisitions.our financial position, results of operations and cash flows.

We have expanded our operationsThe operation and maintenance of generating facilities involves many risks, including the performance by addingkey contracted suppliers and developing minesmaintenance providers; increases in the costs for or limited availability of key supplies, labor and coal reservesservices; breakdown or failure of facilities; curtailment of facilities by counterparties; or the impact of unusual, adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output or efficiency. The Merom facilities contain older generating equipment, which even if maintained in existing, adjacent and neighboring properties.  We continually seek to expand our operations and coal reserves.  Our future growth could be limited if we are unableaccordance with good engineering practices, may require additional capital expenditures to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire.  We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown.  Moreover, any acquisition could be dilutive to earnings. Our ability to make acquisitions in the future could require significant amounts of financing that may not be available to us under acceptable terms andoperating at peak efficiency, while additional costs may be limitedrequired as we eventually transition the Merom facilities to renewable energy.  We could also be subject to costs associated with any unexpected failure to produce and deliver power, including failure caused by restrictions under our existingbreakdown or future debt agreements, competition fromforced outage, as well as the repair of damage to facilities due to storms, natural disasters, wars, sabotage, terrorist acts and other coal companies for attractive properties or the lack of suitable acquisition candidates.catastrophic events.

Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline, and we could experience a material adverse effect on our business, financial condition, or results of operations.  Expansion and acquisition transactions involve various inherent risks, including:

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

Completion of growth projects and future expansion could require significant amounts of financing that may not be available to us on acceptable terms, or at all.

We plan to fund capital expenditures for our current growth projects with existing cash balances, future cash flows from operations, borrowings under credit facilities and cash provided from the issuance of debt or equity. WeaknessAt times, weakness in the energy sector in general and coal, in particular, has significantly impacted access to the debt and equity capital markets. Accordingly, our funding plans may be negatively impacted by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, we may be unable to refinance our current credit facilitiesdebt obligations when they expire or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet their funding obligations. Furthermore, additional growth projects and expansion opportunities may develop in the future that could also require significant amounts of financing that may not be available to us on acceptable terms or in the amounts we expect, or at all.

Various factors could adversely impact the debt and equity capital markets as well as our credit ratings or our ability to remain in compliance with the financial covenants under our then current debt agreements, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth and future expansions as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.

Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, could be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we could be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

We may not recover our investments in our mining and other assets, which may require us to recognize impairment charges related to those assets.

The value of our assets has from time to time been adversely affected by numerous uncertain factors, some of which are beyond our control, including unfavorable changes in the economic environments in which we operate, lower-than-expected coal pricing, technical and geological operating difficulties, an inability to economically extract our coal reserves and unanticipated increases in operating costs. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of operations.

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

As disclosed in Note 5 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a Minimum Debt Service Coverage Ratio (consolidated adjusted EBITDA/annual debt service) of 1.25 to 1.00 and (ii) a Maximum Leverage Ratio (consolidated funded debt/trailing twelve months adjusted EBITDA) not to exceed 2.50 to 1.00, which also decreases for March 31, 2023 and each fiscal quarter thereafter to 2.25 to 1.00.

On December 31, 2022, our debt service coverage ratio was 1.49, and our leverage ratio was 2.05. Therefore, we were in compliance with these two ratios.

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

On December 31, 2022, our funded bank debt was $85.2 million, we had outstanding convertible notes totaling $19 million, and held letters of credit totaling $11.2 million. Our leverage may:

Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions, and capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

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

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

Investor and lender focus on ESG matters may negatively impact our business, financial results, and stock price.

Companies across all industries, including companies in the fossil-fuel industry, are facing increased scrutiny from stakeholders related to their ESG practices. Companies that do not adapt or comply with evolving investor or stakeholder expectations and standards, or are perceived to have not responded appropriately to ESG issues, regardless of any legal requirement to do so, may suffer reputational damage and the business, financial condition, and stock price of such companies could be materially and adversely affected. Several advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, universities, and other members of the investing community. These activities include increasing attention to and demands for action related to climate change, promoting the use of substitutes to fossil-fuel products, encouraging the divestment of fossil-fuel equities, and pressuring lenders to limit funding to companies engaged in the extraction of fossil-fuel reserves. These activities could increase costs, impact our supply chain, reduce demand for our coal, reduce our profits, increase the potential for investigations and litigation, impair our brand, limit our choices for lenders, insurance providers and business partners, and have negative impacts on our stock price and access to capital markets.

In addition, certain organizations that provide corporate governance and other corporate risk information to investors have developed scores and ratings to evaluate companies and investment funds based upon ESG or "sustainability" metrics. Currently, there are no universal standards for such scores or ratings, but consideration of sustainability evaluations is becoming more broadly accepted by investors. Indeed, many investment funds focus on positive ESG business practices and sustainability scores when making investments, whereas other funds may use certain ESG criteria to "screen" certain sectors, such as coal or fossil fuels more generally, out of their investments. In addition, investors, particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance or sell their interests in the company, particularly if its ESG performance does not improve. Moreover, certain members of the broader investment community may consider a company's sustainability score as a reputational or other factor in making an investment decision. Companies in the energy industry, and in particular those focused on coal, natural gas, or oil extraction, often do not score as well under ESG assessments compared to companies in other industries. Consequently, a low ESG or sustainability score could result in our securities being excluded from the portfolios of certain investment funds and investors, restricting our access to capital to fund our continuing operations and growth opportunities.  Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.  

Public statements with respect to ESG matters, such as emission reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential "greenwashing," i.e., misleading information or false claims overstating potential ESG benefits. For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG-statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further ESG-related focus and scrutiny.

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

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

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

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

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

Risks Related to our Industry

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 revenues to the extent we are not protected by the terms of existing coal supply agreements.

Competition within the coal industry could adversely affect our ability to sell coal.

We compete with other coal producers for domestic coal sales in various regions of the U.S. The most important factors on which we compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics, contract flexibility (e.g., volume optionality and multiple supply sources) and reliability of supply. Some competitors could have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships with specific transportation providers. The competition among coal producers could impact our ability to retain or attract customers and could adversely impact our revenues and cash from operations.

Changes in taxes or tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.

We pay certain taxes and fees related to our operations. Congress or state legislatures may seek to increase these taxes and fees that relate specifically to the coal industry. We cannot predict further developments, and such increases could have a material adverse effect on our results of operations, financial position, and cash flows.

New tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows. In response to the tariffs imposed by the United States, the European Union, Canada, Mexico and China have imposed tariffs on United States goods and services. The new tariffs, along with any additional tariffs or trade restrictions that may be implemented by the United States or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors for thermal coal, limits on trade with the United States or other potentially adverse economic outcomes. While tariffs and other retaliatory trade measures imposed by other countries on United States goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position and cash flows and could reduce our revenues and cash available for distribution.

Changes in consumption patterns by utilities regarding the use of coal, including plans by utilities to shut down or move away from coal-fired generation, have affected our ability to sell the coal we produce.

The domestic electric utility industry accounts for the vast majority of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled generation has the potential to displace a significant amount of coal-fired electric power generation in the near term, particularly from older, less efficient coal-fired powered generators.

Future environmental regulation of GHG emissions also could accelerate the use by utilities of fuels other than coal. In addition, federal and state mandates for increased use of electricity derived from renewable energy sources could affect demand for coal. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the United States.  A decrease in coal consumption by the domestic electric utility industry could adversely affect the demand for or the price of coal, which could negatively impact our results of operations and reduce our cash from operations.

Other factors, such as efficiency improvements associated with technologies powered by electricity have slowed electricity demand growth and could contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could be caused by a worsening of current economic conditions or a prolonged economic recession, could have a material adverse effect on the demand for coal and our business over the long term.

Extensive environmental laws and regulations affect coal consumers and have corresponding effects on the demand for coal as a fuel source.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from coal-fired electric power plants, which are the ultimate consumers of much of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations could require further emission reductions and associated emission control expenditures. These laws and regulations could affect demand and prices for coal. There is also continuing pressure on federal and state regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants. Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the U.S.

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

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere. Concerns about the environmental impacts of such emissions have resulted in a series of regulatory, political, litigation, and financial risks for our business. Global climate issues continue to attract public and scientific attention. Most scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere could produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods, and other climatic events.   Increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions due to fossil fuels.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain sources in the United States, or constrain the emissions of power plants (though such emissions restraints have been subject to challenge.) 

Separately, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined emissions reduction targets.  These commitments could further reduce demand and prices for fossil fuels.  Although the United States had withdrawn from the Paris Agreement, following President Biden’s executive order in January 2021, the United States rejoined the Agreement and, in April 2021, established a goal of reducing economy-wide net GHG emissions 50-52% below levels by 2030. Additionally, at COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At COP27 in Sharm El-Sheik in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase out of inefficient fossil fuel subsidies. The United States also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity natural gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future.   The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects upon us and our operators' operations.

Governmental, scientific, and public concern over climate change has also resulted in increased political risks, including certain climate-related pledges made by certain candidates now in political office. In January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across governmental agencies and economic sectors. Other actions that may be pursued include restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities or the promulgation of a carbon tax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories, regional GHG cap and trade programs, or the establishment of renewable energy requirements for utilities. Depending on the particular program, we or our customers could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Litigation risks are also increasing. 

Apart from governmental regulation, there are also increasing financial risks for fossil-fuel producers as stakeholders of fossil-fuel energy companies may elect in the future to shift some or all of their support into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil-fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero ("GFANZ") announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil-fuel sector. In late 2020, the Federal Reserve announced it had joined the Network for Greening the Financial System ("NGFS"), a consortium of financial regulators focused on addressing climate-related risks in the financial sector, and, in September 2022, announced that six of the U.S.' largest banks will participate in a pilot climate scenario analysis to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve released its pilot exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks' portfolio.   Although we cannot predict the effects of these actions, such limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect our coal mining operations.

The adoption and implementation of new or more stringent international, federal, or state legislation, regulations, or other regulatory initiatives that impose more stringent standards for GHG emissions from fossil-fuel companies could result in increased costs of compliance or costs of consuming, and thereby reduce demand for coal, which could reduce the profitability of our interests. Additionally, political, litigation, and financial risks could result in either us restricting or canceling mining activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences for non-fossil-fuel sources, including alternative energy sources, could cause prices and sales of our coal to materially decline and could cause our costs to increase and adversely affect our revenues and results of operations.

Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns that could adversely impact our operations. Such physical risks may result in damage to our facilities or otherwise adversely impact operations which could decrease our production. We may not have insurance to cover these risks and the consequences for our operations could have a negative impact on the costs and revenues from operations.

We or our customers could be subject to related to the alleged effects of climate change.

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by state and local governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, and oil & gas companies alleging that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the U.S. Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Separately, litigation has been brought against certain fossil-fuel companies alleging that they have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or consumers. We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

Litigation resulting from disputes with our customers could result in substantial costs, liabilities, and loss of revenues.

From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract. Disputes could occur in the future, and we may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition and results of operations.

Our profitability could decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.

Our mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability. These conditions and events include, among others:

These conditions have the potential to significantly impact our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.

Our inability to obtain commercial insurance at acceptable rates or our failure to adequately reserve for self-insured exposures could increase our expenses and have a negative impact on our business.

We believe that commercial insurance coverage is prudent in certain areas of our business for risk management. Insurance costs could increase substantially in the future and could be affected by natural disasters, fear of terrorism, financial irregularities, cybersecurity breaches and other fraud at publicly-traded companies, intervention by the government, an increase in the number of claims received by the carriers, and a decrease in the number of insurance carriers. In addition, the carriers with which we hold our policies could go out of business or be otherwise unable to fulfill their contractual obligations or could disagree with our interpretation of the coverage or the amounts owed. In addition, for certain types or levels of risk, such as risks associated with certain natural disasters or terrorist attacks, we may determine that we cannot obtain commercial insurance at acceptable rates, if at all. Therefore, we may choose to forego or limit our purchase of relevant commercial insurance, choosing instead to self-insure one or more types or levels of risks. If we suffer a substantial loss that is not covered by commercial insurance or our self-insurance reserves, the loss and related expenses could harm our business and operating results. Also, exposures exist for which no insurance may be available and for which we have not reserved.  In addition, environmental activists could try to hamper fossil-fuel companies by other means including pressuring insurance and surety companies into restricting access to certain needed coverages.

