EDGAR 10-K Filing

Company CIK: 788965
Filing Year: 2022
Filename: 788965_10-K_2022_0001437749-22-007411.json

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ITEM 1. BUSINESS
ITEM 1. BUSINESS.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our business.
Regulation and Laws
The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:
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employee health and safety;
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mine permits and other licensing requirements;
● air quality standards;
● water quality standards;
● storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could reach waterways or wetlands;
● plant and wildlife protection that could limit or prohibit mining or exploration;
● restricting the types, quantities and concentration of materials that can be released into the environment in the performance of mining or exploration and production activities;
● discharge of materials;
● storage and handling of explosives;
● wetlands protection;
● surface subsidence from underground mining; and
● the effects, if any, that mining has on groundwater quality and availability.
Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. The regulatory burden on fossil fuel industries increases the cost of doing business and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly obligations could increase our or our mineral interest operators’ costs and adversely affect our performance. In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected demand for coal. It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be interpreted differently or more stringently enforced, any of which could have a significant impact on our mining operations or our customers’ ability to use coal. For more information, please see risk factors described in “Item 1A. Risk Factors” below.
We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of the extensive and detailed nature of these regulatory requirements, particularly the regulatory system of the Mine Safety and Health Administration (“MSHA”) where citations can be issued without regard to fault, and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations. When we receive a citation, we attempt to remediate any identified condition immediately. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.
Expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the estimated costs and timing of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.
Mining Permits and Approvals
Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and may delay or prevent commencement or continuation of mining operations.
The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.
We are required to post bonds to secure performance under our permits. Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. Although like other coal companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.
Mine Health and Safety Laws
The Federal Mine Safety and Health Act of 1977 (“FMSHA”) and regulations adopted pursuant thereto, imposes extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations. In addition, the states where we operate have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the United States for the protection of employee safety and have a significant effect on our operating costs. Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.
FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability or liability without fault, and FMSHA requires the imposition of a civil penalty for each cited violation. Negligence and gravity assessments, along with other factors can result in the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties. FMSHA also contains criminal liability provisions. For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order or carry out violations of the FMSHA or its mandatory health and safety standards.
The Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:
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sealing off abandoned areas of underground coal mines;
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mine safety equipment, training, and emergency reporting requirements;
● substantially increased civil penalties for regulatory violations;
● training and availability of mine rescue teams;
● underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
● flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and
● post-accident two-way communications and electronic tracking systems.
MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.
In 2014, MSHA began implementation of a finalized new regulation titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.” The final rule implemented a reduction in the allowable respirable coal mine dust exposure limits, requires the use of sampling data taken from a single sample rather than an average of samples, and increases oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine, all of which increase mining costs. The second phase of the rule began in February 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor technology, which provides real-time dust exposure information to the miner. Phase three of the rule began in August 2016 and resulted in lowering the current respirable dust level of 2.0 milligrams per cubic meter to 1.5 milligrams per cubic meter of air. Compliance with these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations. MSHA has published a request for information regarding engineering controls and best practices to lower miners’ exposure to respirable coal mine dust, which is currently set to close on July 9, 2022. It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period for the current request for information.
MSHA has also published, and may continue to publish, various proposed rules or requests for information, which may result in additional rulemakings. For example, in June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust. Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's request for information. The comment period for the request for information closed in September 2020.
Separately, in November 2020, MSHA published a proposed rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine Equipment and Accessories within underground mining environments. The comment period for the proposed rule closed in December 2020. It is uncertain whether MSHA will present a final rule addressing this issue.
Then, in September 2021, MSHA published a proposed rule requiring that mine operators employing six or more miners develop and implement a written safety program for mobile and powered haulage equipment at surface mines and surface areas of underground mines (Safety Program for Surface Mobile Equipment). The comment period for the proposed rule closed in November 2021. However, MHSA reopened the rulemaking record for additional public comments. A virtual hearing was held in January 2022, and the comment period closed in February 2022.
It is uncertain whether MSHA will present a final rule addressing any of the above issues or any of the other various proposed rules or requests for information or whether any such rule would have material impacts on our operations or our costs of operation.
Subsequent to the passage of the MINER Act, Illinois, Kentucky, Pennsylvania, and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Additionally, state administrative agencies can promulgate administrative rules and regulations affecting our operations. Other states may pass similar legislation or administrative regulations in the future.
Some of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to our customers. Although we have not quantified the full impact, implementing and complying with these new federal and state safety laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operations and financial position.
Black Lung Benefits Act
The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 (“BLBA”), requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical expenses where no responsible coal mine operator has been identified for claims. Effective January 1, 2019, the trust fund was funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price. Effective January 1, 2020, the trust fund was funded by an excise tax on coal sold of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. Effective January 1, 2022, the trust fund is funded by an excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to exceed 2% of the applicable sales price. It is uncertain whether the excise tax rates will be adjusted in the future or whether any such modifications would be retroactive.
Workers' Compensation and Black Lung
We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws. Workers’ compensation laws also compensate survivors of workers who suffer employment-related deaths. We generally self-insure this potential expense using our actuary estimates of the cost of present and future claims. In addition, coal mining companies are subject to federal legislation and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal workers' pneumoconiosis or black lung. We also provide for these claims through self-insurance programs. Our actuarial calculations are based on numerous assumptions, including disability incidence, medical costs, mortality, death benefits, dependents and discount rates.
The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria. These regulations may also increase black lung-related medical costs by broadening the scope of conditions for which medical costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.
The Patient Protection and Affordable Care Act enacted in 2010 includes significant changes to the federal black lung program retroactive to 2005, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association with the federal black lung program.
Surface Mining Control and Reclamation Act
The Federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes establish operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining. Currently, ~98% of our production capacity involves underground room and pillar mining (no surface subsidence), and ~2% involves surface mining. We do not engage in either mountain top removal or long-wall mining. SMCRA nevertheless requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.
SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.
In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a reclamation fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The fee expired on September 30, 2021, and was reauthorized through September 30, 2034, under the Infrastructure Investment and Jobs Act which was signed on November 15, 2021. The fee, as reauthorized, for surface-mined and underground-mined coal is $0.224 per ton and $0.096 per ton, respectively, through September 30, 2034. We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis.
Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the third-party violator. Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and having any permits revoked that were issued after the time of the violations or after the time civil penalties or reclamation fees became due. We are not aware of any currently pending or asserted claims against us relating to the “ownership” or “control” theories discussed above. However, we cannot assure you that such claims will not be asserted in the future.
In April 2015, the United States Environmental Protection Agency ("EPA") finalized rules on coal combustion residuals ("CCRs"); however, the final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites. The Federal Office of Surface Mining ("OSM ") has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but to date, no further action has been taken. These actions by OSM potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.
Bonding Requirements
Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for our competitors and us to secure new surety bonds without posting collateral, and in some cases, it is unclear what level of collateral will be required. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals. Our failure to maintain or inability to acquire surety bonds that are required by federal and state laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.
Air Emissions
The Clean Air Act ("CAA") and similar state and local laws and regulations regulate emissions into the air and affect coal mining operations. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities. There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required under applicable federal and state laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans (“SIPs”), could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future. A significant reduction in fossil fuels’ share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations.
In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:
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The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels. These requirements would not be supplanted by a replacement rule for the Clean Air Interstate Rule (“CAIR”), discussed below.
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The CAIR calls for power plants in 28 states and Washington, D.C. to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system in effect for acid rain. In June 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”), a replacement rule for CAIR, which would have required 28 states in the Midwest and eastern seaboard to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. CSAPR has become increasingly irrelevant with continuing coal plant retirements making the nitrogen oxide ozone budget less stringent and lowering emission allowance prices to levels closer to average operating cost for many of our customers. The full impact of CSAPR is unknown at the present time due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the impact of the continuing coal plant retirements.
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In February 2012, the EPA adopted the MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants. In March 2013, the EPA finalized a reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies. In subsequent litigation, the U.S. Supreme Court struck down the MATS rule based on the EPA’s failure to take costs into consideration. The D.C. Circuit Court allowed the current rule to stay in place until the EPA issued a new finding. In April 2016, the EPA issued a final supplemental finding upholding the rule and concluding that a cost analysis supports the MATS rule. In April 2017, the D.C Circuit Court of Appeals granted the EPA’s request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the supplemental finding. In December 2018, the EPA issued a proposed Supplemental Cost Finding, as well as the CAA required "risk and technology review." In May 2020, EPA issued a final rule that reverses the Agency's prior determination from 2000 and 2016 that it was "appropriate and necessary" to regulate hazardous air pollutants ("HAP") from coal-fueled Electric Generating Units ("EGUs") under the MATS rule. Notwithstanding the invalidation of this threshold regulatory determination, the final rule leaves in place all of the HAP emission control requirements imposed by the MATS rule based on the conclusion that the EGU source category cannot meet the statute's stringent requirements for delisting a source category from HAP regulation. Many electric generators have already announced retirements due to the MATS rule. Although various issues surrounding the MATS rule remain subject to litigation in the D.C. Circuit, the MATS rule has forced generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units.
The announced and possible additional retirements are likely to reduce the demand for coal. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.
● The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the National Ambient Air Quality Standards (“NAAQS”) should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter (“PM”), ozone, nitrogen oxide, and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in “attainment” but do not attain the new standards. In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. In March 2019, the EPA published a final rule that retained the current primary NAAQS for sulfur oxide. In December 2020, EPA published a final rule to retain the current NAAQS for both PM and ozone; however, various entities have filed litigation against one or both of these rulemakings, and the NAAQS may be subject to revision under the Biden Administration. New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal.
● The EPA’s regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas, and international parks. Under the program, states are required to develop SIPs to improve visibility. Typically, these plans call for reductions in sulfur dioxide and nitrogen oxide emissions from coal-fueled electric plants. In prior cases, the EPA has decided to negate the SIPs and impose stringent requirements through FIPs. The regional haze program, including particularly the EPA’s FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations. In September 2018, the EPA issued a memorandum that detailed plans to assist states as they develop their SIPs.
● The EPA’s new source review (“NSR”) program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment. The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the NSR program. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued.
GHG Emissions
Combustion of fossil fuels, such as the coal we produce, results in the emission of GHGs, such as carbon dioxide and methane. Combustion of fuel for mining equipment used in coal production also emits GHGs. Future regulation of GHG emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA. Although no comprehensive climate change regulation has been adopted at the federal level in the 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 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, 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 multiple announcements were made, including a call 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 energy sector. Also at COP26, more than forty countries pledged to phase out coal, although the United States did not sign the pledge. The impact of these actions remains unclear at this time. Moreover, many states, regions, and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities. Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted, which would have an adverse effect on our operations.
Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S. Supreme Court’s 2007 decision that the EPA has authority to regulate GHG emissions. Although the U.S. Supreme Court’s holding did not expressly involve the EPA’s authority to regulate GHG emissions from stationary sources, such as coal-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 which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare.
Several rulemakings have been issued under the EPA's New Source Performance Standards ("NSPS") that constrain the GHG emissions of fossil-fuel-fired power plants. In January 2021, the EPA published a final significant contribution finding for purposes of regulating source category of GHG emissions, confirming that such power plants are a source category for such regulations. However, this finding also excludes several sectors and may, therefore, be subject to revision, and future implementation of the NSPS is uncertain at this time.
