UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
☒
☐
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2020 OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-3473
“COAL KEEPS YOUR LIGHTS ON”
“COAL KEEPS YOUR LIGHTS ON”
HALLADOR ENERGY COMPANY
(www.halladorenergy.com)
Colorado
(State of incorporation)
1183 East Canvasback Drive, Terre Haute, Indiana
(Address of principal executive offices)
Issuer’s telephone number: 812.299.2800
Securities registered pursuant to Section 12(b) of the Act:
84-1014610
(IRS Employer Identification No.)
47802
(Zip Code)
Title of each class
Common Stock, $0.01 par value per share
Trading Symbol(s)
HNRG
Name of each exchange on which registered
Nasdaq Capital Market
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ☐ No ☑
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405
of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth
company. See the definitions of "larger accelerated filer," "accelerated filer", "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act.
☐ Large accelerated filer
☑ Non-accelerated filer
☐ Accelerated filer
☑ Smaller reporting company
☐ Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial
accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting
under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
The aggregate market value of the common stock held by non-affiliates (public float) on June 30, 2020 was $13,999,757 based on the closing price reported that date by the
NASDAQ of $.66 per share.
As of March 4, 2021, we had 30,612,572 shares outstanding. Our Annual Meeting of Shareholders will be held on June 3, 2021 in Terre Haute, IN.
FORWARD-LOOKING STATEMENTS
Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.” These statements are based on our beliefs as
well as assumptions made by, and information currently available to us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,”
“expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to
our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements
reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business
risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the
forward-looking statements are:
● the severity, magnitude and duration of the COVID-19 pandemic, including impacts of the pandemic and of businesses' and governments' responses to the
pandemic on our operations and personnel, and on demand for coal, the financial condition of our customers and suppliers, available liquidity and capital
sources and broader economic disruptions;
● changes in macroeconomic and market conditions and market volatility arising from the COVID-19 pandemic, including coal, oil, natural gas and natural gas
liquids prices, and the impact of such changes and volatility on our financial position;
● the effectiveness or lack of effectiveness in distributed vaccines to reduce the impact of COVID-19;
● changes in competition in coal markets and our ability to respond to such changes;
● changes in coal prices, demand, and availability which could affect our operating results and cash flows;
● risks associated with the expansion of our operations and properties;
● legislation, regulations, and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases,
mining, miner health and safety, and health care;
● deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;
● dependence on significant customer contracts, including renewing customer contracts upon expiration of existing contracts;
● changing global economic conditions or in industries in which our customers operate;
● recent action and the possibility of future action on trade made by the United States and foreign governments;
● the effect of changes in taxes or tariffs and other trade measures;
● liquidity constraints, including those resulting from any future unavailability of financing;
● customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform;
● customer delays, failure to take coal under contracts or defaults in making payments;
● adjustments made in price, volume or terms to existing coal supply agreements;
● changes in oil & gas prices, which could, among other things, affect our investments in oil & gas mineral interests;
● our productivity levels and margins earned on our coal sales;
● changes in raw material costs;
● changes in the availability of skilled labor;
● our ability to maintain satisfactory relations with our employees;
● increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers’ compensation claims;
● increases in transportation costs and risk of transportation delays or interruptions;
● operational interruptions due to geologic, permitting, labor, weather-related or other factors;
● risks associated with major mine-related accidents, mine fires, mine floods or other interruptions;
● results of litigation, including claims not yet asserted;
● difficulty maintaining our surety bonds for mine reclamation;
● decline in or change in the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and
combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels;
● difficulty in making accurate assumptions and projections regarding post-mine reclamation;
● uncertainties in estimating and replacing our coal reserves;
● the impact of current and potential changes to federal or state tax rules and regulations, including a loss or reduction of benefits from certain tax deductions
and credits;
● difficulty obtaining commercial property insurance;
● evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees,
insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;
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● difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not
control;
● other factors, including those discussed in “Item 1A. Risk Factors”; and
● investors' and other stakeholders' increasing attention to environmental, social and governance
("ESG") matters.
If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from
those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in
“Item 1A. Risk Factors” below. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We
disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or
developments, unless required by law.
You should consider the information above when reading any forward-looking statements contained in this Annual Report on Form 10-K; other reports filed by us
with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website http://www.halladorenergy.com and written or oral statements made by
us or any of our officers or other authorized persons acting on our behalf.