Our mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.

We are subject to numerous federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations. Complying with these laws and regulations could be costly and time-consuming and could delay commencement or continuation of exploration or production operations. The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations could occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers’ use of coal. Federal and state laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations. Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards. Implementing and complying with these laws and regulations has increased and will continue to increase our operational expense and have an adverse effect on our results of operation and financial position.

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

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct our operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability.

The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits. In addition, the EPA previously exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia. The EPA’s action was ultimately upheld by a federal court. As a result of these developments, we may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position.

In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process, or even an inability to obtain permits, permit modifications or permit renewals necessary for our operations.

Inflation could result in higher costs and decreased profitability.

The United States, European Union and other large economies have recently experienced inflation at a rate significantly higher than recent years. Current and future inflationary effects may be driven by, among other things, governmental stimulus and monetary policies, supply chain disruptions and geopolitical instability, including the ongoing military conflict between Ukraine and Russia. This recent inflation has resulted in rising prices, including increases in freight rates, prices for energy and other costs, and has adversely impacted us and may further impact us negatively in the future. Sustained inflation could result in higher costs for transportation, energy, materials, supplies and labor. Our efforts to recover inflation-based cost increases from our customers may be hampered as a result of the structure of our contracts and competitive pressures.  Accordingly, substantial inflation may have an adverse impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the U.S., which could increase our cost of debt borrowing in the future.

Increases in interest rates could adversely affect our business.

The Federal Reserve raised the federal funds interest rate throughout 2022 in its effort to take action against domestic inflation, and is expected to continue to raise these rates in 2023. We have exposure to these past increases in interest rates, and may be affected further in the future. Based on our current variable debt level of $85.2 million as of December 31, 2022, comprised of funds drawn on our outstanding bank debt, an increase of one percentage point in the interest rate will result in an increase in annual interest expense of slightly less than $1 million. Any indebtedness we incur in the future may also expose us to increased interest rates, whether as a result of higher fixed rates at the time such a new facility is entered into or because such new indebtedness accrues interest at a variable rate. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or by impairing our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers. Our transportation providers could face difficulties in the future that could impair our ability to supply coal to our customers, resulting in decreased revenues. If there are disruptions of the transportation services provided by our primary rail carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S. Historically, high coal transportation rates from the western coal-producing areas into certain eastern markets limited the use of western coal in those markets. Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers. In the event of further reductions in transportation costs from western coal-producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on our business, financial condition and results of operations.

States in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.

Political or financial instability, currency fluctuations, the outbreak of pandemics or other illnesses (such as the COVID- 19 pandemic), labor unrest, transport capacity and costs, port security, weather conditions, natural disasters, or other events that could alter or suspend our operations, slow or disrupt port activities, or affect foreign trade are beyond our control and could materially disrupt our ability to participate in the export market for coal sales, which could adversely affect our sales and our results of operations.

We may not be able to successfully grow through future acquisitions.

We have expanded our operations by adding and developing mines and coal reserves in existing, adjacent and neighboring properties, including through our recent acquisition of Merom. We continually seek to expand our operations and coal reserves. Our future growth could be limited if we are unable to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown. Moreover, any acquisition could be dilutive to earnings. Our ability to make acquisitions in the future could require significant amounts of financing that may not be available to us under acceptable terms and may be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline, and we could experience a material adverse effect on our business, financial condition, or results of operations. Expansion and acquisition transactions involve various inherent risks, including:

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

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

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

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

The estimates of our coal reserves maycould vary substantially from actual amounts of coal we are able to recover economically. All of the reserves presented in this Annual Report on Form 10-K constitute proven and probable reserves. There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which maycould vary considerably from actual results. These factors and assumptions relate to:

For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on the risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Any inaccuracy in the estimates of our reserves could result in higher than expected costs and decreased profitability.

Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the U.S., which could affect the mining operations and cost structures of these areas.

The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those characteristicscharacteristic of the depleting mines. In addition, permitting, licensing and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines.

Unexpected increases in raw material costs could significantly impair our operating profitability.

Our coal mining operations are affected by commodity prices. We use significant amounts of steel, petroleum products, and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room-and-pillar method of mining. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and maycould change unexpectedly. Inflationary pressures have and could continue to lead to price increases affecting many of the components of our operating expenses such as fuel, steel, and maintenance expense.

There maycould be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability. In March, 2018, President Trump announced that his administration would be assessing tariffs on steel imports which could increase our costs significantly.

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.

Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.

In past years, members of Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed, but the eliminationElimination of those provisions would negatively impact our financial statements orand results of operations.

Risks RelatedA shortage of skilled labor may make it difficult for us to Our Indebtednessmaintain labor productivity and Liquidity

If we are unable to comply with the covenants contained in our credit agreement, the lenderscompetitive costs and could declare all amounts outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and operations.

As disclosed in Note 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.

profitability.

Our indebtedness may limit

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

Disruptions in supply chains could significantly impair our operating profitability.

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

Various limitationsWe are dependent upon vendors to supply mining equipment, safety equipment, supplies, and materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demands for their services, we could experience reductions in our debt agreements may reduceproduction or increased production costs, which could lead to reduced profitability and adversely affect our ability to incur additional indebtedness, to engage in some transactions and to capitalize on business opportunities.  Any subsequent refinancingresults of our current indebtedness or any new indebtedness could have similar or greater restrictions.operations.

Risk Related to Possible Future Impairment ChargeInflationary pressures could significantly impair our operating profitability.

Carlisle MineAny future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduce demand for our coal and could adversely affect our results of operations.

In December 2016,The Russian-Ukrainian conflict, and sanctions brought against Russia, have caused significant market disruptions that may lead to increased volatility in the deteriorationprice 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. commodities.

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 reviewextent and duration of the Carlisle Mine assetsmilitary conflict involving Russia and Ukraine, resulting sanctions and future market or supply disruptions in the region are impossible to predict, but could be significant and may have a severe adverse effect on the region. Globally, various governments have banned imports from Russia including commodities such as coal. These events have caused volatility in the aforementioned commodity markets. Although we have not experienced any material adverse effect on our results of December 31, 2017, based on estimated future netoperations, financial condition or cash flows as a result of the war or the resulting volatility, such volatility, may significantly affect prices for our coal or the cost of supplies and determined that no further impairment was necessary; however, ifequipment, as well as the prices of competing sources of energy for our electric power plant customers.

The war, trade and monetary sanctions, as well as any escalation of the conflict and future expectationsdevelopments, could significantly affect worldwide market prices and assumptions change we may incur possible impairmentdemand for our coal and cause turmoil in future periods.the capital markets and generally in the global financial system. Additionally, the geopolitical and macroeconomic consequences of the war and associated sanctions cannot be predicted, but could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for products, causing a reduction in our revenues or an increase in our costs and thereby materially and adversely affecting our results of operations.

Bulldog ReservesThe integration of any expansions or acquisitions that we complete will be subject to substantial risks.

In October 2017,Even if we entered into an agreement to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction,make expansions or acquisitions that we believe 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 thatincrease 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.revenue, any expansion acquisition involves potential risks, including, among other things:

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

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

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%31.7% 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

 

At March 8, 2018,10, 2023, we had 205249 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.”  We estimate we have over 5,000 street name holders.

 

Equity Compensation Plan Information

 

See Note 59 to our consolidated financial statements.

27

Stock Performance

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.  SELECTED FINANCIAL DATA.[RESERVED]

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.

29

ITEM 7.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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 basis 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.  We own

On October 21, 2022, the Company, through its subsidiary Hallador Power Company, LLC, completed its acquisition of the  one Gigawatt ("GW") Merom Generating Station ("Merom") located in Sullivan County, Indiana pursuant to an Asset Purchase Agreement (the "Purchase Agreement") with Hoosier Energy (the "Seller").

As a result of the Merom acquisition, commencing with this Form 10-K, the Company has two reportable segments: coal operations (operated by Sunrise Coal, LLC) and electric operations (operated by Hallador Power Company, LLC).

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. We have reached an agreement for Savoy to redeemmethod, and 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.wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

 

Fiscal year 2022 was a transitional year for Hallador.  The market price for coal approached all-time highs.  We operate two underground mineswere successful in signing 2.2 million tons of new coal sales contracts at an average price of ~$125 per ton in the summer of 2022, of which a small percentage of deliveries were completed in 2022 and onewill continue through 2025 with the majority contracted to be delivered in 2023.  To fulfill these obligations, we invested substantially in 2022 to expand our coal production capacity from ~6 million tons annually to ~7.5 million tons in 2023.

In addition to our acquisition of Merom in Q4 2022 described above, we also expanded our coal production capacity by adding more units of production at our Oaktown Mining Complex, opening a small surface mine in southwestern Indiana. The underground mines, Oaktown 1pit near Freelandville, Indiana ("Freelandville"), and Oaktown 2 are in Oaktown, Indiana, 43 miles south of Terre Haute, Indiana. Themoving our Ace in the Hole production to a small surface mine pit near Petersburg, Indiana ("Prosperity").  Freelandville and Prosperity production began in Q3 2022.  Volumes from these new pits are expected to be higher cost, and our newer workforce and surface pits will require a ramp to reach peak productivity.  We will continue to evaluate the productivity of these mines in connection with market conditions to determine the appropriate operational balance.

30

---

Table of Contents

To help fund our investment in expanded mine production, improve our liquidity, and position us to efficiently operate Merom, we issued $29 million of convertible notes, $10 million in Q2 2022 and $19 million in Q3 2022.  The $10 million of notes issued in Q2 2022 have been converted into the Company's common stock, bringing our outstanding share count to 33.0 million shares as of December 31, 2022. If the additional notes issued in Q3 2022 were to also convert, our outstanding share count would increase to approximately 36.1 million shares, representing an approximate 17% increase in share count.   

Bank debt was reduced during the year by $26.5 million bringing the balance owed at the end of fiscal 2022 to $85.2 million, bringing the Debt to EBITDA covenant under our credit agreement to 2.05X at the end of fiscal 2022. See Note 5 to our consolidated financial statements for additional discussion about our bank debt and related liquidity.

Mining Properties

The following information concerning our mining properties has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021.  These requirements differ from the previously applicable disclosure requirements of SEC Industry Guide 7.  Among other differences, subpart 1300 of Regulation S-K requires us to disclose our mineral (coal) resources, which we have none, in addition to our mineral (coal) reserves, as of the end of our most recently completed fiscal year both in the aggregate and for each of our individually material mining properties.

As used in this Annual Report on Form 10-K, the terms “mineral resources,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K.  Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person (QP) that the mineral resources can be the basis of an economically viable project.  You are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the SEC.

Internal qualified person(s) have estimated the Company’s mineral reserves and mineral resources based on geologic data, coal ownership (control) information, and current and/or proposed operating plans.  Periodic updates occur to mineral reserve and mineral resource estimates attributableto revised mine plans, new exploration data, depletion from coal production, property acquisitions or dispositions, and/or other geologic or mining data.  Sunrise’s estimates of mineral reserves are proven and probable reserves that could be extracted or produced at the time of the reserve determination, economically, legally, and after considering all material modifying factors.  Modifications or updates of the estimates of the Company’s mineral reserves is limited to qualified geologists and mining engineers.  All modifications or updates of the estimates of recoverable coal reserves are documented.  The John T. Boyd Company, a qualified person firm, has assessed the Company’s estimates of mineral reserves and mineral resources and supporting information.  Based upon the review, John T. Boyd Company provided modification to the Company’s estimates of mineral reserves where warranted.