In August 2015, the EPA issued its final Clean Power Plan ("CPP") rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision. Then, in October 2017 the EPA proposed to repeal the CPP. The EPA subsequently proposed the Affordable Clean Energy ("ACE") rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction." The ACE rule adopts new implementing regulations under the CAA to clarify the roles of the EPA and the states, including an extension of the deadline for state plans and EPA approvals; and the rule revises the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements. In June 2019, the EPA published the final repeal of the CPP and promulgation of the ACE rule. The EPA’s attempts to replace the CPP with the ACE rule are currently subject to litigation, and on January 19, 2021 , the Circuit Court struck down the ACE rule. The EPA has since announced an intent to consider new regulations governing carbon emissions from existing power plants. The EPA’s draft strategic plan issued in November 2021 emphasizes climate change and environmental justice as its top two priorities.
Notwithstanding the ACE rule, these requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal. Congress has not currently adopted legislation to restrict carbon dioxide emissions from existing power plants, and it is unclear whether the EPA has the legal authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP. Substantial limitations on GHG emissions could adversely affect demand for the coal we produce.
There have been numerous protests and challenges to the permitting of new fossil fuel infrastructure, including coal-fired power plants and pipelines, by environmental organizations and state regulators for concerns related to GHG emissions. For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board. In addition, over thirty states have currently adopted “renewable energy standards” or “renewable portfolio standards,” which encourage or require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date. Several states have announced their intent to have renewable energy comprise 100% of their electric generation portfolio. Other states may adopt similar requirements, and federal legislation is a possibility in this area. In December 2021, President Biden issued an executive order setting a goal for a carbon pollution-free electricity sector across the country by 2035. To the extent these requirements affect our current and prospective customers, they may reduce the demand for fossil fuel energy, and may affect long-term demand for our coal. Finally, while the U.S. Supreme Court has held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, the Court did not decide whether similar claims can be brought under state common law. As a result, despite this favorable ruling, tort-type liabilities remain a concern.
In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act (“NEPA”). These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In July 2020, the Council on Environmental Quality ("CEQ ") finalized revisions to NEPA that clarify the extent to which direct, indirect, and cumulative environmental impacts from a proposed project, including GHG emissions, should be examined under NEPA. In October 2021, the CEQ published a proposed rule to restore, in general, NEPA regulations that were in effect before being modified by the 2020 revisions. A final rule is expected in 2022.
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. Since its inception, several additional states and Canadian provinces have joined RGGI as participants or observers, while Virginia has withdrawn from RGGI via executive order by its governor.
Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG 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, only California and certain Canadian provinces are currently active participants in the Western Climate Initiative. Nevertheless, it is likely that these regional efforts will continue based on current trends and concerns related to the reduction of GHG emissions.
It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with fossil fuel production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for fossil fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, which could have a material adverse effect on our business, financial condition, and results of operations. Finally, activists may try to hamper fossil fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding and insurance, as well as pursuing tort litigation for various alleged climate-related impacts.
Water Discharge
The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting. Section 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.
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") and/or a discharge permit from the state regulatory authority under the state counterpart to the CWA. Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments. The CWA authorizes the EPA to review Section 404 permits issued by the Corps of Engineers.
The EPA also has statutory “veto” power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.” In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a previously issued permit for Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project which veto was subsequently upheld by the D.C. Circuit Court of Appeals in 2013. Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to our continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal revenues. In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on a fictitious mine scenario. The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning.
Total Maximum Daily Load (“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired waterbody can receive and still meet state water quality standards and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body. Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDL-related allocations or any changes to antidegradation policies for streams near our coal mines 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 CWA. Rulemakings to establish the extent of such jurisdiction were finalized in 2015 and 2020, respectively, and both rulemakings have been subject to substantial litigation. On August 30, 2021, the US District Court for Arizona granted a request for voluntary remand of the EPA's rule. The Biden Administration has announced plans to establish its own definition of "waters of the United States" ("WOTUS"). Most recently, the EPA and the Corps of Engineers published a proposed rulemaking to revoke the 2020 rule in favor of a pre-2015 definition until a new definition is proposed, which the Biden Administration has announced is underway. Additionally, in January 2022, the Supreme Court agreed to hear a case on the scope and authority of the CWA and the definition of WOTUS. To the extent any decision expands the scope of the EPA and the Corps of Engineers’ jurisdiction under the CWA, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decision
Hazardous Substances and Wastes
The Federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), otherwise known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages. Some products used in coal mining operations 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 analogous state laws impose 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.
RCRA impacts the coal industry in particular because it regulates the disposal of certain coal combustion by-products (“CCB”). On April 17, 2015, the EPA finalized regulations under RCRA for the disposal of CCB. Under the finalized regulations, CCB is regulated as "non-hazardous" waste and avoids the stricter, more costly, regulations under RCRA's hazardous waste 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' 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 2022 and 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. 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 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”), 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 CCB and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal-burning power plants that cannot comply with the new standards. In November 2019, the EPA proposed revisions to the 2015 ELG rule and announced proposed changes to regulations for the disposal of coal ash in order to reduce compliance costs. In October 2020, the EPA published a final rule. In August 2021, the EPA initiated supplemental rulemaking indicating that it intended to strengthen certain discharge limits. The EPA expects to issue a proposed rule for public comment in fall 2022. It is unclear what impact these regulations will have on the market for our products.
Endangered Species Act
The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related activities. In October 2021, the Biden Administration proposed the rollback of new rules promulgated under the Trump Administration; namely, the USFWS plans to rescind the 2018 rule that revised the process for designating critical habitat for threatened and endangered species under the ESA and second, alongside the National Marine Fisheries Service, the USFWS proposes to rescind the 2020 regulatory definition of "habitat." Final action on these proposed rules will occur in 2022.
If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered, or to re-designate a species from threatened to endangered, we could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.
Other Environmental, Health and Safety Regulation
In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground storage tanks in which we may store petroleum or other substances. Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulations. In addition, our use of explosives is subject to the Federal Safe Explosives Act. We are also required to comply with the Federal Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act. The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition or results of operations.
Suppliers
The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, electricity, fuel, and tires. Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of electricity. The supplier base providing mining materials has been relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop.
Illinois Basin (ILB)
The coal industry underwent a significant transformation in the early 1990s, as greater environmental accountability was established in the electric utility industry. Through the U.S. 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 re-opened as a significant fuel source for utilities and has enabled them to burn lower-cost high sulfur coal.
The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana, and western Kentucky. The ILB is centrally located between four of the largest regions that consume coal as fuel for electricity generation (East North Central, West South Central, West North Central, and East South Central). The region also has access to sufficient rail and water transportation routes that service coal-fired power plants in these regions as well as other significant coal consuming regions of the South Atlantic and Middle Atlantic.
U. S. Coal Industry
The major coal production basins in the U.S. include 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-use for each coal type.
Coal in the U.S. is mined through surface and underground mining methods. The primary underground mining techniques are longwall mining and continuous (room-and-pillar) mining. The geological conditions dictate which technique to use. Our mines utilize the continuous mining technique. In continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air. Continuous mining equipment cuts the coal from the mining face. Generally, openings are driven 20’ wide, and the pillars are rectangular in shape measuring 40’x 40’. As mining advances, a grid-like pattern of entries and pillars is formed. Roof bolts are used to secure the roof of the mine. Battery cars move the coal to the conveyor belt for transport to the surface. The pillars can constitute up to 50% of the total coal in a seam.
The 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 other private producers.
Human Capital
As of December 31, 2021, Hallador Energy Company and its subsidiaries employed 805 full-time employees and temporary miners. 760 of those 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, 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. In addition to a highly decorated private mine rescue team, Sunrise Coal in 2021 had three employees on the Indiana State Mine Rescue team and one team trainer which was more than any other mine in Indiana. 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.
We are committed to protecting our employees and doing our part to mitigate the spread of COVID-19 while implementing contingency plans to ensure that we continue to supply our customers without interruption. As the situation has continued to evolve, we continue to monitor the Center for Disease Control and Prevention (CDC) guidelines to keep our employees and their families safe. We have instituted many policies and procedures, in alignment with CDC guidelines along with state and local mandates, to protect our employees during the COVID-19 outbreak. We plan to keep these policies and procedures in place, in accordance with CDC, state, and local guidelines, and continually evaluate further enhancements for as long as necessary. As vaccines for COVID-19 continue to become readily available, we intend to continue encouraging our workforce to get vaccinated, and we are hopeful that the case rate of our employees will continue to decline, and economic activity in general will continue to accelerate. We continue to offer cash incentives to employees who show proof of vaccination.
Other
We have no significant patents, trademarks, licenses, franchises or concessions.
Our corporate office is located at 1183 East Canvasback Drive, Terre Haute, Indiana, 47802, and Sunrise Coal’s corporate office is at the same location, phone 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS.
Risks Related to our Business
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.
We face a wide variety of risks related to pandemics, including the global outbreak of COVID-19. 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. Although we have, to date, managed to continue our operations, we cannot predict the future course of events nor can we assure that this global pandemic, including its economic impact, will not continue to have a material adverse impact on our business, financial position, results of operations and/or cash flows. The COVID-19 pandemic and related economic repercussions have created significant volatility, uncertainty and turmoil in the coal industry. The COVID-19 outbreak and the responsive actions to limit the spread of the virus significantly reduced global economic activity, resulting in a decline in the demand for coal and other commodities. Our operations could be further impacted by the COVID-19 pandemic if significant portions of our workforce are unable to work effectively, including because of illness, quarantines, or absenteeism; steps the company has taken to protect health and well-being; government actions; facility closures; work slowdowns or stoppages; inadequate supplies or resources (such as reliable personal protective equipment, testing, and vaccines); or other circumstances related to COVID-19. Looking forward, we could be unable to perform fully on our contracts, we could experience interruptions in our business, and we could incur liabilities and suffer losses as a result. We will continue to incur additional costs because of the COVID-19 outbreak, including protecting the health and well-being of our employees and as a result of impacts on operations and performance, which costs we may not be fully able to recover. We could be subject to additional regulatory requirements, enforcement actions, and litigation, again with costs and liabilities that are not fully recoverable or insured. The continued spread of COVID-19 could also affect our ability to hire, develop and retain our talented and diverse workforce, and to maintain our corporate culture. The continued global pandemic, including the economic impact, is likely also to cause further disruption in our supply chain. If our suppliers have increased challenges with their workforce (including as a result of illness, absenteeism or government orders), facility closures, access to necessary components and supplies, access to capital, and access to fundamental support services (such as shipping and transportation), they could be unable to provide the agreed-upon goods and services in a timely, compliant and cost-effective manner. We could incur additional costs and delays in our business, including as a result of higher prices for materials and equipment and schedule delays. As a result of the COVID-19 crisis, there may be changes in our customers' priorities and practices, as our customers confront reduced demand. Our customers have and may continue to experience adverse effects as a result of the COVID-19 crisis which could impact their creditworthiness or their ability to make payment for our products. We continue to work with our stakeholders (including customers, employees, suppliers, and local communities) to address this global pandemic responsibly. We continue to monitor the situation, to assess further possible implications to our employees, business, supply chain, and customers, and to take certain actions to mitigate various adverse consequences. We expect that the longer the COVID-19 pandemic, including its economic disruption, continues, the greater the adverse impact on our business operations, financial performance, and results of operations could be. Given the tremendous uncertainties and variables that still exist, we cannot predict the impact of the global COVID-19 pandemic, or any future pandemic, on our operational and financial performance in future periods; but any pandemic or similar outbreak could have a material adverse impact on our business.
Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets could have material adverse impacts on our business and financial condition that we currently cannot predict.
Weakness in global economic conditions or economic conditions in any of the industries we serve or in the financial markets could materially adversely affect our business and financial condition. For example:
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the demand for electricity in the U.S. and globally may decline if economic conditions deteriorate, which may negatively impact the revenues, margins, and profitability of our business;
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any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and
● our future ability to access the capital markets may be restricted as a result of future economic conditions, which could materially impact our ability to grow our business, including development of our coal reserves.
The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal.
In 2021, 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 sales 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 may 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 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 may 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 2021, we derived 95% of our revenue from five customers (10 power plants), with each of the five customers representing at least 10% of our coal sales. If in the future we lose any of these customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition and results of operations.
Our 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 sold and delivered depends on the continued creditworthiness of our customers. If the creditworthiness of our customers declines significantly, our business could be adversely affected. In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease, and we may have to reduce production at our mines until our customer’s contractual obligations are honored.
Although none of our 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 may still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.
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. At times, weakness in the energy sector in general and coal, in particular, has significantly impacted access to the debt and equity capital markets. Accordingly, our funding plans may be negatively impacted by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations. In addition, we may be unable to refinance our current debt obligations when they expire or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet their funding obligations. Furthermore, additional growth projects and expansion opportunities may develop in the future that could also require significant amounts of financing that may not be available to us on acceptable terms or in the amounts we expect, or at all.
Various factors could adversely impact the debt and equity capital markets as well as our credit ratings or our ability to remain in compliance with the financial covenants under our then current debt agreements, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows. If we are unable to finance our growth and future expansions as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.
Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.
Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, 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, 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.
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 1.05 to 1 and (ii) a Maximum Leverage Ratio (consolidated funded debt/trailing twelve months adjusted EBITDA) not to exceed 3.00 to 1, which also decreases in future periods further reducing the maximum leverage permitted. On December 31, 2021, our debt service coverage ratio was 1.11, and our leverage ratio was 2.34. 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, 2021, our bank debt was $111.7 million. Our leverage may:
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adversely affect our ability to finance future operations and capital needs;
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limit our ability to pursue acquisitions and other business opportunities; and
● make our results of operations more susceptible to adverse economic or operating conditions.
Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions, and capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
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 will be 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, 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.
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:
● the adverse impact of the COVID-19 pandemic due to the reduction in demand, as well as impacts of the pandemic on our ability to produce coal;
● the supply of and demand for domestic and foreign coal;
● weather conditions and patterns that affect demand for or our ability to produce coal;
● the proximity to and capacity of transportation facilities;
● supply chain and cost of raw materials for coal operations;
● competition from other coal suppliers;
● domestic and foreign governmental regulations and taxes;
● the price and availability of alternative fuels;
● the effect of worldwide energy consumption, including the impact of technological advances on energy consumption;
● overall domestic and global economic conditions;
● international developments impacting supply of coal; and
● the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits.
Any adverse change in these factors could result in weaker demand and lower prices for our products. 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 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 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 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 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 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. We expect that many of the new power plants needed in the United States 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 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. 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.
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, a prolonged economic recession, or prolonged recovery from the COVID-19 pandemic, 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 powerplants (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. 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. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. 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. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
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 may 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 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 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:
● mining and processing equipment failures and unexpected maintenance problems;
● unavailability of required equipment;
● prices for fuel, steel, explosives and other supplies;
● fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;
● variations in thickness of the layer, or seam, of coal;
● amounts of overburden, partings, rock and other natural materials;
● weather conditions, such as heavy rains, flooding, ice and other natural events affecting operations, transportation or customers;
● accidental mine water discharges and other geological conditions;
● seismic activities, ground failures, rock bursts or structural cave-ins or slides;
● fires;
● employee injuries or fatalities;
● labor-related interruptions;
● increased reclamation costs;
● inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;
● fluctuations in transportation costs and the availability or reliability of transportation; and
● unexpected operational interruptions due to other factors.
These conditions have the potential to significantly impact our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.
Our inability to obtain commercial insurance at acceptable rates or our failure to adequately reserve for self-insured exposures could increase our expenses and have a negative impact on our business.
We believe that commercial insurance coverage is prudent in certain areas of our business for risk management. Insurance costs could increase substantially in the future and could be affected by natural disasters, fear of terrorism, financial irregularities, cybersecurity breaches and other fraud at publicly-traded companies, intervention by the government, an increase in the number of claims received by the carriers, and a decrease in the number of insurance carriers. In addition, the carriers with which we hold our policies could go out of business or be otherwise unable to fulfill their contractual obligations or could disagree with our interpretation of the coverage or the amounts owed. In addition, for certain types or levels of risk, such as risks associated with certain natural disasters or terrorist attacks, we may determine that we cannot obtain commercial insurance at acceptable rates, if at all. Therefore, we may choose to forego or limit our purchase of relevant commercial insurance, choosing instead to self-insure one or more types or levels of risks. If we suffer a substantial loss that is not covered by commercial insurance or our self-insurance reserves, the loss and related expenses could harm our business and operating results. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, environmental activists could try to hamper fossil-fuel companies by other means including pressuring insurance and surety companies into restricting access to certain needed coverages.
Our 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 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. 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.
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 may face difficulties in the future that may 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.
It is possible 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 ability to increase or to maintain production and could adversely affect revenues.
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. 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:
●
uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, expansion and acquisition opportunities;
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the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;
● problems that could arise from the integration of the new operations; and
● unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.
Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.
The 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 may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may 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 may prove inaccurate and could result in decreased profitability.
The estimates of our coal reserves may 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 may vary considerably from actual results. These factors and assumptions relate to:
●
geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;
●
the percentage of coal in the ground ultimately recoverable;
● historical production from the area compared with production from other producing areas;
● the assumed effects of regulation and taxes by governmental agencies;
● future improvements in mining technology; and
● assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes, and development and reclamation costs.
For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Any inaccuracy in the estimates of our reserves could result in higher than expected costs and decreased profitability.
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 characteristic 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 may 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 may be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.
Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.
In past years, members of Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed, but the elimination of those provisions would negatively impact our financial statements and results of operations.
A shortage of skilled labor may make it difficult for us to maintain labor productivity and competitive costs and could adversely affect our profitability.
Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least one year of experience and proficiency in multiple mining tasks. In recent years, a shortage of experienced coal miners has caused us to include some inexperienced staff in the operation of certain mining units, which decreases our productivity and increases our costs. This shortage of experienced coal miners is the result of a significant percentage of experienced coal miners reaching retirement age, combined with the difficulty of retaining existing workers in and attracting new workers to the coal industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.
Disruptions in supply chains could significantly impair our operating profitability.
We are dependent upon vendors to supply mining equipment, safety equipment, supplies, and materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demands for their services, we could experience reductions in our production or increased production costs, which could lead to reduced profitability and adversely affect our results of operations.
Inflationary pressures could significantly impair our operating profitability.
Any future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel, maintenance expense and labor. In addition to potential cost increases, inflation could cause a decline in global or regional economic conditions that reduce demand for our coal and could adversely affect our results of operations.

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

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

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS. None

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

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
Stock Price Information
Our common stock trades on the NASDAQ Capital Market under the symbol HNRG, and 30.7% is held by our officers, directors, and their affiliates.
At March 23, 2022, we had 275 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 10 to our consolidated financial statements.

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

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Our consolidated financial statements should be read in conjunction with this discussion. The following analysis includes a discussion of metrics on a per 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.
COVID-19
In the first quarter of 2020, COVID-19 emerged as a global pandemic. The State of Indiana, where our operations are located, issued a shelter in place order from March 24, 2020, to May 4, 2020. The State deemed our operations necessary and essential, and we were allowed to operate as a supplier to critical power infrastructure. We continue to monitor the ongoing pandemic and note that if conditions deteriorate in the future, it could negatively impact our results of operations, financial position, and liquidity.
We have instituted many policies and procedures, in alignment with CDC guidelines along with state and local mandates, to protect our employees during the COVID-19 outbreak. We plan to keep these policies and procedures in place, in accordance with CDC, state, and local guidelines, and continually evaluate further enhancements for as long as necessary. We recognize that the COVID-19 outbreak, and responses thereto, will also impact both our customers and suppliers. As world economies have emerged from both the global pandemic and the power outages in Texas last winter, supplies have become more challenging to secure. At times we have paid premiums for supplies to ensure no interruptions to our production.
As vaccines for COVID-19 continue to become readily available, we intend to continue encouraging our workforce to get vaccinated, and we are hopeful that the case rate of our employees will continue to decline, and economic activity in general will continue to accelerate. We continue to offer cash incentives to employees who show proof of vaccination.
OVERVIEW
The largest portion of our business is devoted to coal mining in the State of Indiana through Sunrise Coal, LLC (a wholly-owned subsidiary) serving the electric power generation industry. We also own a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method.
On February 15th, 2022, Hallador Energy announced its new wholly-owned subsidiary, Hallador Power Company, LLC, will acquire Hoosier Energy’s 1-Gigawatt Merom Generating Station ("Merom"), located in Sullivan County, Indiana, in return for assuming certain decommissioning costs and environmental responsibilities. The transaction, which includes a 3.5-year power purchase agreement (PPA), is scheduled to close in mid-July 2022 upon obtaining required governmental and financial approvals.
Per the agreement, Hoosier will purchase 100% of the plant’s energy and capacity through May 2023, reducing purchases to 22% of energy output and 32% of its capacity beginning in June 2023 and through 2025. The existing renewable PPA - signed in May 2021 and representing 150 MW of solar generation and 50 MW of battery storage - will be retained, with its start date delayed until Merom’s eventual retirement.
Going forward, Hallador Energy will have two primary subsidiaries: Sunrise Coal, LLC and Hallador Power Company, LLC. All coal production assets will remain with Sunrise Coal. Hallador Power Company will hold assets associated with electricity production, including, but not limited to, the Merom Generating Station, Power Purchase Agreements and Interconnection rights.
We anticipate operating Merom post-closing in mid-July of 2022. Hallador will provide little coal to the plant in 2022 but anticipates increasing Sunrise Coal’s sales to Merom in 2023 and beyond.
We expect Hallador Power to contribute little to Hallador Energy profits in 2022. However, this acquisition is significant starting in 2023, and we believe Hallador Power will double Hallador Energy’s EBITDA.