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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:
● employee health and safety;
● 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.
Capital 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 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.
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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 U.S. for 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 and other factors can result in the issuance of various types of
orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties. FMSHA also
contains criminal liability provisions. For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order or carry
out violations of the FMSHA, or its mandatory health and safety standards.
The Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) significantly amended the FMSHA, imposing more extensive and
stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal
oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety
of topics, including:
● sealing off abandoned areas of underground coal mines;
● mine safety equipment, training, and emergency reporting requirements;
● substantially increased civil penalties for regulatory violations;
● training and availability of mine rescue teams;
● underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
● flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and
● post-accident two-way communications and electronic tracking systems.
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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. It is uncertain whether
MSHA will present a proposed rule pertaining to exposure of underground miners to diesel exhaust, after completing its evaluation of the comments received.
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.
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 and to some survivors of a miner who dies from
this disease. The BLBA levied a tax on coal sales of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of
the applicable sales price in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease,
and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, the BLBA
provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax. The
Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust
becomes solvent. The Emergency Economic Stabilization Act of 2008 extended these rates through December 31, 2018. On January 1, 2019, the excise tax rates
reverted to their original 1977 statutory levels of $0.50 per ton for underground-mined coal and $0.25 per ton for surface mined coal, but not to exceed 2% of the
applicable sales price. In December 2019, the excise tax rates were increased to their 2018 levels and that rate increase was set to expire on December 31, 2020.
However, in December 2020, the excise tax rate increase was extended another year, through December 31, 2021.
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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 worker’s 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, ~96% of our production capacity involves underground room and pillar
mining (no surface subsidence), and ~4% involves surface mining. We do not engage in either mountain top removal or long-wall mining. SMCRA nevertheless
requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.
SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation
plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable. 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 for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively. The fee is currently
scheduled to be in effect until September 30, 2021 and requires Congressional action to reauthorize. 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.
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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 us and our competitors to secure new surety bonds without posting collateral and in
some cases it is unclear what level of collateral will be required.
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:
● 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.
● 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 are 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.
● 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.
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● 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 has signed executive orders recommitting the United States to the agreement and calling for the federal government to begin
formulating the United States’ nationally determined emissions reduction targets under the agreement. However, the impact of these orders, and the terms of any
legislation or regulation to implement the United States’ commitment under the Paris Agreement, remain 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.
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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 NSPS that constrain the GHG emissions of fossil-fuel-fired power plants. Most recently, 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. In October 2017 the EPA proposed to repeal the CPP. The EPA subsequently
proposed the 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, though the case is not yet final, and we cannot predict the final outcome.
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 of and challenges to the permitting of new fossil fuel infrastructure, including coal-fired power plants and pipelines, by
environmental organizations and state regulators for concerns related to GHG emissions. For instance, various state regulatory authorities have rejected the
construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future
laws limiting the emissions of carbon dioxide. In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been
appealed to the EPA’s Environmental Appeals Board. In addition, over thirty states have currently adopted “renewable energy standards” or “renewable portfolio
standards,” which encourage or require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date.
Several states have announced their intent to have renewable energy comprise 100% of their electric generation portfolio. Other states may adopt similar
requirements, and federal legislation is a possibility in this area. To the extent these requirements affect our current and prospective customers, they may reduce the
demand for fossil fuel energy, and may affect long-term demand for our coal. Finally, while the U.S. Supreme Court has held that federal common law provides no
basis for public nuisance claims against utilities due to their carbon dioxide emissions, the Court did not decide whether similar claims can be brought under state
common law. As a result, despite this favorable ruling, tort-type liabilities remain a concern.
In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before
granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act (“NEPA”). These
groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In 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; however, these regulations may be subject to further regulation under the Biden
Administration.
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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 northeastern states and Canadian provinces have joined RGGI as participants or
observers.
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, as of 2020, 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, an operator 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, and in 2009, the EPA began reviewing Section 404 permits issued by the Corps of Engineers for coal mining
in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various
initiatives launched by the EPA regarding these permits.
The EPA also has statutory “veto” power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will
have an “unacceptable adverse effect.” In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a previously issued permit for Spruce
No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such
power was exercised with regard to a previously permitted coal mining project which veto was subsequently upheld by the D.C. Circuit Court 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 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.