The information that follows is derived, for the most part, from, and in some instances is extracted from, the Oaktown Mining Complex technical report summary (“TRS”) that was filed with our 2021 Annual Report on form 10-K and a subsequent update letter from John T. Boyd Company.  There were no material adjustments to the coal resources and reserves necessitating the filing of an amended or revised TRS.  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 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, 2022:

SUMMARY MINERAL RESERVES AT END OF THE

FISCAL YEAR ENDED DECEMBER 31, 2022

		Mineral Reserves (tons in millions)
		Proven				Probable				Total
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine			36.2				0.5				36.7
Oaktown Fuels No. 2 Mine			28.5				1.1				29.6
Total			64.7				1.6				66.3

31

---

Table of Contents

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:

32

---

Table of Contents

Comprising 118 square miles within the ILB coal-producing region of the mid-western United States, 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 64.7 million tons of clean coal.  The complex is configured to operate up to 7 CM sections, with an annual production target of approximately 7 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 is in Clay City,the process of being upgraded to 1,800 raw tons-per-hour (TPH) from its current 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 30 miles southeastRailroad (INRD) via a rail spur and rail loop that connects the complex with the mainline rail just north of Terre Haute,Oaktown, Indiana. 

Additionally, the Oaktown Complex Coal Preparation Plant can facilitate the loading of trucks for direct transport to select customers, or to our transload facility in Princeton, Indiana serviced by the Norfolk Southern (NS) Railroad.

Sources of electrical power, water, supplies, and materials are readily available.  Electrical power is provided to the mines and facilities by regional utility companies.  Water is supplied by public water services, surface impoundments, or water wells.

Multiple permits are required by federal and state law for underground mining, coal preparation and related facilities, and other incidental activities.  All necessary permits to support current operations are in place or pending approval.  New permits or permit revisions may be necessary from time to time to facilitate future operations.  Given sufficient time and planning, we should be able to secure new permits, as required, to maintain our planned operations within the context of the current regulations.

Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. We also ownhold surety bonds to cover obligations relating to mining and reclamation, road repair, etc. Those obligations are currently estimated at $6.8 million.

33

---

Table of Contents

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

OAKTOWN MINING COMPLEX

Recoverable Coal Reserves as of December 31, 2022 and 2021

		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				12/31/2022				12/31/2021
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine			11,522				6.1				—				100.0				36.2				0.5				36.7				40.5
Oaktown Fuels No. 2 Mine			11,534				5.7				—				100.0				28.5				1.1				29.6				30.9
Total																			64.7				1.6				66.3				71.4

Oaktown Fuels No. 1 Mine located near Carlisle,

The assigned and accessible reserve base for the Oaktown Fuels No. 1 Mine contains 36.7 million tons of recoverable Indiana 36 miles southV seam coal, of Terre Haute.which 36.7 million tons are currently permitted.  The Carlisle reserve is contiguouscontains saleable tons which average heating content of approximately 11,522 Btu per pound with approximately 6.1 pounds of sulfur dioxide per MMBtu on an as-received basis.  Access to the Oaktown 2. The CarlisleFuels No. 1 Mine is developed, but currently idle.via a 90-foot-deep box cut and a 2,200-foot 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 1,Fuels No. 2 Mine

The assigned and accessible reserve base for the Oaktown Fuels No. 2 and Carlisle are one large underground mining complex representing 121Mine contains 29.7 million tons of controlledrecoverable Indiana V seam coal, of which 23.8 million tons are currently permitted.  The reserve contains saleable tons which average heating content of approximately 11,534 Btu per pound with approximately 5.7 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 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) has been constructed for employee and supply ingress/egress closer to the active production faces.

Historical production for our Oaktown Mining Complex during the years ended December 31, 2022, 2021, and 2020 is provided in the following table:

		Annual Saleable Production Tons
		(Million Tons)
Mine/Reserve		2022				2021				2020
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine			3.9				3.5				3.4
Oaktown Fuels No. 2 Mine			2.5				2.1				1.8
Total Oaktown Mining Complex Production			6.4				5.6				5.2

34

---

Table of Contents

Other Properties

The Company holds other recoverable coal reserves with three slopes, one elevator, twoin 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 is scheduled to be moved to our Carlisle and Oaktown wash plants and two rail facilities, located onin early 2023. Reclamation will resume in the CSX railroad.Spring of 2023. We anticipate total capacity forexpect Phase 1 reclamation should be substantially complete by the three mines to be roughly 10.5end of 2023.

Ace in the Hole Mine #2 Reserves (surface) – Unassigned

In 2018, we leased property giving us 1.0 million controlled, saleable tons annually. Additionally, the capacityat a new location 2 miles southwest of our Ace in the Hole mine. Future mine development is .4 million tons annually. Thus, our total mining capacity is 10.9 million tons annually. The addition of our Princeton Rail Loop, expected to come online in the spring of 2018, will also provide us new access to coal markets served by the Norfolk Southern Railway Company.being reviewed along with other opportunities.

 

For 2017, over 67%Prosperity (surface) – Assigned

The Prosperity mine contains approximately 0.3 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 is producing coal and also reclaiming 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. Currently the mine is projected to produce approximately 20,000 tons per month until mid-2024.

Freelandville (surface) – Assigned

Sunrise is a contract miner at the Freelandville East Mine Center Pit, Permit No. S 358. Sunrise has an option through May 31, 2023 to assume the permit. The permit contains approximately 1.7 million tons of salable coal with an additional 0.6 million available. Mining started in the fall of 2022. Once the mine reaches full capacity in March of 2023 the mine is expected to produce approximately 40,000 salable tons per month.

Our Coal Contracts

In 2022, Sunrise sold 6.3 million tons of coal to 14 power plants in five different states across nine different customers.

During 2022, 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 were tosales. During 2021, we derived 95% of our revenue from five customers (10 power plants), with large scrubbed coal-fired power plants ineach of the State of Indiana. Our mines and coal reserves are strategically located in close proximity to our primaryfive 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 majorityrepresenting at least 10% 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.sales.

 

President Trump Promotes Coal

Below isSignificant customers in 2022 include Vectren Corporation, a timelinewholly-owned subsidiary of someCenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC), Alcoa Power Generating, Inc., a subsidiary 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.

30

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, such 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.

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 are subject to different standards when their emissions reach an enforceable limit.

These actions are encouraging and will be important to us and the U.S. energy sector.

Our Coal Contracts

We sell coal to the following customers: Duke EnergyAlcoa Corporation (NYSE:  DUK)AA), Hoosier Energy, an electric cooperative, Indianapolis Power & Light Company (IPL), a wholly-owned subsidiary of The AES Corporation (NYSE: AES), Vectrenand Duke Energy Corporation (NYSE: VVC),DUK).

Of our 2022 sales, 74% were shipped to locations in the State of Indiana.

35

---

Table of Contents

In the summer of 2022, customer coal inventories and Orlando Utility Commission (OUC). In 2018,natural gas (a competitor to coal) inventory levels were lower than normal.  Customers paid near record prices in 2022 to secure limited fuel supply.  We invested in expanding our mining production to meet the demand. As discussed above we have opened the Prosperity and Freelandville surface mines to meet the demand resulting in contracts being signed newraising our estimated average sales contractsprice for 2023 to $58.70 per ton.

		Contracted				Estimated
		tons				price
Year		(millions)*				per ton
2023			7.5			$	58.70
2024 - 2027 (total)			7.3				**
Total			14.8

  ______________________

*     Contracted tons are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.

**   Unpriced or partially priced tons

As of December 31, 2022, we are committed to supplying our customers up to a maximum of 14.8 million tons of coal through 2027 of which 10.8 million tons are priced.

Beginning in 2024, with two plantsthe acquisition of the Merom power plant, we have never shippedthe optionality to before. Onesell up to 3.0 million tons of the new customers is certainly dueour coal directly to the addition of our Princeton Rail Loop on the Norfolk Southern Railroad. The other is to aMerom plant, locatedwhich would be in the Carolinas. We attribute the latteraddition to the trend of ILB coals replacing coals from higher cost eastern basins.

31

The table below reflectscontracted tons to our projected tons. Some ofthird party customers described above.  We anticipate our contracts contain language that allow our customersmines will need 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 17.7 million tons committedproduce at a 7 million-ton 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.

32

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.

33

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

34

��

 

As set forth in our StatementConsolidated Statements of Cash Flows, cash provided by operations was $62$54.2 million and $48.0 million for 2017.  This amount was adequatethe years ended December 31, 2022 and 2021 respectively. Operating cash flow increased primarily due to fundan increase in operating margins at our maintenancecoal mines brought on by the addition of higher priced contracts in the summer of 2022.  Operating margin per ton at our coal mines increased in 2022 to $8.35 per ton from $7.35 per ton in 2021, increasing operating cash flow by $7.6 million.

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 20182023 is $31$69 million, of which $16$35 million is for maintenance capex.  CashOf the $69 million, the budget for coal operations is $34 million and the budget for electric operations is $35 million. 

We paid down debt of $26.5 million in 2022. As of December 31, 2022, our bank debt was $85.2 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 is to convert $35 million of the revolver into a new term loan with a maturity of March 31, 2024 (with principal payments of $10.0 million due by June 30, 2023; $10.0 million by September 30, 2023; $10.0 million by December 31, 2023, and $5.0 million by March 31, 2024), and extend the maturity date of the revolver to May 31, 2024.  The effect of the amendment on our future cash flow is to extend the maturity date of $44.7 million of our outstanding debt as of December 31, 2022 to May 2024. In addition, the amendment reduced the total capacity under the revolver to $85.0 million (previously $120 million).  Subsequent to the amendment, the current portion of our outstanding debt as of December 31, 2022 is $35.5 million.   

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 5to our consolidated financial statements for additional discussion about our bank debt.debt and related liquidity.

36

---

Table of Contents

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$20.8 million, which areincluding $7.2 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$36.9 million to cover ARO.

 

Capital Expenditures (capex)

 

For 2017,the year ended December 31, 2022, our capex was $28.6$54.0 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		$	21.0
Oaktown – investment			22.1
Prosperity mine			3.6
Freelandville mine			2.5
Merom plant			3.7
Other			1.1
Capex per the Consolidated Statements of Cash Flows		$	54.0

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

		2022				2021
OPERATING REVENUES:		$	293,344			$	246,396
EXPENSES:
Operating expenses			236,416				198,442
Depreciation, depletion and amortization			43,612				39,829
Asset impairment			—				1,588
Asset retirement obligations accretion			1,010				1,504
Asset retirement obligations change in estimate			—				(3,510	)
Exploration costs			651				482
General and administrative			7,919				6,069
Total operating expenses			289,608				244,404
INCOME (LOSS) FROM OPERATIONS			3,736				1,992

Operating revenues from coal operations increased 19% over 2021 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 increased our average sales price by over $6 per ton from 2021. We also sold 168,000 additional tons over 2022 at the higher average price due to lower inventories and the higher gas prices.

Operating expenses increased, however, by ~$5 per ton. The addition of the higher cost Freelandville and Prosperity surface mines as well as significant inflationary pressures contributed significantly to the increased costs. We continue to experience significant onboarding of new employees which takes time provide training and gain the experience to reach maximum productivity which is also contributing to higher costs.

 

35

37

---

Table of Contents

 

ResultsDepreciation, depletion, and amortization increased 9% as a significant amount of our assets are depreciated and amortized based on production which increased approximately 13% over 2021.

Changes in asset retirement obligation accretion and change in estimate are a result of a review in 2021 that determined the liabilities we have recorded and the future liabilities were overstated due to a change in estimate when factoring time to reclamation, discount rates used, and inflationary factors used. Our review in 2022 did not result in any significant adjustments.