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”). 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, 2021:
SUMMARY MINERAL RESERVES AT END OF THE
FISCAL YEAR ENDED DECEMBER 31, 2021
Mineral Reserves (tons in millions)
Proven
Probable
Total
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine
40.1
0.4
40.5
Oaktown Fuels No. 2 Mine
29.7
1.2
30.9
Total
69.8
1.6
71.4
Oaktown Mining Complex
The Oaktown Mining Complex is a coal mining and processing operation located in Knox and Sullivan counties, Indiana, and Crawford and Lawrence counties, Illinois. The following figure shows the general location of the Oaktown Mining Complex:
Comprising 118 square miles within the ILB coal-producing region of the mid-western 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 [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 58.3 million tons of clean coal. The complex is configured to operate up to 7 CM sections, with an annual production target of approximately 6-7 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 has a current processing capacity of 1,600 raw tons-per-hour (TPH). Product coal from the Oaktown Mining Complex is transported to its customer base via rail, truck, or a combination of both. The Oaktown Complex Coal Preparation Plant is served by both the CSX Railroad and Indiana Railroad (INRD) via a rail spur and rail loop that connects the complex with the mainline rail just north of Oaktown, Indiana.
Additionally, the Oaktown Complex Coal Preparation Plant can facilitate the loading of trucks for direct transport to select customers, or to our transload facility in Princeton, Indiana serviced by the Norfolk Southern (NS) Railroad.
Sources of electrical power, water, supplies, and materials are readily available. Electrical power is provided to the mines and facilities by regional utility companies. Water is supplied by public water services, surface impoundments, or water wells.
Multiple permits are required by federal and state law for underground mining, coal preparation and related facilities, and other incidental activities. All necessary permits to support current operations are in place or pending approval. New permits or permit revisions may be necessary from time to time to facilitate future operations. Given sufficient time and planning, we should be able to secure new permits, as required, to maintain our planned operations within the context of the current regulations.
Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. We hold surety bonds to cover obligations relating to mining and reclamation, road repair, etc. Those obligations are currently estimated at $5.8 million.
Additional information is provided in the following table regarding the Oaktown Mining Complex mineral reserves:
OAKTOWN MINING COMPLEX
Recoverable Coal Reserves as of December 31, 2021 and 2020
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
12/31/2021
12/31/2020
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine
11,519
6.0
-
100.0
40.1
0.4
40.5
45.3
Oaktown Fuels No. 2 Mine
11,540
5.6
-
100.0
29.7
1.2
30.9
34.9
Total Recoverable Coal Reserves
69.8
1.6
71.4
80.2
Oaktown Fuels No. 1 Mine
The assigned and accessible reserve base for the Oaktown Fuels No. 1 Mine contains 40.5 million tons of recoverable Indiana V seam coal, of which 40.5 million tons are currently permitted. The reserve contains saleable tons which average heating content of approximately 11,519 Btu per pound with approximately 6.0 pounds of sulfur dioxide per MMBtu on an as-received basis. Access to the Oaktown Fuels No. 1 Mine is via a 90-foot-deep box cut and a 2,200-foot slope, which facilitates the egress of coals being mined in excess of 375 feet below the surface. Since beginning first commercial coal production in 2009, the mine workings have substantially grown, and an additional mine access (elevator) was constructed for employee and supply ingress/egress closer to the active production faces.
Oaktown Fuels No. 2 Mine
The assigned and accessible reserve base for the Oaktown Fuels No. 2 Mine contains 30.9 million tons of recoverable Indiana V seam coal, of which 25.6 million tons are currently permitted. The reserve contains saleable tons which average heating content of approximately 11,540 Btu per pound with approximately 5.6 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, 2021, 2020, and 2019 is provided in the following table:
Annual Saleable Production Tons
(Million Tons)
Mine/Reserve
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine
3.5
3.4
4.2
Oaktown Fuels No. 2 Mine
2.1
1.8
2.3
Total Oaktown Mining Complex Production
5.6
5.2
6.5
Other Properties
The Company holds other recoverable coal reserves in the ILB, which are not deemed individually material.
Ace in the Hole Mine (Ace) (surface) - Assigned
We have 0.05 million controlled, saleable tons at our Ace mine. The Ace mine is near Clay City, Indiana in Clay County and 50 road miles northeast of the Oaktown Mine. The two primary seams are low sulfur coal (~2# SO2), which make up the vast majority of the 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 toblend 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.
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 95% 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 78% to 100% depending on the seam.
We will complete mining operations at Ace in the Hole Mine in 2022.
Ace in the Hole Mine #2 Reserves (surface) - Unassigned
In 2018, we leased property giving us 1.0 million controlled, saleable tons at a new location 2 miles southwest of our Ace in the Hole mine. Future mine development is being reviewed along with other opportunities.
Asset Impairment Review
See Note 2 to our consolidated financial statements.
Our Coal Contracts
In 2021, Sunrise sold 6.2 million tons of coal to 14 power plants in four different states across nine different customers.
During 2021, we derived 95% of our revenue from five customers (10 power plants), with each of the five customers representing at least 10% of our coal sales. During 2020, we derived 79% of our revenue from four customers (6 power plants), with each of the four customers representing at least 10% of our coal sales.
Significant customers in 2021 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC), Alcoa Power Generating, Inc., a subsidiary of Alcoa Corporation (NYSE: AA), Indianapolis Power & Light Company (IPL), a wholly-owned subsidiary of The AES Corporation (NYSE: AES), and Duke Energy Corporation (NYSE: DUK).
Of our 2021 sales, 73% were shipped to locations in the State of Indiana.
Upon closing the purchase of the Merom Power Plant, we anticipate Hallador Power Company consuming 45% of Sunrise Coal’s production by 2024.
In Q4 2021, customer coal inventories and natural gas (a competitor to coal) inventory levels were both lower than normal. Customers returned to market this year, and we are increasing production to meet the increasing demand. We are increasing production to 7 million clean tons annually starting in 2022 and expect to maintain that pace into the foreseeable future.
Contracted
Estimated
tons
price
Year
(millions)*
per ton
6.8
$ 39.81
5.3
$ 43.10
2024 - 2027
6.3
**
Total
18.4
* 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
Of significant note, both the reopening of the economy post Covid-19 related lockdowns and the supply disruption created by the conflict between Russia and Ukraine have significantly increased demand for U.S. steam coal. This has led to higher pricing both for coal and electricity. All of our 2022 coal and electricity supply is priced, but we anticipate participating in higher coal and electricity prices in 2023.
We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers.
Some utility customers have proposed shuttering certain plant units or entire plants in the coming years. It remains to be seen whether these plans will be implemented. Upon completion of the acquisition of the Merom Power Plant from Hoosier Energy, we anticipate our mines will need to produce at a 7 million-ton annualized pace for several years.
Liquidity and Capital Resources
As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $48.0 million and $52.6 million for the years ended December 31, 2021 and 2020 respectively. Operating cash flow decreased primarily due to a reduction in operating margins brought on by lower pricing and increased costs. Operating margin per ton decreased in 2021 to $7.35/ton from $9.49/ton in 2020, reducing operating cash flow by $11.3 million. This reduction was offset by changes in certain working capital items, specifically our significant inventory reduction from 2020.
Our capital expenditure budget for 2022 is $25 million, of which $15 million is for maintenance capex. We also have scheduled payments on long-term debt totaling $25.7 million. We expect cash from operations for 2022 and the utilization of our revolver, if necessary, to fund our maintenance capital expenditures and our debt service.
In 4Q21, we generated lower than expected EBITDA due to elevated cash costs related to: i) a temporary decrease in efficiency, as new hires were integrated into the workforce to support more shifts required to fulfill the significant increase in contracted tonnage, and ii) a lower yield on coal mined due to mining of a coal face ~10.5 miles away from the slope. We amended our bank agreement in March 2022 to provide covenant relief to maintain our liquidity levels as costs are anticipated to improve in 2022.
See Note 5 to our consolidated financial statements for additional discussion about our bank debt and related liquidity.
Off-Balance Sheet Arrangements
Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded reclamation obligations of $14.1 million, with the long-term portion presented as asset retirement obligations (ARO) and the remainder in accounts payable and accrued liabilities in our accompanying balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $23.5 million to cover ARO.
Capital Expenditures (capex)
For the year ended December 31, 2021, our capex was $28.1 million allocated as follows (in millions):
Oaktown - maintenance capex
$ 9.0
Oaktown - investment
19.0
Other
0.1
Capex per the Consolidated Statements of Cash Flows
$ 28.1
Results of Operations
I. 2021 Net Loss of $3.8 million.
a. Sales: We shipped 6.2 million tons during 2021, an increase over the 6.0 million tons shipped in 2020.
i. Coal inventory was reduced by $17.0 million during the year.
b. Production: 2021 production costs were $32.16/ton. 2020 costs were slightly better at $31.07/ton. Oaktown costs over that same period were $30.34 and $29.84, respectively.
i. In November 2021, we completed construction and put into service an employee and supply hoist closer to the operating face reducing travel time and related labor costs.
ii. We experienced supply chain disruptions with some vendors, causing us to pay premium prices for some of our inputs. We expect these increases to dissipate throughout 2022.
c. Cash Flow & Debt: We generated $48.0 million in operating cash flow during the year, which we utilized to pay down our bank debt by $26.0 million. The Small Business Administration notified us in the third quarter of 2021 that the entire $10 million borrowed under the Paycheck Protection Program had been completely forgiven.
i. As of December 31, 2021, our bank debt was $111.7 million, bringing our liquidity to $33.4 million and our leverage ratio to 2.34X, within our covenant of 3.0X.
The following tables presenting our quarterly results of operations should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of this Form 10-K. We have prepared the unaudited information on the same basis as our audited consolidated financial statements. Our operating results for any quarter are not necessarily indicative of results for any future quarters or for a full year. The tables present our unaudited quarterly results of operations for the eight quarters ended December 31, 2021, 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.