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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. It is also possible that the Biden Administration could propose a broader definition of WOTUS. Should any rule expanding the definition of
what constitutes a water of the United States take effect a result of the EPA and the Corps of Engineers' rulemaking process, we could face increased costs and
delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.
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.
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. 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. 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.
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Other Environmental, Health and Safety Regulations
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 principle supplier; however, supplier competition continues to develop.
Illinois Basin (ILB)
The coal industry underwent a significant transformation in the early 1990s, as greater environmental accountability was established in the electric utility industry.
Through the U.S. Clean Air Act, acceptable baseline levels were established for the release of sulfur dioxide in power plant emissions. In order to comply with the
new law, most utilities switched fuel consumption to low-sulfur coal, thereby stripping the ILB of over 50 million tons of annual coal demand. This strategy
continued until mid-2000 when a shortage of low-sulfur coal drove up prices. This price increase combined with the assurance from the U.S. government that the
utility industry would be able to recoup their costs to install scrubbers caused utilities to begin investing in scrubbers on a large scale. With scrubbers, the ILB has re-
opened as a significant fuel source for utilities and has enabled them to burn lower-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.
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Human Capital
As of December 31, 2020, Hallador Energy Company and its subsidiaries employed 690 full-time employees and temporary miners. 644 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 2020 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 incidence rate, injury
severity, violations per inspection day, and significant and substantial citations and compare to the national averages noting that in 2020 we were at or below the
national averages in all four 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 continues to evolve, we will monitor the Center for Disease Control and Prevention (CDC)
guidelines to keep our employees and their families safe. We have taken measures to minimize the spread of germs at our offices and mining locations and educating
our employees on how they can reduce the risk of spreading germs to one another. We have implemented social distancing measures while keeping our employees
informed about health and safety. Management encourages employees to stay home when they are sick and has adapted our sick day policy to promote time off for
illnesses.
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.
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 most of 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 have significantly reduced global
economic activity, resulting in a decline in the demand for coal and other commodities, and negatively impacted our results of operations for 2020. 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, we cannot at this time predict the impact of the global COVID-19
pandemic, or any future pandemic, but any pandemic or similar outbreak could have a material adverse impact on our business, financial position, results of
operations, and/or cash flows.
Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets
could have material adverse impacts on our business and financial condition that we currently cannot predict.
Weakness in global economic conditions or economic conditions in any of the industries we serve or in the financial markets could materially adversely affect our
business and financial condition. For example:
● the demand for electricity in the U.S. and globally may decline if economic conditions deteriorate, which may negatively impact the revenues, margins, and
profitability of our business;
● any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and
● our future ability to access the capital markets may be restricted as a result of future economic conditions, which could materially impact our ability to grow
our business, including development of our coal reserves.
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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 2020, approximately 97% 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 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. 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.
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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 3.50 to 1, which also decreases in future periods further reducing the maximum leverage permitted. On December 31, 2020, our debt service
coverage ratio was 1.22, and our leverage ratio was 2.68. Therefore, we were in compliance with these two ratios.
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Our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.
On December 31, 2020, our bank debt was $137.7 million. Our leverage may:
● adversely affect our ability to finance future operations and capital needs;
● limit our ability to pursue acquisitions and other business opportunities; and
● make our results of operations more susceptible to adverse economic or operating conditions.
Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions, and capitalize on business
opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.
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 SBA continues to develop and issue new and updated guidance regarding the PPP loan application process, including guidance regarding required borrower
certifications and requirements for forgiveness of loans made under the program. We continue to track the guidance as it is released and assess various aspects of its
application as necessary based on the guidance. However, given the evolving nature of the guidance, we cannot give any assurance that the anticipated PPP
loan will be forgiven in whole or in part.
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 has 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 have applied for forgiveness of the entire $10
million of the PPP loan, 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.
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;
● 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.
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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. In addition, declining prices from
an oversupply of coal in the market could reduce our revenues and cash from operations.
Changes in tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.
Certain taxes and fees related to our operations, including the Abandoned Mine Land Reclamation Fund and the Black Lung Excise Tax, are set to expire in 2021.
While the renewal of these taxes and fees would not have a significant impact on our business or results of operations, Congress 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 ~91% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is
affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for
power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled generation has the potential to displace coal-fueled
generation, particularly from older, less efficient coal-powered generators. We expect that many of the new power plants needed in the 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.