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

		2022				2021
OPERATING REVENUES:		$	66,316			$	—
EXPENSES:
Operating expenses			29,608				—
Depreciation, depletion and amortization			3,117				—
General and administrative			2,086				—
Total operating expenses			34,811				—
INCOME (LOSS) FROM OPERATIONS			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 a power purchase 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 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 year ended December 31, 2022, we recorded $23.3 million 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 expires in May 2023 and requires 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 will be amortized over the term of the agreement as the contract is fulfilled.  For the year ended December 31, 2022, we recorded $3.6 million in additional operating expense for coal purchased and used and an additional $11.2 million to inventory for coal purchased and unused as a result of amortizing the contract asset. 

38

---

Table of Contents

 

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 includes2022, 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
		2022				2022				2022				2022				Total 2022
SALES AND OPERATING REVENUES:
Coal sales		$	57,010			$	64,161			$	83,562			$	84,643			$	289,376
Electric sales			—				0				—				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

 

36

39

---

Table of Contents

 

		Mar-31				Jun-30				Sep-30				Dec-31
		2021				2021				2021				2021				Total 2021
SALES AND OPERATING REVENUES:
Coal sales		$	45,879			$	54,600			$	79,036			$	64,388			$	243,903
Other revenues			816				1,038				786				1,123				3,763
Total revenue			46,695				55,638				79,822				65,511				247,666
EXPENSES:
Operating expenses			34,009				42,456				67,792				54,583				198,840
Depreciation, depletion and amortization			10,307				9,715				9,842				10,109				39,973
Asset impairment			—				—				—				1,588				1,588
Asset retirement obligations accretion			363				373				380				388				1,504
Asset retirement obligations change in estimate			—				—				—				(3,510	)			(3,510	)
Exploration costs			58				159				96				169				482
General and administrative			2,821				3,383				3,067				5,562				14,833
Total operating expenses			47,558				56,086				81,177				68,889				253,710
LOSS FROM OPERATIONS			(863	)			(448	)			(1,355	)			(3,378	)			(6,044	)
Bank debt and other interest			(2,135	)			(2,307	)			(2,167	)			(1,901	)			(8,510	)
Amortization and swap related interest			237				125				59				41				462
Gain on extinguishment of debt			—				—				10,000				—				10,000
Equity method investment income			—				63				90				211				364
INCOME (LOSS) BEFORE INCOME TAXES			(2,761	)			(2,567	)			6,627				(5,027	)			(3,728	)
INCOME TAX EXPENSE (BENEFIT):
Current			—				—				—				—				—
Deferred			(1,729	)			397				(1,359	)			2,717				26
Total income tax expense (benefit)			(1,729	)			397				(1,359	)			2,717				26
NET INCOME (LOSS)		$	(1,032	)		$	(2,964	)		$	7,986			$	(7,744	)		$	(3,754	)
NET INCOME (LOSS) PER SHARE:
Basic and diluted		$	(0.03	)		$	(0.10	)		$	0.26			$	(0.25	)		$	(0.12	)

40

---

Table of Contents

 

Quarterly coal sales and cost data follow (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 2022				2nd 2022				3rd 2022				4th 2022				T4Qs
Tons produced			1,917				1,647				1,487				1,561				6,612				1,397				1,762				1,663				1,721				6,543
Tons sold			1,555				1,548				1,786				1,685				6,574				1,377				1,595				1,705				1,664				6,341
Coal sales		$	62,555			$	62,829			$	73,896			$	68,922			$	268,202			$	57,010			$	64,161			$	83,563			$	84,641			$	289,375
Average price/ton		$	40.23			$	40.59			$	41.38			$	40.90			$	40.80
Average price per ton																						$	41.40			$	40.23			$	49.01			$	50.87			$	45.64
Wash plant recovery in %			71	%			69	%			70	%			68	%							67	%			71	%			69	%			68	%
Operating costs		$	39,692			$	44,079			$	54,354			$	52,025			$	190,150			$	54,443			$	50,776			$	63,876			$	67,319			$	236,414
Average cost/ton		$	25.53			$	28.47			$	30.43			$	30.88			$	28.92
Average cost per ton																						$	39.54			$	31.83			$	37.46			$	40.46			$	37.28
Margin		$	22,863			$	18,750			$	19,542			$	16,897			$	78,052			$	2,567			$	13,385			$	19,687			$	17,322			$	52,961
Margin/ton		$	14.70			$	12.11			$	10.94			$	10.03			$	11.87
Margin per ton																						$	1.86			$	8.39			$	11.55			$	10.41			$	8.35
Capex		$	5,144			$	6,711			$	9,473			$	7,294			$	28,622			$	9,082			$	13,821			$	15,096			$	12,368			$	50,367
Maintenance capex		$	2,887			$	3,032			$	2,961			$	2,520			$	11,400			$	4,481			$	7,600			$	6,625			$	5,748			$	24,454
Maintenance capex/ton		$	0.54			$	4.25			$	2.52			$	1.50			$	1.73
Maintenance capex per ton																						$	3.25			$	4.76			$	3.89			$	3.45			$	3.86

  

		1st 2016				2nd 2016				3rd 2016				4th 2016				T4Qs
All Mines																						1st 2021				2nd 2021				3rd 2021				4th 2021				T4Qs
Tons produced			1,524				1,448				1,501				1,640				6,113				1,592				1,292				1,440				1,447				5,771
Tons sold			1,629				1,464				1,485				1,739				6,317				1,174				1,403				2,042				1,554				6,173
Coal sales		$	75,795			$	66,274			$	65,360			$	71,495			$	278,924			$	45,879			$	54,600			$	79,036			$	64,388			$	243,903
Average price/ton		$	46.53			$	45.27			$	44.01			$	41.11			$	44.15
Average price per ton																						$	39.08			$	38.92			$	38.71			$	41.43			$	39.51
Wash plant recovery in %			65	%			63	%			68	%			67	%							74	%			69	%			73	%			70	%
Operating costs		$	49,777			$	45,397			$	46,940			$	50,663			$	192,777			$	33,907			$	42,364			$	67,694			$	54,583			$	198,548
Average cost/ton		$	30.56			$	31.01			$	31.61			$	29.13			$	30.52
Average cost per ton																						$	28.88			$	30.20			$	33.15			$	35.12			$	32.16
Margin		$	26,018			$	20,877			$	18,420			$	20,832			$	86,147			$	11,972			$	12,236			$	11,342			$	9,805			$	45,355
Margin/ton		$	15.97			$	14.26			$	12.40			$	11.98			$	13.64
Margin per ton																						$	10.20			$	8.72			$	5.55			$	6.31			$	7.35
Capex		$	6,053			$	1,822			$	3,935			$	8,022			$	19,832			$	5,720			$	5,117			$	7,238			$	9,975			$	28,050
Maintenance capex		$	2,984			$	904			$	1,709			$	5,301			$	10,898			$	2,343			$	1,049			$	2,324			$	3,302			$	9,018
Maintenance capex/ton		$	1.83			$	0.62			$	1.15			$	3.05			$	1.73
Maintenance capex per ton																						$	2.00			$	0.75			$	1.14			$	2.12			$	1.46

 

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.

38

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,asset retirement obligation liabilities, our deferred tax accounts, our valuation of inventory, our 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.

We account for business combinations using  The process of estimating reserves is complex, requiring significant judgment in the purchase method of accounting. The purchase method requires us to determine the fair valueevaluation of all acquired assets, including identifiable intangible assetsavailable geological, geophysical, engineering and all assumed liabilities.economic data.  The total cost of acquisitions is allocatedreserve 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 underlying identifiable net assets, based on their respective estimated fair values. Determiningreserves estimates from 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.prior year were nominal. 

 

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 Ace in the Hole, 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

---

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 exposure to price riskaccount for supplies that are used directlybusiness acquisitions as either asset acquisitions or indirectlybusiness 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 normal coursetransaction to each of coal productionthe acquired assets based upon their relative fair value.  Fair value in many instances involves estimates based on third-party valuations, such as steel, electricity 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-hedgesappraisals, or internal valuations based on discounted cash flow analyses or other derivatives relatedvaluation techniques. Those estimates are subject to these risks. The Trump administration recently announced that they would like to assess tariffs on steel importsa high degree of uncertainty, thus we typically will retain professionals in the future which would addrelevant industries of the acquiree to this risk.assist us with our analysis and valuations.  See "Item 8. Financial Statements - Note 16 - Acquisition" for more information on the Merom Acquisition.

 

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 component

42

---

Table of the interest rate to achieve an effective fixed rate of no greater than 5% on the original term loan balance and on $100 million of the revolver. Quarterly, we mark-to-market the value of the swaps. For 2017, the change in value was $723,000 and not considered material. As short-term interest rates rise (especially the two-year U.S. treasury note) the value of the swap increases and as they fall the value decreases.

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.

40

Contents

 

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

  

Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)	44
Report of Independent Registered Public Accounting Firm	42
Consolidated Balance Sheets	44
Consolidated Statements of Comprehensive Income (PCAOB ID Number 166)	45
Consolidated Balance Sheets	47
Consolidated Statements of Operations	48
Consolidated Statements of Cash Flows	49
Consolidated Statement of Cash FlowsStockholders’ Equity	4651
Consolidated Statement of Stockholders' Equity	47
Notes to Consolidated Financial Statements	4852

  

41

  

43

---

Table of Contents

 

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 sheetssheet of Hallador Energy Company (a Colorado corporation) and subsidiaries (the "Company"“Company”) as of December 31, 2017 and 2016, and2022, the related consolidated statements of income, comprehensive income, stockholders' equity, andoperations, cash flows and stockholders’ equity for eachthe year in the three-year period ended December 31, 2017,2022, and the related notes (collectively referred to as the "consolidated“financial statements”). In our opinion, the financial statements"). statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022, and the results of its operations and its cash flows for the year ended December 31, 2022, in conformity with accounting principles generally accepted in the United States of America.

We also have also audited, in accordance with the Company'sstandards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017,2022, based on the criteria established in the 2013 Internal Control - —Integrated Framework: (2013)Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"(“COSO”)., and our report dated March 16, 2023 expressed an unqualified opinion.

 

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our 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 the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.

Critical audit matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) 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 statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Accounting for and valuation of the Merom one gigawatt power plant

As described further in Note 16 to the financial statements, on October 21, 2022, the Company completed the purchase of the Merom one gigawatt power plant located on 800 acres in Sullivan County, Indiana, along with equipment and machinery, materials inventory, a coal ash landfill; and coal inventory (collectively, the Merom Plant Acquisition). The consideration exchanged for the Merom Plant Acquisition was $181.1 million, comprised of $2.9 million in direct transaction costs, $11.0 million future capacity reductions, $17.0 million coal inventory on hand, and certain contracts entered into with the seller at the time of closing as consideration consisting of a power purchase agreement and a coal purchase agreement. The acquisition date fair values of the power purchase and coal purchase agreements were a $184.5 million liability and a $34.3 million asset, respectively.  The consideration exchanged in an asset acquisition is allocated among the individual components of assets acquired based upon their relative fair values.  We identified the accounting for and valuation of the power plant as a critical audit matter.

44

---

Table of Contents

The principal considerations for our determination that the accounting for and valuation of the power plant is a critical audit matter are that (1) the transaction requires the appropriate application of complex accounting authoritative guidance from FASB’s Accounting Standards Codification (“ASC”), (2) significant judgment is used by management when determining the relative fair value of the assets acquired and the fair value of consideration exchanged, (3) there is a high degree of auditor judgment and subjectivity in performing procedures and evaluating management’s significant accounting and valuation assumptions, and (4) the audit effort involved the use of professionals with specialized skill and knowledge.

Our audit procedures related to the accounting for and the valuation of the power plant included the following, among others:

●

We tested the design and operating effectiveness of the controls over the Company’s acquisition and valuation process, including application of the appropriate accounting literature and testing controls over management’s review of the specialists’ calculations and significant assumptions and the completeness and accuracy of the underlying data.

●

With the assistance of our valuation specialists, we evaluated the discounted cash flow valuation methods used to determine the fair value of the power purchase agreement, coal purchase agreement and power plant for reasonableness by testing management’s computations within an acceptable tolerance range.