Mar-31
Jun-30
Sep-30
Dec-31
Total 2021
SALES AND OPERATING REVENUES:
Coal sales
$ 45,879
$ 54,600
$ 79,036
$ 64,388
$ 243,903
Other revenues
1,038
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
1,504
Asset retirement obligations change in estimate
-
-
-
(3,510 )
(3,510 )
Exploration costs
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 interest
(2,135 )
(2,307 )
(2,167 )
(1,901 )
(8,510 )
Non-cash interest
Gain on extinguishment of debt
-
-
10,000
-
10,000
Equity method investment income
-
INCOME (LOSS) BEFORE INCOME TAXES
(2,761 )
(2,567 )
6,627
(5,027 )
(3,728 )
INCOME TAX EXPENSE (BENEFIT):
Current
-
-
-
-
-
Deferred
(1,729 )
(1,359 )
2,717
Total income tax expense (benefit)
(1,729 )
(1,359 )
2,717
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 )
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic and diluted
30,611
30,613
30,613
30,618
30,614
Mar-31
Jun-30
Sep-30
Dec-31
Total 2020
SALES AND OPERATING REVENUES:
Coal sales
$ 61,932
$ 50,473
$ 64,754
$ 64,925
$ 242,084
Other revenues
2,157
Total revenue
62,483
50,850
65,247
65,661
244,241
EXPENSES:
Operating expenses
48,469
36,165
46,570
54,753
185,957
Depreciation, depletion and amortization
10,627
10,217
9,315
9,485
39,644
Asset Impairment
-
-
1,799
-
1,799
Asset retirement obligations accretion
1,381
Exploration costs
General and administrative
2,978
2,678
3,131
2,807
11,594
Total operating expenses
62,660
49,611
61,337
67,535
241,143
INCOME (LOSS) FROM OPERATIONS
(177 )
1,239
3,910
(1,874 )
3,098
Bank interest
(2,654 )
(2,842 )
(2,714 )
(2,443 )
(10,653 )
Non-cash interest
(3,060 )
(2,377 )
Equity method investment income (loss)
1,231
(119 )
(113 )
1,054
INCOME (LOSS) BEFORE INCOME TAXES
(5,836 )
(364 )
1,462
(4,140 )
(8,878 )
INCOME TAX EXPENSE (BENEFIT):
Current
(524 )
-
(74 )
-
(598 )
Deferred
(1,652 )
(618 )
(387 )
(2,060 )
Total income tax expense (benefit)
(2,176 )
(618 )
(461 )
(2,658 )
NET INCOME (LOSS)
$ (3,660 )
$
$ 1,923
$ (4,737 )
$ (6,220 )
NET INCOME (LOSS) PER SHARE:
Basic and diluted
$ (0.12 )
$ 0.01
$ 0.06
$ (0.15 )
$ (0.20 )
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic and diluted
30,420
30,423
30,465
30,475
30,446
Quarterly coal sales and cost data follow (in 000’s, except for per ton data and wash plant recovery percentage):
All Mines
1st 2021
2nd 2021
3rd 2021
4th 2021
T4Qs
Tons produced
1,592
1,292
1,440
1,447
5,771
Tons sold
1,174
1,403
2,042
1,554
6,173
Coal sales
$ 45,879
$ 54,600
$ 79,036
$ 64,388
$ 243,903
Average price/ton
$ 39.08
$ 38.92
$ 38.71
$ 41.43
$ 39.51
Wash plant recovery in %
%
%
%
%
Operating costs
$ 33,907
$ 42,364
$ 67,694
$ 54,583
$ 198,548
Average cost/ton
$ 28.88
$ 30.20
$ 33.15
$ 35.12
$ 32.16
Margin
$ 11,972
$ 12,236
$ 11,342
$ 9,805
$ 45,355
Margin/ton
$ 10.20
$ 8.72
$ 5.55
$ 6.31
$ 7.35
Capex
$ 5,720
$ 5,117
$ 7,238
$ 9,975
$ 28,050
Maintenance capex
$ 2,343
$ 1,049
$ 2,324
$ 3,302
$ 9,018
Maintenance capex/ton
$ 2.00
$ 0.75
$ 1.14
$ 2.12
$ 1.46
All Mines
1st 2020
2nd 2020
3rd 2020
4th 2020
T4Qs
Tons produced
1,701
1,468
1,234
1,233
5,636
Tons sold
1,526
1,244
1,585
1,613
5,968
Coal sales
$ 61,932
$ 50,473
$ 64,754
$ 64,925
$ 242,084
Average price/ton
$ 40.58
$ 40.57
$ 40.85
$ 40.25
$ 40.56
Wash plant recovery in %
%
%
%
%
Operating costs
$ 48,334
$ 36,001
$ 46,444
$ 54,640
$ 185,419
Average cost/ton
$ 31.67
$ 28.94
$ 29.30
$ 33.87
$ 31.07
Margin
$ 13,598
$ 14,472
$ 18,310
$ 10,285
$ 56,665
Margin/ton
$ 8.91
$ 11.63
$ 11.55
$ 6.38
$ 9.49
Capex
$ 5,999
$ 4,006
$ 3,995
$ 6,661
$ 20,661
Maintenance capex
$ 3,470
$ 2,578
$ 1,365
$ 2,342
$ 9,755
Maintenance capex/ton
$ 2.27
$ 2.07
$ 0.86
$ 1.45
$ 1.63
2021 v. 2020
For 2021, we sold 6,173,000 tons at an average price of $39.51/ton. For 2020, we sold 5,968,000 tons an average price of $40.56/ton. The decrease in average price per ton results from our changing contract mix caused by the expiration of contracts and the acquisition of new contracts. 2022 pricing is expected to be comparable to 2021 at approximately $40 per ton. 2023 pricing is expected to improve as we take advantage of the higher pricing environment and is projected at just over $43 per ton based on the current tons under contract.
Operating expenses for our coal mines averaged $32.16/ton and $31.07/ton for the years ended December 31, 2021 and 2020, respectively. Oaktown costs over the periods were $30.34 and $29.84, respectively. The majority of our production cost increase was a result of approaching the end of our Ace in the Hole Mine’s reserve life. We anticipate the Ace reserve reaching its end in mid-2022 and being replaced with a new reserve. At Oaktown, we added 17% to our workforce as we begin to increase production from a 6.2 million-ton pace to over 7 million tons annually. It will take time and training for our new workforce to reach top efficiency and productivity. Additionally, as expected and announced, adding a new production unit required mining through challenging conditions during Q4 2021 and completed in Q1 2022. We expect operating costs for our coal mines to be elevated in Q1 2022, but to average $29-$31 per ton for the full year 2022.
Operating expenses associated with the idled Prosperity mine were $1.0 million for both years ended December 31, 2021 and 2020. We expect operating costs to be $1.0 million in 2022.
Other revenues increased $1.6 million in 2021. Coal storage contracts and deferral fees charged for tons carried over from 2020 account for $0.8 million. The remainder represents royalty income on owned minerals that we began collecting in mid-2020.
General and administrative expenses increased $3.2 million in 2021 as a result of increased legal and financing costs associated with the Merom Power Plant acquisition and other projects. We expect general and administrative expenses for 2022 to remain elevated at $13 - $14 million while we complete the Merom Power Plant acquisition.
Our Sunrise Coal employees and contractors totaled 797 at December 31, 2021, compared to 682 at December 31, 2020. As previously stated, the significant increase is due to increased demand for our coal going forward.
Signs of Improvement for the Coal Market
I.
Natural Gas - Forward Nymex gas prices (a competitor to coal) average $5.11 for the remainder of 2022, $4.05 for 2023 and $3.51 for 2024. These gas prices cause coal plants to dispatch prior to gas especially in Indiana where ~80% of our coal is sold. Gas prices are significantly higher than recent history and should remain strong until additional production occurs.
II.
Coal Exports - U.S. export prices are significantly higher than recent history due to energy shortfalls in Asia and Europe, resulting in very strong exports in comeing years.
a.
API 4 (Asia)
2021: Mid $80s / tonne
2022: $202 / tonne
2023: $151 / tonne
2024: $106 / tonne
2025: $95 / tonne
b. API 2 (Europe)
2021: Mid $60s / tonne
2022: $228 / tonne
2023: $170 / tonne
2024: $116 / tonne
2025: $98 / tonne
III. Utility Coal Inventories - Coal inventories at power plants remain well below historical averages. As coal demand stays strong and coal supply is limited, inventories should remain low for the foreseeable future.
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. After applying the provisions of ASU 2014-09, as of December 31, 2021, we do not consider unreimbursed costs from our customers related to these compliance matters to be material and have constrained such amounts and will recognize them when they can be estimated with reasonable certainty.
Income Taxes
Our effective tax rate (ETR) for 2021 was (1%) compared to 30% for 2020. The tax rate for the years ended December 31, 2021 and 2020 are not predictive of future tax rates. Our ETR differs from the statutory rate due to statutory depletion in excess of tax basis, PPP loan forgiveness, return to provision adjustments, and changes in the valuation allowance. The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.
Critical Accounting Estimates
We believe that the estimates of our coal reserves, our interest rate swaps, our asset retirement obligation liabilities, our deferred tax accounts, and the estimates used in our impairment analysis are our only critical accounting estimates.
The reserve estimates are used in the depreciation, depletion and amortization calculations and in our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected.
The fair value of our interest rate swaps and asset retirement obligation liabilities is determined using a discounted future cash flow model based on the key assumption of anticipated future interest rates and related credit adjustment considerations.
We have analyzed our filing positions in all federal and state jurisdictions where we are required to file income tax returns, and all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm (Plante & Moran, PLLC, Denver, Colorado, PCAOB ID 166)
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statement of Stockholders’ Equity
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of Hallador Energy Company
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Hallador Energy Company (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, cash flows, and stockholders' equity for each of the years in the two-year period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021, and 2020, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
The Company's management is responsible for these financial statements. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. 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 audits we are required to obtain an understanding of internal control over financial reporting 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 included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit 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 a critical audit matter 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.
Asset Retirement Obligations
Critical Audit Matter Description
The Company’s asset retirement obligations (“ARO”) balance was $14.0 million as of December 31, 2021. As further described in Note 1, these AROs relate to obligations associated with the future retirement of long-lived assets including underground and surface mines, support facilities, refuse areas, and slurry ponds. The AROs are initially recognized at their estimated fair value at the time incurred and subsequently accreted to their estimated reclamation cost. The Company reviews the ARO balance at least annually and records revisions for permit changes, changes in estimated reclamation costs, and changes in the estimated timing of such costs.
We identified ARO as a critical audit matter as it includes significant judgments made by management as the estimated fair value is determined using a discounted cash flow technique requiring estimates including reclamation costs, credit-adjusted risk-free rates, inflation rates, market risk premiums, and an estimated reclamation date which includes an estimate of the life of the mine and permit and regulatory considerations. In turn, performing audit procedures and evaluating audit evidence obtained related to these significant estimates and judgments required a high degree of judgment and effort.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures performed to address this critical audit matter included the following, among others:
●
We gained an understanding of the design of the controls over management’s process to develop the estimates included in the ARO determination.
●
Evaluated the methodology used by management in determining amount of the ARO.
●
Compared certain assumptions to market data including credit-adjusted risk-free rates and inflation rates.
●
Interviewed the Company’s engineering specialists regarding the regulatory requirements and mine closure plans as well as the reclamation cost estimates and scope of the obligations.
●
Evaluated the reclamation cost estimates by comparison to recent activity and historical amounts.
●
We evaluated the adequacy of the Company’s footnote disclosures in relation to AROs.
We have served as the Company’s auditor since 2003.
/S/PLANTE & MORAN, PLLC
Denver, Colorado
March 28, 2022
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
Consolidated Balance Sheets
As of December 31,
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents
$ 2,546 $ 8,041
Restricted cash
3,283 4,030
Accounts receivable
13,584 14,414
Inventory
7,699 24,663
Parts and supplies
10,015 8,903
Prepaid expenses
2,112 3,282
Total current assets
39,239 63,333
Property, plant and equipment:
Land and mineral rights
115,837 115,853
Buildings and equipment
342,782 352,115
Mine development
112,575 93,635
Total property, plant and equipment
571,194 561,603
Less - accumulated depreciation, depletion and amortization
(268,370 ) (252,245 )
Total property, plant and equipment, net
302,824 309,358
Investment in Sunrise Energy
3,545 3,181
Other assets
8,372 8,258
Total assets
$ 353,980 $ 384,130
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS, AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net
$ 23,098 $ 34,311
Current portion of PPP note
- 5,490
Accounts payable and accrued liabilities
41,528 31,409
Total current liabilities
64,626 71,210
Long-term liabilities:
Bank debt, net
84,667 97,307
PPP note
- 4,510
Deferred income taxes
2,850 2,824
Asset retirement obligations
14,025 16,177
Other
1,577 2,842
Total long-term liabilities
103,119 123,660
Total liabilities
167,745 194,870
Redeemable noncontrolling interests
4,000 4,000
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
- -
Common stock, $.01 par value, 100,000 shares authorized; 30,785 and 30,610 issued and outstanding, respectively
308 306
Additional paid-in capital
104,126 103,399
Retained earnings
77,801 81,555
Total stockholders’ equity
182,235 185,260
Total liabilities, redeemable noncontrolling interests, and stockholders’ equity
$ 353,980 $ 384,130
See accompanying notes.
Hallador Energy Company
Consolidated Statements of Operations
For the years ended December 31,
(in thousands, except per share data)
SALES AND OPERATING REVENUES:
Coal sales
$ 243,903
$ 242,084
Other revenues
3,763
2,157
Total revenue
247,666
244,241
EXPENSES:
Operating expenses
198,840
185,957
Depreciation, depletion and amortization
39,973
39,644
Asset impairment
1,588
1,799
Asset retirement obligations accretion
1,504
1,381
Asset retirement obligations change in estimate
(3,510 )
-
Exploration costs
General and administrative
14,833
11,594
Total operating expenses
253,710
241,143
INCOME (LOSS) FROM OPERATIONS
(6,044 )
3,098
Interest expense (1)
(8,048 )
(13,030 )
Gain on extinguishment of debt
10,000
-
Equity method investment income
1,054
LOSS BEFORE INCOME TAXES
(3,728 )
(8,878 )
INCOME TAX EXPENSE (BENEFIT):
Current
-
(598 )
Deferred
(2,060 )
Total income tax expense (benefit)
(2,658 )
NET LOSS
$ (3,754 )
$ (6,220 )
NET LOSS PER SHARE:
Basic and diluted
$ (0.12 )
$ (0.20 )
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic and diluted
30,614
30,446
(1) Bank interest
$ 8,510
$ 10,653
Non-cash interest:
Change in interest rate swap valuation
(3,026 )
Amortization of debt issuance costs
2,564
2,296
Other
-
Total non-cash interest
(462 )
2,377
Total interest
$ 8,048
$ 13,030
See accompanying notes.
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
OPERATING ACTIVITIES:
Net loss
$ (3,754 )
$ (6,220 )
Deferred income taxes
(2,060 )
Equity income - Sunrise Energy
(364 )
(1,054 )
Cash distribution - Sunrise Energy
-
1,125
Depreciation, depletion and amortization
39,973
39,644
Asset impairment
1,588
1,799
Gain on extinguishment of debt
(10,000 )
-
Loss on sale of assets
Unrealized gain on marketable securities
-
(14 )
Change in fair value of interest rate swaps
(3,026 )
Change in fair value of fuel hedge
(297 )
Amortization of debt issuance costs
2,564
2,296
Asset retirement obligations accretion
1,504
1,381
Asset retirement obligations change in estimate
(3,510 )
-
Stock-based compensation
1,004
1,211
Change in current assets and liabilities:
Accounts receivable
11,166
Inventory
16,964
2,893
Parts and supplies
(1,112 )
2,872
Prepaid income taxes
-
1,562
Prepaid expenses
(5,215 )
-
Accounts payable and accrued liabilities
10,844
(1,405 )
Other
(362 )
(3,048 )
Cash provided by operating activities
$ 47,974
$ 52,576
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
(continued)
INVESTING ACTIVITIES:
Capital expenditures
$ (28,050 )
$ (20,688 )
Proceeds from sale of equipment
Proceeds from sale of marketable securities
-
2,310
Proceeds from maturities of certificates of deposit
-
Investment in Sunrise Energy
-
(113 )
Cash used in investing activities
(27,525 )
(18,190 )
FINANCING ACTIVITIES:
Payments on bank debt
(46,249 )
(49,662 )
Borrowings of bank debt
20,250
7,250
Proceeds from PPP note
-
10,000
Debt issuance costs
(418 )
(1,903 )
Taxes paid on vesting of RSUs
(274 )
(75 )
Dividends
-
(1,236 )
Cash used in financing activities
(26,691 )
(35,626 )
Decrease in cash, cash equivalents, and restricted cash
(6,242 )
(1,240 )
Cash, cash equivalents, and restricted cash, beginning of year
12,071
13,311
Cash, cash equivalents, and restricted cash, end of year
$ 5,829
$ 12,071
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents
$ 2,546
$ 8,041
Restricted cash
3,283
4,030
$ 5,829
$ 12,071
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest
$ 8,720
$ 10,971
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expenses
$ 8,520
$ 1,199
See accompanying notes.
Hallador Energy Company
Consolidated Statement of Stockholders’ Equity
(in thousands)
Additional
Total
Common Stock Issued
Paid-in
Retained
Stockholders'
Shares
Amount
Capital
Earnings
Equity
BALANCE, DECEMBER 31, 2019
30,420
$
$ 102,215
$ 89,011
$ 191,530
Stock-based compensation
-
-
1,211
-
1,211
Stock issued on vesting of RSUs
(1 )
-
-
Taxes paid on vesting of RSUs
(80 )
-
(75 )
-
(75 )
Dividends
-
-
-
(1,236 )
(1,236 )
Net loss
-
-
-
(6,220 )
(6,220 )
Other
-
BALANCE, DECEMBER 31, 2020
30,610
103,399
81,555
185,260
Stock-based compensation
-
-
1,004
-
1,004
Stock issued on vesting of RSUs
(3 )
-
-
Taxes paid on vesting of RSUs
(121 )
(1 )
(274 )
-
(275 )
Net loss
-
-
-
(3,754 )
(3,754 )
BALANCE, DECEMBER 31, 2021
30,785
104,126
77,801
182,235
See accompanying notes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Consolidation
The consolidated financial statements include the accounts of Hallador Energy Company (hereinafter known as, “we, us, or our”) and its wholly owned subsidiaries Sunrise Coal, LLC (Sunrise) and Hourglass Sands, LLC (Hourglass), and Sunrise’s wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Sunrise is engaged in the production of steam coal from mines located in western Indiana.
Going Concern - Alleviation of Substantial Doubt
In accordance with ASU 2014-15, Presentation of Financial Statements- Going Concern (Subtopic 205-40) - Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern, we are required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about our ability to continue as a going concern within one year after the date that our financials are issued. When management identifies conditions or events that raise substantial doubt about their ability to continue as a going concern it should consider whether its plans to mitigate those relevant conditions or events will alleviate the substantial doubt. If conditions or events raise substantial doubt about an entity’s ability to continue as a going concern, but the substantial doubt is alleviated as a result of management’s plans, the entity should disclose information that enables user of financial statements to understand the principal events that raised the substantial doubt, management’s evaluation of the significance of those conditions or events, and management’s plans that alleviated substantial doubt about the entity’s ability to continue as a going concern.
We performed the analysis, and our overall assessment was there were conditions or events, considered in the aggregate as of December 31, 2021, which raised substantial doubt about our ability to continue as a going concern within the next year, but such doubt was adequately mitigated by our plans to address the substantial doubt.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. During our analysis and overall assessment, it became clear that we were likely to violate one or more of our financial covenants due to a step down of our leverage ratio and a step up of our debt service coverage ratio beginning with quarter ending March 31, 2022 due to lower than expected EBITDA, a significant factor in the calculation of both ratios. This factor raised substantial doubt about the Company’s ability to continue as a going concern.
In March 2022, as disclosed in Note 5, the Company executed an amendment to our credit agreement providing relief on the covenants in question until the time our internal projections show that we will again meet the covenants.
Accordingly, the above factors have alleviated substantial doubt about the entity’s ability to continue as a going concern.
Segment Information
The Company’s significant operating segment includes the two Oaktown underground mines located in southwestern Indiana. The Company’s chief operating decision maker (“CODM”) reviews the operating results, assesses performance and makes decisions about allocation of resources to this segment at the mine level, however, we aggregate the results of operations of the mines for reporting purposes since the nature of the product, production process, customer type, product distribution, and long-term economic characteristics at each mine are similar.
Allowance for Doubtful Accounts
The Company evaluates the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables and disputed amounts. Historically, credit losses have been insignificant. At December 31, 2021 and 2020, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.
Inventory
Inventory and parts and supplies are valued at the lower of average cost or net realizable value determined using the first-in first-out method. Inventory costs include labor, supplies, operating overhead, and other related costs incurred at or on behalf of the mining location, including depreciation, depletion, and amortization of equipment, buildings, mineral rights, and mine development costs.
Prepaid expenses
Prepaid expenses include prepaid insurance, prepaid maintenance expense, and a prepaid balance with our primary parts and supplies vendor.
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.
Mining Properties
Mining properties are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase the productivity of the assets are expensed as incurred. Other than land and most mining equipment, mining properties are depreciated using the units-of-production method over the estimated recoverable reserves. Most surface and underground mining equipment is depreciated using estimated useful lives ranging from three to twenty-five 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 mines, including asset retirement obligation assets, or significantly expanding the capacity of existing mines, are capitalized and amortized using the units-of-production method over estimated recoverable reserves.
Asset Retirement Obligations (ARO) - Reclamation
At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to mine development. Obligations are typically incurred when 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 (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 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 $23.5 million to cover ARO.
The table below (in thousands) reflects the changes to our ARO:
Year Ended December 31,
Balance, beginning of year
$ 16,277 $ 15,764
Accretion
1,504 1,381
Change in estimate
(3,510 ) -
Payments
(146 ) (868 )
Balance, end of year
14,125 16,277
Less current portion
(100 ) (100 )
Long-term balance, end of year
$ 14,025 $ 16,177
Interest Rate Swaps
The Company generally utilizes derivative instruments to manage exposures to interest rate risk on long-term debt. The Company enters into 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.
Statement of Cash Flows
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.
Net Income (Loss) per Share
Basic net income (loss) per share is computed on the basis of 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 in the Company’s earnings. Diluted net income (loss) per share is computed on the basis of the weighted average number of shares of common stock plus the effect of dilutive potential common shares outstanding during the period. Dilutive potential common shares include restricted stock units and are included in basic net income (loss) per share, using the two-class method.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual amounts could differ from those estimates. The most significant estimates included in the preparation of the financial statements relate to: (i) deferred income tax accounts, (ii) coal reserves, (iii) depreciation, depletion, and amortization, (iv) estimates relating to interest rate swaps, (v) estimates used in our impairment analysis and measurement of impairments, and (vi) estimates used in the calculation of our asset retirement obligations.
Long-term Contracts
As of December 31, 2021, we are committed to supplying our customers up to a maximum of 20.7 million tons of coal through 2027 of which 16.2 million tons are priced.
For 2021, we derived 95% of our coal sales from five customers, each representing at least 10% of our coal sales. 99% of our accounts receivable was from five customers, each representing more than 10% of the December 31, 2021 balance.
For 2020, we derived 79% of our coal sales from four customers, each representing at least 10% of our coal sales. 87% of our accounts receivable was from four customers, each representing more than 10% of the December 31, 2020 balance.
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.