●

We tested the reasonableness of forecasted revenues and expenses, as well as the discount rate applied to the present value of the estimated future cash flows with the assistance of our valuation specialists.

●

We assessed the appropriate interpretation and application used by management of the FASB’s ASC including ASC 805, Business Combinations, and ASC 820, Fair Value Measurements.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2022.

Tulsa, Oklahoma

March 16, 2023

45

---

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors of Hallador Energy Company

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheet of Hallador Energy Company (the “Company”) as of December 31, 2021, the related consolidated statements of operations, cash flows, and stockholders' equity for the year then ended, and the related notes (collectively referred to as the “financial statements”). 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, 2017 and 2016,2021, and the results of its operations and its cash flows for eachthe year in the three-year periodthen ended, December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework: (2013) issued by COSO.

 

BASIS FOR OPINIONSBasis for Opinion

 

The Company's management is responsible for these consolidated financial statements, 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 Report on Internal Control over Financial Reporting.statements. 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.audit. 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 auditsaudit 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 effectivefraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit we are required to obtain an understanding of internal control over financial reporting was maintained in all material respects.but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

 

Our audits of the consolidated financial statementsaudit 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 auditsaudit 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 provideaudit provides a reasonable basis for our opinions.opinion.

42

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 consolidated 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets 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.

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/ EKS&H LLLP
March 12, 2018
Denver, Colorado

 

We have served as the Company'sCompany’s auditor since 2003.from 2003 through 2022.

 

43

/S/PLANTE & MORAN, PLLC

Denver, Colorado

March 28, 2022, except for Note 18, as to which the date is March 16, 2023.

  

46

---

Table of Contents

PART I - FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Hallador Energy Company

Consolidated Balance Sheets

As of December 31,

(in thousands)

		2022				2021
ASSETS
Current assets:
Cash and cash equivalents		$	3,009			$	2,546
Restricted cash			3,417				3,283
Accounts receivable			29,889				13,584
Inventory			49,796				7,699
Parts and supplies			28,295				10,015
Contract asset - coal purchase agreement			19,567				—
Prepaid expenses			4,546				2,112
Total current assets			138,519				39,239
Property, plant and equipment:
Land and mineral rights			115,595				115,837
Buildings and equipment			534,129				342,782
Mine development			140,108				112,575
Total property, plant and equipment			789,832				571,194
Less - accumulated depreciation, depletion and amortization			(309,370	)			(268,370	)
Total property, plant and equipment, net			480,462				302,824
Investment in Sunrise Energy			3,988				3,545
Other assets			7,585				8,372
Total assets		$	630,554			$	353,980
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS, AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net		$	33,031			$	23,098
Accounts payable and accrued liabilities			82,972				41,528
Deferred revenue			35,485				—
Contract liability - power purchase agreement and capacity payment reduction			88,114				—
Total current liabilities			239,602				64,626
Long-term liabilities:
Bank debt, net			49,713				84,667
Convertible notes payable			10,000				—
Convertible notes payable - related party			9,000				—
Deferred income taxes			4,606				2,850
Asset retirement obligations			17,254				14,025
Contract liability - power purchase agreement			84,096				—
Other			1,259				1,577
Total long-term liabilities			175,928				103,119
Total liabilities			415,530				167,745
Commitments and contingencies
Redeemable noncontrolling interests			—				4,000
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued			—				—
Common stock, $.01 par value, 100,000 shares authorized; 32,983 and 30,785 issued and outstanding, respectively			330				308
Additional paid-in capital			118,788				104,126
Retained earnings			95,906				77,801
Total stockholders’ equity			215,024				182,235
Total liabilities, redeemable noncontrolling interests, and stockholders’ equity		$	630,554			$	353,980

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

47

---

Table of Contents

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

		2022				2021
SALES AND OPERATING REVENUES:
Coal sales		$	289,376			$	243,903
Electric sales			66,252				—
Other revenues			6,363				3,763
Total sales and operating revenues			361,991				247,666
OPERATING EXPENSES:
Operating expenses			266,608				198,840
Depreciation, depletion and amortization			46,875				39,973
Asset impairment			—				1,588
Asset retirement obligations accretion			1,010				1,504
Asset retirement obligations change in estimate			—				(3,510	)
Exploration costs			651				482
General and administrative			16,417				14,833
Total operating expenses			331,561				253,710
INCOME (LOSS) FROM OPERATIONS			30,430				(6,044	)
Interest expense (1)			(11,012	)			(8,048	)
Gain on extinguishment of debt			—				10,000
Equity method investment income			443				364
INCOME (LOSS) BEFORE INCOME TAXES			19,861				(3,728	)
INCOME TAX EXPENSE:
Current			—				—
Deferred			1,756				26
Total income tax expense			1,756				26
NET INCOME (LOSS)		$	18,105			$	(3,754	)
NET INCOME (LOSS) PER SHARE:
Basic		$	0.57			$	(0.12	)
Diluted		$	0.55			$	(0.12	)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			32,043				30,614
Diluted			33,649				30,614

See

---

(1) Interest Expense:
Interest on bank debt		$	7,563			$	8,510
Other interest			715				—
Amortization and swap related interest:
Payments on interest rate swap, net of changes in value			(867	)			(3,026	)
Amortization of debt issuance costs			3,601				2,564
Total amortization and swap related interest			2,734				(462	)
Total interest expense		$	11,012			$	8,048

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

 

44

48

---

Table of Contents

 

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

		2022				2021
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	18,105			$	(3,754	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred income taxes			1,756				26
Equity income – Sunrise Energy			(443	)			(364	)
Depreciation, depletion and amortization			46,875				39,973
Asset impairment			—				1,588
Gain on extinguishment of debt			—				(10,000	)
Loss (gain) on sale of assets			(264	)			317
Payments on interest rate swap, net of changes in value			(867	)			(3,026	)
Change in fair value of fuel hedge			—				(297	)
Amortization of debt issuance costs			3,601				2,564
Asset retirement obligations accretion			1,010				1,504
Asset retirement obligations change in estimate			—				(3,510	)
Cash paid on asset retirement obligation reclamation			(3,162	)			—
Stock-based compensation			1,269				1,004
Provision for loss on customer contracts			159				—
Amortization of contract asset and contract liabilities			(19,731	)			—
Change in current assets and liabilities:
Accounts receivable			(16,305	)			830
Inventory			(25,863	)			16,964
Parts and supplies			(6,271	)			(1,112	)
Prepaid expenses			(5,941	)			(5,215	)
Accounts payable and accrued liabilities			24,037				10,844
Deferred revenue			35,485				—
Other			719				(362	)
Net cash provided by operating activities		$	54,169			$	47,974

  

49

---

Table of Contents

 

*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

		2022				2021
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		$	(54,020	)		$	(28,050	)
Proceeds from sale of equipment			655				525
Net cash used in investing activities			(53,365	)			(27,525	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt			(78,225	)			(46,249	)
Borrowings of bank debt			51,700				20,250
Issuance of convertible notes payable			11,000				—
Issuance of related party convertible notes payable			18,000				—
Debt issuance costs			(2,097	)			(418	)
Distributions to redeemable noncontrolling interests			(585	)			—
Taxes paid on vesting of RSUs			—				(274	)
Net cash used in financing activities			(207	)			(26,691	)
Increase (decrease) in cash, cash equivalents, and restricted cash			597				(6,242	)
Cash, cash equivalents, and restricted cash, beginning of year			5,829				12,071
Cash, cash equivalents, and restricted cash, end of year		$	6,426			$	5,829
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents		$	3,009			$	2,546
Restricted cash			3,417				3,283
		$	6,426			$	5,829
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest		$	8,123			$	8,720
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expenses		$	3,440			$	8,520

  

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

50

---

Table of Contents

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, 2020																											30,610			$	306			$	103,399			$	81,555			$	185,260
Stock-based compensation			14				-				3,134				-				-				3,134				—				—				1,004				—				1,004
Stock issued on vesting of RSUs			411				3				-				-				-				3				296				3				(3	)			—				—
Taxes paid on vesting of RSUs			(136	)			-				(1,029	)			-				-				(1,029	)			(121	)			(1	)			(274	)			—				(275	)
Dividends			-				-				-				(4,794	)			-				(4,794	)
Net loss																											—				—				—				(3,754	)			(3,754	)
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			-				-				-				20,132				-				20,132				—				—				—				18,105				18,105
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, 2022																											32,983				330				118,788				95,906				215,024

 

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

 

See accompanying notes.

47

51

---

Table of Contents

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2022 AND 2021

(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 known as, “we, us, or our”) and its 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 own

Segment Information

As the result of Hallador Power’s acquisition of the Merom 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 16, 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 exploration company with operations in the same vicinity as the Carlisle Mine. We also own 30.6% equity interest in Savoy Energy, L.P., a private oil and gas company that has 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.  Prior periods have been recast to finalize in mid-March 2018. Our net after commissions paid will be $7.5 million.reflect Corporate and Other apart from Coal Operations which previously were aggregated into a single reportable segment.

The Coal Operations reportable segment includes currently operating mining complexes Oaktown 1 and 2 underground mines, Prosperity surface mine, Freelandville surface mine, and Carlisle wash plant.

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

ReclassificationAccounts Receivable

 

To maintain consistencyThe timing of revenue recognition, billings and comparability, certain amountscash 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 financial statementsresolution of price variability, such as coal quality thresholds. Payments are generally received within thirty days of invoicing.  Historically, credit losses have been reclassified to conform to current year presentation.insignificant. No charges for credit losses were recognized during the years ended December 31,2022 or 2021.

 

InventoriesInventory and Parts and Supplies

 

CoalInventory 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 is the result of a coal purchase agreement with Hoosier whereby we are purchasing coal from Hoosier through May 31, 2023 at fixed prices which were below market prices at the date we entered into the agreement.  This agreement was entered into as consideration in the Merom Acquisition.  The asset is being amortized to inventory as coal is purchased over the term of the agreement as the contract is fulfilled.  During the year ended December 31, 2022, $14.7 million was amortized, of which $3.6 million was recognized in operating expenses on the consolidated statement of operations.  The Coal Purchase Agreement term is from October 22, 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.

52

---

Table of Contents

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 are 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.

 

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.

 

48

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 using credit-adjusted risk-free discount rates ranging from 5.0% to 10%. to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by our 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, 2021 was a result of a change in timing of expected reclamation of the Ace in the Hole Mine, Carlisle Mine, and Prosperity Mine and updates to inflation rates from when the liabilities were first projected. In the event we are not able to perform reclamation, we have surety bonds totaling $25$36.9 million to cover ARO.

 

53

---

Table of Contents

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

										Year Ended December 31,
		2017				2016				2022				2021
Balance, beginning of year		$	13,260			$	12,231			$	14,125			$	16,277
Merom acquisition											7,230				—
Freelandville addition											1,631
Accretion			861				1,029				1,010				1,504
Revisions			(112	)			-
Change in estimate											—				(3,510	)
Payments			(203	)			-				(3,162	)			(146	)
Balance, end of year			13,806				13,260				20,834				14,125
Less current portion			(300	)			(145	)			(3,580	)			(100	)
Long-term balance, end of year		$	13,506			$	13,115			$	17,254			$	14,025

  

Contract Liabilities - Power Purchase Agreement and Capacity Payment Reduction

Contract Liabilities - Power Purchase Agreement and Capacity Payment Reduction is the result of a power purchase agreement with Hoosier whereby we are selling power to Hoosier through 2025 at fixed prices which were below market prices at the date we entered into the agreement.  We also agreed to a reduction in future capacity payments as part of 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 year ended December 31, 2022, amortization of the power purchase agreement contract liability totaled $23.3 million.  The Power Purchase Agreement term is from October 22, 2022 to December 31, 2025.  The Capacity Payment Reductions occur on May 31, 2023 and November 30, 2023 in the amount of $7.5 million each.

Interest Rate Swaps

The Company generally utilizes derivative instruments to manage exposures to interest rate risk on long-term debt. The Company enters 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 are 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, 2022, the Company is not a party to any interest rate swaps.

Commitments and Contingencies

From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business.  The Company has 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 the Company’s business, financial position, results of operations or liquidity.

Statement of Cash Flows

 

Cash and cash equivalents include investments with maturities when purchased of three months or less.

 

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.

 

54

---

Table of Contents

Net Income (Loss) per Share

 

Basic net incomeearnings (loss) per share is(“EPS”) are computed on the basis ofby dividing net earnings (loss) 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 the Company were vested and convertible debt. The Company applied 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.

 

49

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 measurement of impairments, and (vi) estimates used in the calculation of our asset retirement obligations.

 

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, 2017,2022, we are committed to supplying our customers up to a maximum of 26.114.8 million tons of coal through 20242027 of which 13.510.8 million tons are priced.

 

For 2017, we derived 92% of our coal sales from five customers, each representing at least 10% of our coal sales. 83% of our accounts receivable were from four of these customers, each representing more than 10% of the December 31, 2017 balance.

For 2016,2022, we derived 90% of our coal sales from five customers, each representing at least 10% of our coal sales. 78%86% of our coal operations accounts receivable werewas from four of these customers, each representing more than 10% of the December 31, 20162022 balance.  100% of our electric sales and accounts receivable were with one customer.

 

For 2015,2021, we derived 82%95% of our coal sales from four customers, each representing at least 10% of our coal sales. 99% of our coal operations accounts receivable was from five customers, each representing more than 10% of the December 31, 2021 balance.

 

WeFor 2022, we derived 100% of our electric generation and capacity revenue from Hoosier.  As of  December 31, 2022,  we are paid every twocommitted to four weekssupply 100% of the plants energy and do not expect any credit losses.capacity to Hoosier through May 31, 2023, reducing commitments to 22% of energy output and 32% of its capacity from June 1, 2023 through December 31, 2025.

 

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.

50

New Accounting Standards Issued and Adopted(2)    LONG-LIVED ASSET IMPAIRMENTS

 

In July 2015,Long-lived assets are reviewed for impairment whenever events or changes in circumstance indicate that the FASB issued ASU 2015-11, carrying amount of the assets may not be recoverable.

Prosperity Mine

We recorded an impairment of $1.6 million as of December 31, 2021 on assets consisting of the wash plant and rail facilities at the Prosperity Mine.  The wash plant was torn down and the remaining rail was pulled up in the fourth quarter of 2021.

(3)     INVENTORY

Inventory (Topic 330): Simplifying the Measurement of Inventory (ASU 2015-11).  ASU 2015-11 simplifies the subsequent measurement of inventory.  It replaces the current lower of cost or market test with theis 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, 2022, and December 31, 2021, coal inventory includes NRV adjustments of completion, disposal,$4.9 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.$3.8 million, respectively.

 

55

---

Table of Contents

New Accounting Standards Issued and Not Yet Adopted(4)     OTHER LONG-TERM ASSETS (IN THOUSANDS)

		December 31,
		2022				2021
Advanced coal royalties		$	5,967			$	6,678
Other			1,618				1,694
Total other assets		$	7,585			$	8,372

(5)     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.

51

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.

52

(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 our lenders for theunder our credit agreement.  The primary purpose of increasing liquiditythe amendment was to return the allowable leverage ratio and maintaining compliancedebt service coverage ratio to their 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 is to convert $35 million of the outstanding balance on the revolver into a new term loan with a maturity of March 31, 2024 and extend the maturity date of the agreementrevolver to May 31, 2024.  The amendment also reduced the total capacity under the revolver to $85 million and waives the maximum annual capital expenditure covenant for 2022 and increases 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 $17.0 million under the revolver.

The interest rate per the amendment will transition from LIBOR to SOFR based pricing with ranges from SOFR plus 4.00% to SOFR plus 5.00%, depending on the Company’s leverage ratio. The Company expects the interest rate to be SOFR plus 4.00% for the majority of  2023.

Bank debt was reduced by $26.5 million during the year ended December 31, 2022.  Prior to the latest 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 in August 2019.  March 2023.  The revolver was reduced from $250to mature in September 2023. Under the provision of the latest amendment, bank debt is comprised of term debt ($40.5 million to $200as of December 31, 2022) and a $85 million revolver ($44.7 million borrowed as of December 31, 2022). The term debt requires payment of $5.5 million in March 2023 and the $175$10 million term loan remained the same. each quarter thereafter in 2023 and $5.0 million by March 31, 2024.  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, 2022, we had additional borrowing capacity of $69$29.1 million under the revolver and total liquidity of $85$32.1 million.  Our additional borrowing capacity is net of $11.2 million in outstanding letters of credit as of December 31, 2022 that were required to maintain surety bonds.  Liquidity consists of our additional borrowing capacity and cash and cash equivalents.

 

BankWe entered new contracts during the three months ended June 30, 2022, with significantly higher prices, that began shipping during the three months ended September 30, 2022.  These contracts substantially increased our cash flow for the remainder of 2022 and 2023.

Fees

Unamortized bank fees and other costs incurred in connection with the initial facility and subsequent amendments totaled $4.0 million as of December 31, 2021. Additional costs incurred with the amendment were $9.1 million, whichMarch 25, 2022, May 20, 2022, and August 5, 2022 amendments totaled $2.1 million.  These costs were deferred and are being amortized over five years. The credit facilitythe term of the loan. Unamortized costs as of December 31, 2022, and December 31, 2021, were $2.5 million and $4.0 million, respectively.

56

---

Table of Contents

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,
		2022				2021
Current bank debt		$	35,500			$	25,725
Less unamortized debt issuance cost			(2,469	)			(2,627	)
Net current portion		$	33,031			$	23,098
Long-term bank debt		$	49,713			$	86,013
Less unamortized debt issuance cost			—				(1,346	)
Net long-term portion		$	49,713			$	84,667
Total bank debt		$	85,213			$	111,738
Less total unamortized debt issuance cost			(2,469	)			(3,973	)
Net bank debt		$	82,744			$	107,765

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 listedexceed the amounts below:

 

Fiscal Periods Ending		Ratio
December 31, 2017 and March 31, 20182022		2.50 to 1.00	4.25	X
June 30, 2018 March 31, 2023, and September 30, 2018each fiscal quarter thereafter			4.00	X
December 31, 20182.25 to 1.00			3.75	X
March 31, 2019 and June 30, 2019			3.50	X

 

The amendedAs of December 31, 2022, our Leverage Ratio of 2.05 was in compliance with the requirements of the credit agreement.

Beginning 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 and2022, our Debt Service Coverage Ratio of 1.49 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 LIBOR plus 2.25%2.75% to LIBOR plus 4%4.00%, depending on our leverage ratio.Leverage Ratio, with a LIBOR floor of 0.50%.  We entered into swap agreements to fix the LIBOR component of the interest rate to achieve an effective fixed rate of ~5%at 2.92% on the originaldeclining term loan balance and on $100$52.7 million of the revolver.  The revolver swap notional value steps down 10% each quarter which commenced on March 31, 2016. At agreements matured in May 2022.  On December 31 2017, these two interest rate swaps had, 2022, we are paying LIBOR plus 4.0% on the outstanding bank debt.

Future Maturities (in thousands):
2023			35,500
2024			49,713
Total		$	85,213

Paycheck Protection Program

As previously reported in the Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2020, we entered into a Paycheck Protection Program Promissory Note and Agreement on April 15, 2020, evidencing an estimated net fair valueunsecured $10 million loan (the “PPP Loan”) under the Paycheck Protection Program (or “PPP”) made through First Financial Bank, N.A., (the "Lender"). The PPP was established under the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and is administered by the U.S. Small Business Administration (the “SBA”).

57

---

Table of $.5 million included in other assets on our consolidated balance sheet. Notional valuesContents

Under the terms of the twoCARES Act, PPP loan recipients can apply for forgiveness. The SBA can grant forgiveness of all, or a portion of, loans made under the PPP if the recipients use the PPP loan proceeds for eligible purposes, including payroll costs, mortgage interest, rate swaps were $96 millionrent or utility costs, and $30 million asmeet other requirements regarding, among other things, the maintenance of December 31, 2017.

At December 31, 2017, we were paying LIBOR at 1.57% plus 3%employment and compensation levels. The Company used the PPP Loan proceeds for a total interest ratequalifying expenses and applied for the forgiveness of 4.57%.

53

New accounting standards adoptedthe PPP Loan in 2016 required that our debt issuance costs be presented as a direct reduction fromaccordance with the related debt rather than as an asset.  Our debt at December 31 is presented below (in thousands):terms of the CARES Act.

		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,July 23, 2021, we received a notification from the U.S. government enacted comprehensive tax legislation commonly referred to asLender that the Tax Cuts and Jobs Act (Tax Act).SBA approved our PPP Loan forgiveness application for the entire PPP Loan balance of $10 million, together with interest accrued thereon. The Tax Act makes broad and complex changes toLender notified us that the U.S. tax code including, but not limited to, (1) bonus depreciation that will allow for full expensing of qualified property; (2) reductionforgiveness payment was received on July 26, 2021.  The forgiveness 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 taxablePPP Loan is recognized as other income.

 

The SEC staff issued SAB 118, which provides guidance on accountingSBA retains the right to review the Company's loan file for a period subsequent to the date the loan is forgiven, with the potential for the tax effectsSBA to pursue legal remedies at its discretion.

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

		December 31,
		2022				2021
Accounts payable		$	62,306			$	27,835
Accrued property taxes			1,917				2,529
Accrued payroll			5,933				2,413
Workers' compensation reserve			3,440				2,560
Group health insurance			2,250				1,800
Fair value of interest rate swaps			—				867
Asset retirement obligation - current portion			3,580				100
Other			3,546				3,424
Total accounts payable and accrued liabilities		$	82,972			$	41,528

(7)   REVENUE

Revenue from Contracts with Customers

We account for a contract with a customer when the parties have approved the contract and are committed to performing their respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and it is probable substantially all of the Tax Act. SAB 118 providesconsideration will be collected. We recognize revenue when we satisfy a measurement periodperformance obligation by transferring control of a good or service to a customer.

Coal operations

Our coal revenue is derived from sales to customers of coal produced at our facilities. Our customers typically purchase coal directly from our mine sites or our rail facility in Princeton, Indiana, where the sale occurs and where title, risk of loss, and control pass to the customer at that should not extend beyond one yearpoint. 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 Tax Act enactment date for companiescontract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the prevailing market price or, in some instances, require us to completenegotiate 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 accountingterms of these contracts vary by customer.

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

58

---

Table of Contents

Electric operations

The Company concluded that the definition of a contract and the criteria in ASC 606,Revenue from Contracts with Customers ("ASC 606"), was met at the time the PPA was executed by the parties, as this is the point at which enforceable rights and obligations were established. Accordingly, the Company concluded that the PPA constitutes a valid contract under ASC 740. In accordance with SAB 118, a company must reflect606.

The Company will recognize revenue daily for the income tax effectsactual capacity made available as part of those aspectsits stand-ready obligation to provide electricity for the contract capacity performance obligation and daily for the actual delivered electricity plus the amortization of the Act for which the accounting under ASC 740 is complete. To the extent thatcontract liability as a company’s accounting for certain income tax effectsresult of the Tax ActAPA with Hoosier, for the Delivered Energy performance obligation.

Disaggregation of Revenue

Revenue is incomplete but it is abledisaggregated by primary geographic markets, as we believe this best depicts how the nature, amount, timing, and uncertainty of our revenue and cash flows are affected by economic factors.

Coal operations

74% and 73% of our coal revenue for the years ended December 31, 2022 and 2021, respectively, was sold to determine a reasonable estimate, it must record a provisional estimatecustomers in the financial statements. If a company cannot determine a provisional estimateState of Indiana with the remainder sold to be includedcustomers in the financial statements, it should continue to apply ASC 740 on the basisFlorida, North Carolina, Georgia, and Alabama.