(2) LONG-LIVED ASSET IMPAIRMENTS
Long-lived assets are reviewed for impairment whenever events or changes in circumstance indicate that the carrying amount of the assets may not be recoverable. The impact of COVID-19 is being monitored closely, but for the years ended December 31, 2021 and 2020, there were no material COVID-19 related impairment charges recorded for long-lived assets.
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. We have estimated the scrap value to be $1.1 million on the carrying value of $2.7 million. The remaining scrap will be sold in 2022.
Hourglass Sands
We recorded an impairment of $2.9 million as of December 31, 2019, due to softness in the pricing of the frac sand market. The impairment included inventory, land, mine development, buildings and equipment and was determined using a market approach. The remaining fair market value of inventory, equipment, and buildings at Hourglass Sands was $1.9 million as of December 31, 2019. Due to the continued regression of the frac sand market, in August 2020, we ceased operations of the plant and recorded an impairment of $1.8 million in the third quarter of 2020, which included the remaining inventory and buildings and which was determined using a market approach.
(3) INVENTORY
Inventory is valued at lower of average cost or net realizable value (NRV). As of December 31, 2021, and December 31, 2020, coal inventory includes NRV adjustments of $3.8 million and $1.6 million, respectively.
(4) OTHER LONG-TERM ASSETS (IN THOUSANDS)
December 31,
Advanced coal royalties
$ 6,678
$ 6,449
Other
1,694
1,809
Total other assets
$ 8,372
$ 8,258
(5) BANK DEBT
On April 15, 2020, we executed an amendment to our credit agreement with PNC, administrative agent for our lenders. The primary purposes of the amendment were to modify the allowable leverage ratio over the term of the loan to increase available liquidity. As a result of the amendment, our maximum annual capital expenditures are limited to $30 million for 2020 and $25 million for each year thereafter with carryover provisions of unused expenditures, and our dividend is suspended until our leverage ratio falls below 2.0X.
On March 25, 2022, we executed another amendment to our credit agreement with PNC to return the allowable leverage ratio and debt service coverage ratio to their December 31, 2021 levels through September 30, 2022, with the debt service coverage ratio waived for March 31, 2022.
During 2021, we reduced our bank debt by $26.0 million through net cash payments, which as of December 31, 2021, was $111.7 million. Bank debt is comprised of term debt ($31.2 million as of December 31, 2021) and a $120.0 million revolver ($80.5 million borrowed as of December 31, 2021). The term debt amortization concludes with the final payment in March 2023. The revolver matures September 2023. 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, 2021, we had additional borrowing capacity of $33.4 million under the revolver and total liquidity of $35.9 million. Our additional borrowing capacity is net of $5.7 million in outstanding letters of credit as of December 31, 2021 that were required to maintain surety bonds. Liquidity consists of our additional borrowing capacity and cash and cash equivalents.
Fees
Unamortized bank fees and other costs incurred in connection with the initial facility and subsequent amendments totaled $7.9 million as of our amendment in April 2020. Additional costs incurred with the April 15, 2020 amendment were $1.9 million. Additional fees of $0.4 million were incurred in May 2021, for a technical amendment related to our entry into the renewable power market. These costs were deferred and are being amortized over the term of the loan. Unamortized costs as of December 31, 2021 and 2020 were $4.0 million and $6.1 million, respectively.
Bank debt, less debt issuance costs, is presented below (in thousands):
December 31,
Current bank debt
$ 25,725
$ 36,750
Less unamortized debt issuance cost
(2,627 )
(2,439 )
Net current portion
$ 23,098
$ 34,311
Long-term bank debt
$ 86,013
$ 100,988
Less unamortized debt issuance cost
(1,346 )
(3,681 )
Net long-term portion
$ 84,667
$ 97,307
Total bank debt
$ 111,738
$ 137,738
Less total unamortized debt issuance cost
(3,973 )
(6,120 )
Net bank debt
$ 107,765
$ 131,618
Covenants
The credit facility includes a Maximum Leverage Ratio (consolidated funded debt / trailing twelve months adjusted EBITDA), calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed the amounts below:
Fiscal Periods Ending
Ratio
December 31, 2021
3.00 to 1.00
March 31, 2022, and each fiscal quarter thereafter
2.50 to 1.00
As of December 31, 2021, our Leverage Ratio of 2.34 was in compliance with the requirements of the credit agreement.
The credit facility also requires a Minimum Debt Service Coverage Ratio (consolidated adjusted EBITDA / annual debt service) calculated as of the end of each fiscal quarter for the trailing twelve months of 1.05 to 1.00 through December 31, 2021, at which time it increases to 1.25 to 1.00 through the maturity of the credit facility.
As of December 31, 2021, our Debt Service Coverage Ratio of 1.11 was in compliance with the requirements of the credit agreement.
Interest Rate
The interest rate on the facility ranges from LIBOR plus 2.75% to LIBOR plus 4.00%, depending on our Leverage Ratio, with a LIBOR floor of 0.50%. We entered into swap agreements to fix the LIBOR component of the interest rate at 2.92% on the declining term loan balance and on $52.7 million of the revolver. At December 31, 2021, we are paying LIBOR at the swap rate of 2.92% plus 3.50% for a total interest rate of 6.42% on the hedged amount ($83.9 million) and 3.5% on the remainder ($27.8 million).
Future Maturities (in thousands):
25,725
86,013
Total
$ 111,738
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 unsecured $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”).
Under the terms of the CARES 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, rent or utility costs, and meet other requirements regarding, among other things, the maintenance of employment and compensation levels. The Company used the PPP Loan proceeds for qualifying expenses and applied for the forgiveness of the PPP Loan in accordance with the terms of the CARES Act.
On July 23, 2021, we received a notification from the Lender that the SBA approved our PPP Loan forgiveness application for the entire PPP Loan balance of $10 million, together with interest accrued thereon. The Lender notified us that the forgiveness payment was received on July 26, 2021. The forgiveness of the PPP Loan is recognized as other income.
The SBA 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 SBA to pursue legal remedies at its discretion.
At December 31, 2020, the PPP loan totaling $10 million is presented as current and long-term liabilities on the condensed consolidated balance sheets based upon the schedule of repayments and excluding any possible forgiveness of the loan.
(6) ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (IN THOUSANDS)
December 31,
Accounts payable
$ 27,835
$ 14,785
Accrued property taxes
2,529
2,566
Accrued payroll
2,413
1,621
Workers' compensation reserve
2,560
2,988
Group health insurance
1,800
1,800
Fair value of interest rate swaps
2,793
Other
3,524
4,856
Total accounts payable and accrued liabilities
$ 41,528
$ 31,409
(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 collectability of consideration is probable. We recognize revenue when we satisfy a performance obligation by transferring control of a good or service to a customer. We utilize the normal purchase normal sales exception for all long-term sales contracts.
Our revenue is derived from sales to customers of coal produced at our facilities. Our customers purchase coal directly from our mine sites and our Princeton Loop, where the sale occurs and where title, risk of loss, and control typically pass to the customer at that point. Our customers arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts, or include a predetermined escalation in price for each year. Price re-opener and index provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary by customer.
Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was recognized based on quality standards that are specified in the coal sales agreement, such as Btu factor, moisture, ash, and sulfur content and can result in either increases or decreases in the value of the coal shipped.
Disaggregation of Revenue
Revenue is disaggregated by 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. 73% and 74% of our coal revenue for the years ended December 31, 2021 and 2020, respectively, was sold to customers in the State of Indiana with the remainder sold to customers in Florida, North Carolina, Kentucky, Georgia, South Carolina, and Tennessee.
Performance Obligations
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 contracts, the customer contracts with us to provide coal that meets certain quality criteria. We consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract, increased or decreased for quality adjustments.
We recognize revenue at a point in time as the customer does not have control over the asset at any point during the fulfillment of the contract. For substantially all of our customers, this is supported by the fact that title and risk of loss transfer to the customer upon loading of the truck or railcar at the mine. This is also the point at which physical possession of the coal transfers to the customer, as well as the right to receive substantially all benefits and the risk of loss in ownership of the coal.
We have remaining performance obligations relating to fixed priced contracts of approximately $588 million, which represent the average fixed prices on our committed contracts as of December 31, 2021. We expect to recognize approximately 85% of this revenue in 2022 and 2023, with the remainder recognized thereafter.
We have remaining performance obligations relating to contracts with price reopeners of approximately $166 million, which represents our estimate of the expected re-opener price on committed contracts as of December 31, 2021. We expect to recognize all of this revenue beginning in 2024.
The tons used to determine the remaining performance obligations are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.
Contract Balances
Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional. Under the typical payment terms of our contracts with customers, the customer pays us a base price for the coal, increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and included in accounts receivable in our consolidated balance sheets. As of January 1, 2020, accounts receivable for coal sales billed to customers was $14.4 million. We do not currently have any contracts in place where we would transfer coal in advance of knowing the final price of the coal sold, and thus do not have any contract assets recorded. Contract liabilities 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 statutory income tax rate of 21%. The reasons for and effects of such differences for the years ended December 31 are below (in thousands):
Expected amount
$ (783 ) $ (1,865 )
State income taxes, net of federal benefit
(767 ) (644 )
Percentage depletion
(1,725 ) (2,154 )
Valuation allowance
3,376 1,275
Stock-based compensation
380 67
PPP loan forgiveness
(2,100 ) -
Return to provision adjustments
1,610 (60 )
Other
35 723
$ 26 $ (2,658 )
The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following at December 31 (in thousands):
Deferred tax assets:
Net operating loss
$ 32,659 $ 24,081
Valuation allowance
(4,651 ) (1,275 )
Capital loss carryforward
- 525
Stock-based compensation
- 179
Other
- 234
Total deferred tax assets
28,008 23,744
Deferred tax liabilities:
Coal properties
(30,368 ) (26,171 )
Investment in partnerships
(484 ) (397 )
Other
(6 ) -
Total deferred tax liabilities
(30,858 ) (26,568 )
Net deferred tax liability
$ (2,850 ) $ (2,824 )
Our effective tax rate (ETR) for 2021 was (1%) compared to 30% for 2020. The tax rate for the years ended December 31, 2021 and 2020 are not predictive of future tax rates. Our ETR differs from the statutory rate due to statutory depletion in excess of tax basis, PPP loan forgiveness, return to provision adjustments, and changes in the valuation allowance. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income taxes.
We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations. We believe that it is more likely than not that the benefit from certain federal and state NOL carryforwards will not be realized. In recognition of this, we have provided a valuation allowance of $4.7 million and $1.3 on the deferred tax assets related to these state NOL carryforwards as of December 31, 2021 and 2020, respectively.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions, to determine whether the positions will be more likely than not be sustained by the applicable tax authority. Tax positions not deemed to meet the more-likely-than-not threshold are not recorded as a tax benefit or expense in the current year. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deduction will be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. While not material, we record any penalties and interest as general and administrative expense. Tax returns filed with the IRS and state entities generally remain subject to examination for three years after filing.
At December 31, 2021, we had approximately $125 million and $158 million of federal and Indiana net operating loss carryforwards (“NOLs”), respectively. These NOLs are available to offset future taxable income. Federal NOLs generated in 2017 and prior years have a carryforward period of 20 years while those generated in 2018 and future years carryforward indefinitely. The federal NOLs generated in pre-2018 years of $56 million can offset 100% of the current years' taxable income. The federal NOLs generated in post 2017 years of $69 million can offset 80% of current 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.