Electric operations

100% 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 completeelectric revenue for the year ended December 31, 2017. Additional information2022 was sold to Hoosier in the State of Indiana.

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 may affectmeets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the accounting under ASC 740 would include further clarificationtransaction 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 guidancerisk 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 of approximately $593 million, which represent the average fixed prices on howour committed contracts as of December 31, 2022. We expect to recognize approximately 75% of this coal sales revenue in 2023, with the Internal Revenue Service and state taxing authorities will implementremainder recognized thereafter.

We have remaining performance obligations relating to coal sales contracts with price reopeners of approximately $166 million, which represents our estimate of the Tax Act.expected re-opener price on committed contracts as of December 31, 2022. We do not believe potential adjustmentsexpect to recognize all of this coal sales revenue beginning in future periods would materially impact the Company’s financial condition or results of operations.2024.

 

The Tax Act reducescoal tons used to determine the corporate tax rateremaining performance obligations are subject to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 requiresadjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the effectcustomer contract.

Electric operations

The Company concluded that each megawatt hour ("MWh") of delivered energy is capable of being distinct as a change in tax laws or ratescustomer could benefit from each on its own by using/consuming it as a part of its operations.  The Company also concluded that the stand-ready obligation to be recognizedavailable to provide electricity to Hoosier is capable of being distinct as each unit of capacity provides an economic benefit to the date of enactment, we are required to adjust deferred tax assetsholder 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.could be sold by Hoosier.

 

54

59

---

Table of Contents

Hallador 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.

 

In addition to delivered energy, Hallador shall provide a stand-ready obligation to provide electricity, also known as contract capacity. The contract capacity that Hallador shall provide is 917 megawatts ("MW") for contract year 1, and 300 MW for contract years 2-4. Hoosier shall pay Hallador the capacity price of $5.80 per kilowatt month for the contract capacity.

Contract Balances

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

Under the typical payment terms of our contracts with customers, the customer pays us a base price for the coal, increased or decreased for any quality adjustments, electricity, or capacity. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our consolidated balance sheets. As of January 1, 2021, accounts receivable for coal sales billed to customers was $12.8 million. We do not currently have any other contracts in place where we would transfer coal, electricity or capacity in advance of knowing the final price, and thus do not have any other contract assets recorded. Contract liabilities also arise when consideration is received in advance of performance.

(8)     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				2022				2021
Expected amount		$	4,868			$	2,966			$	9,653			$	4,171			$	(783	)
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				391				(767	)
Percentage depletion			(4,128	)			(6,021	)			(2,606	)			(2,081	)			(1,725	)
Valuation allowance															(970	)			3,376
Stock-based compensation			(204	)			(238	)							—				380
Captive insurance			(379	)			(418	)			(419	)
Adjustments to NOL carryforwards			(1,038	)
PPP loan forgiveness															—				(2,100	)
Return to provision adjustments			(205	)											153				1,610
Other			(249	)			72				283				92				35
		$	(19,194	)		$	(4,026	)		$	7,438			$	1,756			$	26

  

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	)

		2022				2021
Deferred tax assets:
Net operating loss		$	26,570			$	32,659
Valuation allowance			(3,681	)			(4,651	)
Stock-based compensation			163				—
Other			471				—
Total deferred tax assets			23,523				28,008
Deferred tax liabilities:
Coal properties			(26,446	)			(30,368	)
Investment in partnerships			(1,480	)			(484	)
Other			(203	)			(6	)
Total deferred tax liabilities			(28,129	)			(30,858	)
Net deferred tax liability		$	(4,606	)		$	(2,850	)

  

60

---

Table of Contents

Our effective tax rate (ETR)("ETR") for 20172022 was (138)%9% compared to (48)%(1%) for 2016 and 27% for 2015.2021. 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 negative2022 and 2021 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, PPP loan forgiveness, return to provision adjustments, 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 3 years as well as projected earnings  into the future, the Company believes that it is more likely than not that the benefit from certain federal and state deferred tax assets will be realized. As such, the Company has released a portion of its valuation allowance in the current year.  Due to federal NOL’s that are limited to 80% utilization to offset future federal tax liabilities reversing the Company continues to have a valuation against a portion of these NOL’s which it believes is not more likely than not to be realized.  In recognition of this, we have provided a valuation allowance of $3.7 million and $4.7 million on the deferred tax assets related to these NOL carryforwards as of December 31, 2022 and 2021, respectively.

The federal NOLs generated in pre-2018 years and remaining of $40.3 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 our 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 numerousand state entities generally remain subject to examination.

examination for three years after filing.  

55

(9)     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, 2017:2022:

 

Total authorized RSUs in Plan approved by shareholders			4,850,000
Stock issued out of the Plan from vested grants			(2,512,4323,265,829	)
Non-vested grants			(944,5001,056,937	)
RSUs available for future issuance			1,393,068527,234

Non-vested grants at December 31, 2020			324,250
Non-vested grants at January 1, 2015			1,042,000
Granted – weighted average share price on grant date was $11.52$2.46			2,000173,000
Vested – weighted average share price on vesting date was $7.42$2.27			(410,500296,250	)
Forfeited			(27,00018,000	)
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			(271,500—	)
Forfeited			(16,0007,500	)
Non-vested grants at December 31, 20162022			733,0001,056,937
Granted – weighted average share price on grant date was $7.98			1,211,500
Vested – weighted average share price on vesting date was $7.22			(990,500	)
Forfeited			(9,500	)
Non-vested grants at December 31, 2017 (1)			944,500

 

RSU Vesting Schedule

Vesting Year		RSUs Vesting
2023			457,721
2024			299,608
2025			299,608

61

(1)

RSU Vesting Schedule

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

---

Table of Contents

Vested shares had a value of  $7.1$0.7 million for 2017, $2.4 million for 2016, and $3.0 million for 20152021, on their vesting dates.   Under our RSU plan, participants are allowed to relinquish shares to pay for their required statutory income taxes.

 

56

The outstanding RSUs have a valuevalue of $6.2$8.1 million based on the March 9, 2018, 1, 2023 closing stock price of $6.53.$7.65.

 

For the years ended December 31, 2017, 2016 2022 and 2015 stock based2021 stock-based compensation was $7.3 million, $2.5$1.3 million and $3.1$1.0 million, respectively. For 2018, based on existing RSUs outstanding, stock-based

As of December 31, 2022, unrecognized stock compensation expense is estimated to be $2.0 million.$5.1 million, and we had 527,234 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

 

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.(10)     EMPLOYEE BENEFITS

 

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

 

		2017				2016				2015				2022				2021
Health benefits, including premiums		$	13,311			$	12,672			$	13,400			$	14,607			$	13,084
401(k) matching			1,892				1,458				2,267				2,549				1,946
Deferred bonus plan			677				588				445				809				698
Total		$	15,880			$	14,718			$	16,112			$	17,965			$	15,728

 

Of the amounts in the above table, $15.5 million, $13.8$17.4 million and $15.2 million for 2017, 2016, and 2015, respectively are recorded in operating costsexpenses for 2022 and expenses2021, respectively with the remainder in SG&A.general and administrative.

 

Our mine employees are also covered by workers’ compensation and such costs for 2017, 20162022 and 20152021, were approximately $2.8 million, $2.3$4.9 million and $4.6$2.9 million, respectively, of which $2.5 million, $2.3 million, and $4.6 million, respectively are recorded in operating costs and expenses with the remainder in SG&A.expenses. 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, our operations are protected from these perils through stop-loss insurance policies. Our maximum annual exposure is limited to $1 million per occurrence with a $4 million aggregate deductible.  Based on discussions and representations from our insurance carrier, we believe that our reserve for our workers’ compensation benefits is adequate.  We have a safety conscious workforce, and based on our experience modifier, our claims are averaging 27% below that of our peers in underground coal mining in the state of Indiana.

 

57

(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.(11)     LEASES

 

We have operating 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 calculated the right-of-use assets and lease liabilities using our secured incremental borrowing rate at the lease commencement date. We currently do not have any finance leases outstanding.

		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” Information related to leases was as follows as of December 31 (in the MD&A section for a discussion of these amounts.thousands): 

 

(8)

Self Insurance

		2022
Operating lease information:
Operating cash outflows from operating leases		$	218
Weighted average remaining lease term in years			1.30
Weighted average discount rate			6.0	%

62

---

Table of Contents

Future minimum lease payments under non-cancellable leases as of December 31, 2022 were as follows (in thousands):

Year		Amount
2023		$	173
2024			60
Total minimum lease payments		$	233
Less imputed interest			(3	)
Total operating lease liability		$	230
As reflected on balance sheet:
Other long-term liabilities		$	230

At December 31, 2022 and 2021, respectively, we had approximately $230 and $424 right-of-use operating lease assets recorded within “buildings and equipment” on the Consolidated Balance Sheet.

(12)     SELF INSURANCE

 

We self-insure our underground mining equipment. Such equipment is allocated among 10seven mining units spread outdispersed over 2210 miles. The historical cost of such equipment is about $258 million.was approximately $280 million and $260 million as of December 31, 2022 and December 31, 2021, respectively.    

  

AsRestricted cash of $3.4 million and $3.3 million as of December 31, 2017,2022, and 2016, restricted cash of $3.8 million and $2.8 million,December 31, 2021, 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.(13)     NET INCOME (LOSS) PER SHARE

 

The following table (in thousands, except per share amounts) sets forth the computation of basic net income (loss) per share:

		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,
		2022				2021
Basic earnings per common share:
Net income (loss) - basic		$	18,105			$	(3,754	)
Weighted average shares outstanding - basic			32,043				30,614
Basic earnings (loss) per common share		$	0.57			$	(0.12	)
The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:
		Year Ended December 31,
		2022				2021
Diluted earnings per common share:
Net income (loss) - basic		$	18,105			$	(3,754	)
Add: Convertible Notes interest expense, net of tax			527				-
Net income (loss) - diluted		$	18,632			$	(3,754	)
Weighted average shares outstanding - basic		$	32,043			$	30,614
Add: Dilutive effects of if converted Convertible Notes			1,398				-
Add: Dilutive effects of Restricted Stock Units			208				-
Weighted average shares outstanding - diluted			33,649				30,614
Diluted net income (loss) per share		$	0.55			$	(0.12	)

  

58

63

---

Table of Contents

  

(14)     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). Our Level 3 instruments are comprised of interest rate swaps. The fair values of our swaps were estimated using discounted cash flow calculations based upon forward interest-rate yield curves.and impairment measurements.  Although we utilize third party-party broker quotes to assess 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. The Company recorded an impairment during Q4 of 2021 which incorporates Level 3 non-recurring fair value measures as further discussed in Note 2.   Certain properties' asset retirement obligation liabilities use Level 3 non-recurring fair value measures as further discussed in Note 1. Lastly, Level 3 fair value measurements were also used in the determination of the fair values of assets acquired, liabilities assumed and considerations exchanged as part of the Merom Acquisition.

 

The following table summarizes our financial assets and liabilities measured on a recurring basis at fair value at December 31, 2017 2022 and 20162021 by respective level of the fair value hierarchy:hierarchy (in thousands):

  

		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

		Level 1				Level 2				Level 3				Total
December 31, 2021
Liabilities:
Interest rate swaps		$	—			$	—			$	867			$	867

 

59

 

The table below highlights the change in fair value of the fuel hedges and interest rate swaps:swaps which are based on a discounted future cash flow model (in thousands):

  

		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

Ending balance, December 31, 2021			867
Settlements			(1,058	)
Unrealized loss			191
Ending balance, December 31, 2022		$	—

  

(11)

Equity Method Investments

(15)     EQUITY METHOD INVESTMENTS

Sunrise Energy, LLC

 

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, 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 our consolidated balance sheets as of December 31, 20172022 and 2016,2021 was $4.0 million and $3.5 million, respectively.