(9) STOCK COMPENSATION PLANS
Restricted Stock Units (RSUs)
The table below shows the number of RSUs available for issuance at December 31, 2021:
Total authorized RSUs in Plan approved by shareholders
4,850,000
Stock issued out of the Plan from vested grants
(3,265,829 )
Non-vested grants
(183,000 )
RSUs available for future issuance
1,401,171
Non-vested grants at December 31, 2019
488,500
Granted - weighted average share price on grant date was $.90
40,000
Vested - weighted average share price on vesting date was $.92
(193,250 )
Forfeited
(11,000 )
Non-vested grants at December 31, 2020
324,250
Granted - weighted average share price on grant date was $2.46.
173,000
Vested - weighted average share price on vesting date was $2.27.
(296,250 )
Forfeited
(18,000 )
Non-vested grants at December 31, 2021
183,000
RSU Vesting Schedule
Vesting Year
RSUs Vesting
183,000
Vested shares had a value of $0.7 million for 2021, and $0.2 million for 2020, on their vesting dates. Under our RSU plan, participants are allowed to relinquish shares to pay for their required statutory income taxes.
The outstanding RSUs have a value of $0.7 million based on the March 21, 2022 closing stock price of $3.74.
For the years ended December 31, 2021 and 2020 stock-based compensation was $1.0 million and $1.2 million, respectively. For 2022 and 2023, based on existing RSUs outstanding, stock-based compensation expense is estimated to be $0.2 million each year.
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.
(10) 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 2,274 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 $16.6 million not including premiums.
Our employee benefit expenses for the years ended December 31 are below (in thousands):
Health benefits, including premiums
$ 13,084 $ 13,173
401(k) matching
1,946 1,797
Deferred bonus plan
698 679
Total
$ 15,728 $ 15,649
Of the amounts in the above table, $15.2 million and $15.0 million are recorded in operating costs and expenses for 2021 and 2020, respectively with the remainder in SG&A.
Our mine employees are also covered by workers’ compensation and such costs for 2021 and 2020, were approximately $2.9 million and $1.9 million, respectively, and are recorded in operating costs and expenses. Workers’ compensation is a no-fault system by which individuals who sustain work-related injuries or occupational diseases are compensated. Benefits and coverage are mandated by each state which includes disability ratings, medical claims, rehabilitation services, and death and survivor benefits. We are partially self-insured for such claims, however, 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.
(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.
Information related to leases was as follows as of December 31 (in thousands):
Operating lease information:
Operating cash outflows from operating leases
$ 199
Weighted average remaining lease term in years
2.21
Weighted average discount rate
6.0 %
Future minimum lease payments under non-cancellable leases as of December 31, 2021 were as follows (in thousands):
Year
Amount
$ 207
Total minimum lease payments
$ 441
Less imputed interest
(17 )
Total operating lease liability
$ 424
As reflected on balance sheet:
Other long-term liabilities
$ 424
At December 31, 2021, we had approximately $424,000 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 seven mining units dispersed over 10 miles. The historical cost of such equipment was approximately $260 million and $269 million as of December 31, 2021 and December 31, 2020, respectively.
Restricted cash of $3.3 million and $4.0 million as of December 31, 2021, and December 31, 2020, respectively, represents cash held and controlled by a third party and is restricted for future workers’ compensation claim payments.
(13) NET LOSS PER SHARE
We compute net loss per share using the two-class method, which is an allocation formula that determines net loss per share for common stock and participating securities, which for us are our outstanding RSUs.
The following table (in thousands, except per share amounts) sets forth the computation of net loss per share:
Year Ended December 31,
Numerator:
Net loss
$ (3,754 ) $ (6,220 )
Less loss allocated to RSUs
35 94
Net loss allocated to common shareholders
$ (3,719 ) $ (6,126 )
Denominator:
Weighted average number of common shares outstanding
30,614 30,446
Net loss per share:
Basic and diluted
$ (0.12 ) $ (0.20 )
(14) 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 are Level 1 instruments.
Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. 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 fuel hedges, interest rate swaps, and impairment measurements. The fair values of our hedges and swaps were estimated using discounted cash flow calculations based upon forward fuel prices and interest-rate yield curves. The notional values of our two interest rate swaps were $53 million and $31 million as of December 31, 2021, both with maturities of May 2022. Although we utilize third-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 also recorded impairments during Q3 of 2021 and Q4 of 2021 which incorporate Level 3 non-recurring fair value measures as further discussed in Note 2. Certain properties' asset retirement obgligation liabilities use Level 3 non-recurring fair value measures which are discussed in Note 1.
The following table summarizes our financial assets and liabilities measured on a recurring basis at fair value at December 31, 2021 and 2020 by respective level of the fair value hierarchy (in thousands):
Level 1
Level 2
Level 3
Total
December 31, 2021
Liabilities:
Interest rate swaps
- - 867 867
$ - $ - $ 867 $ 867
December 31, 2020
Liabilities:
Fuel hedge
$ - $ - $ 297 $ 297
Interest rate swaps
- - 3,893 3,893
$ - $ - $ 4,190 $ 4,190
The table below highlights the change in fair value of the fuel hedges and interest rate swaps which are based on a discounted future cash flow model (in thousands):
Ending balance, December 31, 2019
$ (3,800 )
Change in estimated fair value
(390 )
Ending balance, December 31, 2020
(4,190 )
Change in estimated fair value
3,323
Ending balance, December 31, 2021*
$ (867 )
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*Recorded in accounts payable and accrued liabilities and other liabilities in the Balance Sheet to these Consolidated Financial Statements.
(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. The carrying value of the investment included in our consolidated balance sheets as of December 31, 2021 and 2020 was $3.5 million and $3.2 million, respectively.
Sunrise Energy plans to develop and explore for oil, gas, and coal-bed methane gas reserves on or near our underground coal reserves.
(16) HOURGLASS SANDS
In February 2018, we invested $4 million in Hourglass Sands, LLC (Hourglass), a frac sand mining company in the State of Colorado. We own 100% of the Class A units and are consolidating the activity of Hourglass in these statements. Class A units are entitled to 100% of profit until our capital investment and interest is returned, then 90% of profits are allocated to us with remainder to Class B units. We do not own any Class B units.
In February 2018, a Yorktown company associated with one of our directors also invested $4 million in Hourglass in return for a royalty interest in Hourglass. This investment coupled with our $4 million investment brings the initial capitalization of Hourglass to $8 million. We report the royalty interest as a redeemable noncontrolling interest in the consolidated balance sheets. A representative of the Yorktown company holds a seat on the board of managers, and, with a change of control, the Yorktown company may be entitled to receive a portion of the net proceeds realized, as prescribed in the Hourglass operating agreement.
In December 2019, we recorded an impairment to Hourglass Sands of $2.9 million. In August 2020, we ceased operation of the plant and recorded an additional impairment of $1.8 million. See Note 2 to these consolidated financial statements for further discussion.
(17) SUBSEQUENT EVENTS
As announced in our Form 8-K filed on February 18, 2022, on February 14, 2022, Hallador Energy Company, through its subsidiary Hallador Power Company, LLC, entered into an Asset Purchase Agreement (the "Purchase Agreement") to acquire Hoosier Energy’s 1-Gigawatt Merom Generating Station, located in Sullivan County, Indiana, in return for assuming certain decommissioning costs and environmental responsibilities. The transaction, which includes a 3.5-year power purchase agreement (PPA), is scheduled to close in mid- July 2022 upon obtaining required governmental and financial approvals.
On March 25, 2022, we executed an amendment to our credit agreement with PNC as discussed in Note 5 to these consolidated financial statments.

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

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES.
Disclosure Controls
We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our CEO and CFO as appropriate to allow timely decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.
Internal Control Over Financial Reporting (ICFR)
Our management, including our CEO and CFO, is responsible for establishing and maintaining adequate ICFR. Our ICFR is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles in the United States. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Management evaluated the effectiveness of our ICFR based on the framework in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in 2013.
Our management evaluated, with the participation of our CEO and CFO, the effectiveness of our ICFR as of December 31, 2021. Based on that evaluation, our management concluded that our ICFR was effective at December 31, 2021.
There were no significant changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2021 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
On March 25, 2022, 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 return the allowable leverage ratio and debt service coverage ratio to their December 31, 2021 levels through September 30, 2022, with the debt service coverage ratio waived for March 31, 2022.
The interest rate per the amendment ranges from LIBOR plus 2.75% to LIBOR plus 4.00%, with a LIBOR floor of 0.50%, depending on the Company’s leverage ratio. The Company expects the interest rate to be LIBOR plus 3.50% for 2022.
A copy of the credit agreement is filed herewith as Exhibit 10.10 to this Form 10-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

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ITEM 11. EXECUTIVE COMPENSATION

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
See Item 8 for an index of our financial statements.
Our exhibit index is as follows:
3.1
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009. (1)
3.2
By-laws of Hallador Energy Company, effective December 24, 2009 (2)
4.1
Description of Securities (3)
10.1
2009 Stock Bonus Plan (4)*
10.2
Third Amended and Restated Credit Agreement dated May 21, 2018 (5)
10.3
Second Amendment to the Third Amended and Restated Credit Agreement as of September 30, 2019 (6)
10.4 Third Amendment to the Third Amended and Restated Credit Agreement and Waiver (7)
10.5 US SBA Loan (PPP) dated April 16, 2020 (7)
10.6 Amended and Restated Hallador Energy Company 2008 Restricted Stock Unit Plan (8)
10.7
Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement* (8)
10.8 Hallador Energy Company 2020 Compensation Plan adopted March 5, 2020 *(9)
10.9 Asset and Purchase Agreement dated February 14, 2022 (10)
10.10 Sixth Amendement to the Third Amended and Restated Credit Agreement dated March 25, 2022 (12)
Code of Ethics for Senior Financial Officers (11)
21.1
List of Subsidiaries (12)
23.1
Consent of Plante & Moran, PLLC (12)
31.1
SOX 302 Certification - President and CEO (12)
31.2
SOX 302 Certifications - CFO (12)
31.3
SOX 302 Certifications - CAO (12)
SOX 906 Certification (12)
Mine Safety Disclosure (12)
101.INS* Inline XBRL Instance Document (12)
101.SCH* Incline XBRL Schema Document (12)
101.CAL* Inline XBRL Calculation Linkbase Document (12)
101.LAB* Inline XBRL Labels Linkbase Document (12)
101.PRE* Inline XBRL Presentation Linkbase Document (12)
101.DEF* Inline XBRL Definition Linkbase Document (12)
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 dated June 29, 2020
(3) IBR to Form 10-K dated March 9, 2020
(4)
IBR to Form S-8 dated December 1, 2009
(5)
IBR to Form 10-Q dated August 6, 2018
(6)
IBR to Form 10-Q dated November 4, 2019
(7) IBR to Form 10-Q dated May 11, 2020
(8)
IBR to Form DEF 14A dated April 11, 2017
(9)
IBR to Form 10-K/A dated June 12, 2020
(10) IBR to Form 8-K/A dated March 11, 2022
(11)
IBR to Form 10KSB dated April 14, 2006
(12) Filed herewith.
* Management Agreements