64

---

Table of Contents

(16)     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 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 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 consists of the assumption of the power plant’s closure and post-closure remediation, valued at approximately $7.2 million; no cash will be paid by Hallador 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 is being accounted for as an asset acquisition under ASC 805-50 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) are 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

65

---

Table of Contents

(17)     CONVERTIBLE NOTES

 

On November 3, 2016, Lubar Equity Fund, LLC acquiredMay 2, 2022, and May 20, 2022, we issued senior unsecured convertible notes (the "Notes") to five parties, in the aggregate principal amount of $10 million, with $9 million being issued to related parties affiliated with independent members of our board of directors and the remainder to a 25%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 converted. At any time on or after June 1, 2025, the Company may, at its 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 any accrued but unpaid interest thereon to the redemption date. After receipt of such redemption notice from the Company, 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 the Company no later than 5 days prior to the date fixed for redemption.

In 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 the one holder of the $1 million Note converted it into 231,697 shares of common stock pursuant to the terms of the notes and their related agreements.

On July 29, 2022, we issued $5 million of a 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 period August 18, 2022 through August 17, 2024, the holder has the option to convert the note into shares of the Company's common stock at a conversion price of $6.254.  Beginning August 18, 2025, the Company 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 the Company, the holder may elect to convert the principal balance and accrued interest into the Company's common stock.

On August 8, 2022, we issued $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 29, 2028.  For the period August 18, 2022 through August 17, 2024, the holder has the option to convert the notes into shares of the Company's common stock at a conversion price of $6.254.  Beginning August 8, 2025, the Company 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 the Company, the holder may elect to convert the principal balance and accrued interest into the Company's common stock.

On August 12, 2022, we issued a $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 notes into shares of the Company's common stock at a conversion price of $6.15.  Beginning August 12, 2025, the Company 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 the Company, the holder may elect to convert the principal balance and accrued interest into the Company's common stock.

The funds received from the issuance of the various notes described above in this note 17 were used to provide additional working capital to the Company.  The conversion price and number of shares of the Company’s common stock issuable upon conversion of the above notes are subject to adjustment from time to time for any subdivision or consolidation of the Company’s shares of common stock and other standard dilutive events.

66

---

Table of Contents

(18)     SEGMENTS OF BUSINESS

At December 31, 2022, 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 SavoySunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for $9.5 million in cash. Accordingly,using the equity method and our ownership interest was reduced from 40.8%wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

Year Ended December 31, (in millions)		2022				2021
Operating Revenues
Coal Operations		$	293,344			$	246,396
Electric Operations		$	66,316			$	-
Corporate and Other and Eliminations		$	2,331			$	1,270
Consolidated Operating Revenues		$	361,991			$	247,666
Income (Loss) from Operations
Coal Operations		$	3,736			$	1,992
Electric Operations		$	31,505			$	-
Corporate and Other and Eliminations		$	(4,811	)		$	(8,036	)
Consolidated Income (Loss) from Operations		$	30,430			$	(6,044	)
Depreciation, Depletion and Amortization
Coal Operations		$	43,612			$	39,829
Electric Operations		$	3,117			$	-
Corporate and Other and Eliminations		$	146			$	144
Consolidated Depreciation, Depletion and Amortization		$	46,875			$	39,973
Assets
Coal Operations		$	376,228			$	346,201
Electric Operations		$	266,730			$	-
Corporate and Other and Eliminations		$	(12,404	)		$	7,779
Consolidated Assets		$	630,554			$	353,980
Capital Expenditures
Coal Operations		$	50,367			$	28,050
Electric Operations		$	3,653			$	-
Corporate and Other and Eliminations		$	-			$	-
Consolidated Capital Expenditures		$	54,020			$	28,050

(19)     SUBSEQUENT EVENTS

On March 13, 2023, we executed an amendment 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 appliedwith PNC as discussed in Note 5 to our bank debt. Mr. Lubar, one of our directors, is affiliated with Lubar Equity Fund, LLC.

We did not receive any distributions in 2017 and received two distributions in 2016 totaling $3.6 million from Savoy. Both distributions were applied to our bank debt as required under our agreement.

Savoy also recorded impairments of $1.0 million, $2.0 million, and $2.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.

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.these consolidated financial statements.

 

60

67

---

(12)

Freelandville and Log Creek Purchases

On March 22, 2016, we completed the purchase

Table of the Freelandville coal reserves, advanced royalties, 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 for the acquisition was as follows (in thousands):

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

On December 12, 2016, we completed a second transaction with Triad, 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 2016 and 2017.

(13)

Quarterly Financial Data (Unaudited)

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

Contents

 

*See Note 2 related to asset impairment taken in December 2016 and Note 4 related to the effects of the Tax Act in December 2017.

61

(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.

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

 

Not applicable.None.

ITEM 9A.

CONTROLS AND PROCEDURES.

ITEM 9A.  CONTROLS AND PROCEDURES.

 

Disclosure Controls

 

We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC'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.

As permitted by the SEC, we have excluded the business of Hallador Power Company, LLC, our wholly-owned subsidiary, from our evaluation of the effectiveness of internal control over financial reporting for the year ended December 31, 2022, as substantive operations of this business commenced during the fourth quarter of 2022 following the acquisition of the Merom power plant on October 21, 2022.  See “Note 16 – Merom Acquisition” for additional information on this acquisition.  The operations excluded from our evaluation represent approximately 42% of our total assets as of December 31, 2022 and 18% of our total revenues for the year ended December 31, 2022.

 

Our management evaluated, with the participation of our CEO and CFO, the effectiveness of our ICFR as of December 31, 2017.2022.  Based on that evaluation, our management concluded that our ICFR was effective at December 31, 2017. EKS&H LLLP2022.  

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. Their2022, 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, 2017,2022 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

62

 

68

---

Table of Contents

 

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, 2022, 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, 2022, 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, 2022, and our report dated March 16, 2023 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.

Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of Hallador Power Company, LLC, a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 42 and 18 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2022. As indicated in Management’s Report, Hallador Power Company, LLC began substantive operations during 2022. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of Hallador Power Company, LLC.

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.

69

---

Table of Contents

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 16, 2023

70

---

Table of Contents

ITEM 9B.  OTHER INFORMATION 

On March 13, 2023, Hallador Energy Company executed an amendment to its credit agreement with PNC, administrative agent for its lenders. The primary purpose of the amendment is 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.  The amendment also waived the maximum annual capital expenditure covenant for 2022 and increases the covenant for 2023 to $75 million.

The interest rate per the amendment will transition from LIBOR to SOFR based pricing with ranges from SOFR plus 4.00% to SOFR plus 5.00%, depending on the Company’s leverage ratio. The Company expects the interest rate to be SOFR plus 4.00% for the majority of  2023.

A copy of the credit agreement is filed herewith as Exhibit 10.10 to this Form 10-K.

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, 2022.

 

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.

63

71

---

Table of Contents

 

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 

See Item 8 for an index of our financial statements.

 

Our exhibit index is as follows:

 

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	Description of Securities (3)
10.1	2009 Stock Bonus Plan (2)*(4)
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*
10.5 10.9		Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement* (5)US SBA Loan (PPP) dated April 16, 2020 (7).
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 Restricted Stock Unit Issuance Agreement* (8)
10.12	Hallador Energy Company Four-Year Plan* (7)2020 Compensation Plan adopted March 5, 2020** (2)
14 10.13	2022 Executive Officer Compensation Plan**(17)
10.14	Asset and Purchase Agreement dated February 14, 2022 (9)
10.15	Hallador Energy Company Unsecured Convertible Promissory Note dated May 2, 2022 - Charles R. Wesley, IV Revocable Trust U/A dated October 30, 2020 (11)
10.16	Hallador Energy Company Unsecured Convertible Promissory Note dated May 2, 2022 - Lubar Opportunities Fund I, LLC (11)
10.17	Hallador Energy Company Unsecured Convertible Promissory Note - dated May 2, 2022 - NextG Partners LLC (11)
10.18	Hallador Energy Company Unsecured Convertible Promissory Note - dated May 2, 2022 - Hallador Alternative Asset Fund, LLC (11)
10.19	Hallador Energy Company Unsecured Convertible Promissory Note dated May 20, 2022 - NextG Partners, LLC (12)
10.20	Hallador Energy Company Unsecured Convertible Promissory Note dated May 20 2022 - Hallador Alternative Asset Fund, LLC (12)
10.21	Hallador Energy Company Unsecured Convertible Promissory Note dated May 20, 2022, - Lubar Opportunities Fund I, LLC (12)
10.22	Hallador Energy Company Unsecured Convertible Promissory Note dated May 20, 2020 - Murchison Capital Partners, LP (12)
10.21	Hallador Energy Company Convertible Note Purchase Agreement dated July 29, 2022 (13)
10.23	Hallador Energy Company Unsecured Convertible Promissory Note dated July 29, 2022 - Lubar Opportunities Fund I LLC (13)
10.24	Hallador Energy Company Unsecured Convertible Promissory Note dated August 8, 2022 - Lubar Opportunities Fund I, LLC (14)
10.25	Hallador Energy Company Unsecured Convertible Promissory Note dated August 8, 2022 - Hallador Alternative Assets Fund, LLC (14)
10.26	Hallador Energy Company Unsecured Convertible Promissory Note dated August 12, 2022 - ALJ (15)
14.1	Code of Ethics for Senior Financial Officers. (8)*Officers (18)
21.1		List of  Subsidiaries (9)
23.1		Consent of EKS&H LLLP (9)Grant Thornton LLP
23.2	31Consent of Plante & Moran, PLLC
31.1	SOX 302 Certification - President and CEO
31.2	SOX 302 Certifications (9)- CFO
32 31.3	SOX 302 Certifications - CAO
32	SOX 906 Certification (9)
95		Mine Safety Disclosure (9)
101		Interactive data files. (9)

 

72

---

Table of Contents

 

(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 10-K/A amendment 1, filed June 12, 2020
(3)	IBR to Form 10-K filed March 9, 2020
(4)	IBR to Form S-8 dated December 1, 2009
(3) (5)	IBR to Form 10-Q dated November 10, 2014filed August 6, 2018
(4) (6)	IBR to Form 10-Q dated May 6, 2016
(5)	IBR to Form 8-K dated May 17, 2017
(6)	IBR to Form 10-Q dated August 8, 2017filed November 4, 2019
(7)	IBR to Form 10-Q datedfiled May 6, 201611, 2020
(8)	IBR to the 2005 Form 10-KSB.DEF 14A dated April 11, 2017
(9)	IBR to Form 8-K/A filed February 18, 2022
(10)	IBR to Form 10-K filed March 28, 2022
(11)	IBR to Form 8-K filed May 6, 2022
(12)	IBR to Form 10-Q filed May 23, 2022
(13)	IBR to Form 8-K filed August 4, 2022
(14)	IBR to Form 8-K dated August 11, 2022
(15)	IBR to Form 10-Q filed August 15, 2022
(16)	IBR to Form 8-K filed October 4, 2022
(17)	IBR to Form 10-Q filed November 14, 2022
(18)	IBR to Form 10KSB dated April 14, 2006
*	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.

 

64

73

---

Table of Contents

 

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 16, 2023	/s/LAWRENCE D. MARTIN
	Lawrence D. Martin, CFO
Date: March 16, 2023	/s/R. TODD DAVIS
Date: March 12, 2018	/s/ LAWRENCE D. MARTIN
	Lawrence D. Martin, CFO and CAO

   

R. Todd Davis, 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, 201816, 2023
/s/ BRYAN LAWRENCE
/s/BRYAN LAWRENCE
Bryan Lawrence		Director		March 12, 201816, 2023
/s/ BRENT BILSLAND
/s/BRENT BILSLAND
Brent Bilsland		Board Chairman, President and CEO		March 12, 201816, 2023
/s/ SHELDON B. LUBAR
Sheldon B.
/s/DAVID J.  LUBAR
David J.  Lubar		Director		March 12, 201816, 2023

  

65

74