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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, President Biden has signed executive orders recommitting the United States
to the agreement and calling for the federal government to begin formulating the United States' nationally determined emissions reduction targets under the
agreement. However, the impact of these orders, and the terms of any legislation or regulation to implement the United States' commitment under the Paris
Agreement, remain unclear at this time.
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, as a number of cities, local governments, and other plaintiffs have sued various fossil
fuels companies in state and federal courts, alleging various legal theories to recover for the impacts of alleged damages from global warming, such as rising sea
levels. Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or
customers by failing to adequately disclose those impacts. Although a number of these lawsuits have been dismissed, others remain pending and the outcome of
these cases remains difficult to predict.
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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. 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. Recently, the Federal Reserve
announced it had joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the
financial sector. Limitation of investments in and financing, bonding, and insurance coverages for fossil-fuel energy companies could adversely affect
mining activities.
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 and/or oil & gas to materially
decline and could cause our costs to increase and adversely affect our revenues and results of operations.
We or our customers could be subject to tort claims based on 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 United States 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.
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.
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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 might 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.
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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.
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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;
● 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.
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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. 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.
24
ITEM 1B. UNRESOLVED STAFF COMMENTS. None.
ITEM 2. PROPERTIES.
See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our mines.
Coal Reserve Estimates
“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of
the reserve determination. “Recoverable” reserves mean coal that is economically recoverable using existing equipment and methods under federal and state laws
currently in effect. “Proven (measured) reserves” are defined by Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops,
trenches, workings, or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement
are spaced so closely, and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves”
are defined by Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves,
but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that
for proven reserves, is high enough to assume continuity between points of observation.
Our reserve estimates are prepared by Scott McGuire, one of our mining engineers. Mr. McGuire is a licensed Professional Engineer in the State of Indiana and
Kentucky and has nineteen years’ experience estimating coal reserves.
Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards,
coal within 1,320’ of a data point is considered to be proven, and coal within 1,320’ to 3,960’ is placed in the Probable category. Only seams greater than 4’ in
thickness are included in our underground reserves. All reserves are stated as a final salable product.
Prior to acquiring coal mineral leases, title abstractors conduct a preliminary title search on the property. This information provides a strong indication of the coal
owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us the rights to explore and mine the property. Prior to
mining, attorneys review the chain of mineral ownership to verify the lessor is the mineral owner. Prior to purchasing coal properties, we follow a similar process.
ITEM 3. LEGAL PROCEEDINGS. None
ITEM 4. MINE SAFETY DISCLOSURES:
Safety is a core value for us and our subsidiaries. As such, we have dedicated a great deal of time, energy, and resources to creating a culture of safety. We are proud
of the mine rescue team at Sunrise Coal, who placed 2nd overall in the National Mine Rescue contest held in Lexington, Kentucky in September 2019. We would
also like to recognize Willie Hamilton, who finished second in the nation on pre-shift and Steve Earle, who was first in Indiana on bench.
See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.
25
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES.
Stock Price Information
Our common stock is traded on the NASDAQ Capital Market under the symbol HNRG, and 30.7% is held by our officers, directors and their affiliates.
At March 1, 2021, we had 248 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.
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.
IMPACT OF COVID-19
We continue to face uncertainty regarding the evolving impact of the COVID-19 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. Below is an outline of some of the actions we have taken to address the challenges the COVID-19 pandemic has brought. We continue
to monitor the ongoing pandemic and note that if conditions deteriorate in the future, it could result in further negative impact on our results of operations, financial
position, and liquidity.
I.
II.
III.
IV.
Sales – The global shelter in place response to the COVID–19 pandemic led to an unexpected and dramatic reduction in power demand, especially during
the second quarter 2020. For example, our largest customer base is the MISO power region, and MISO coal consumption declined 20% during the first half
of 2020 as compared to prior year. The drop in power demand resulted in disruptions in shipments and increases in customers' inventory levels of historic
proportions. Markets should be better in 2021and 2022 driven by an improving economy and higher natural gas prices, and we expect our customers to
return to the market in the next three to nine months. This should lead to sales opportunities starting in back-half 2021 and especially 2022.
Production – COVID-19 affected our cost structure in 2020. At times up to 25% of our workforce was unable to work due to exposure issues. COVID-19
related absenteeism has been on the decline, but we expect some influence on cost through the first half of 2021.
Liquidity and financial flexibility - In Q2 2020, to enhance our liquidity and financial flexibility in response to COVID-19, we amended our credit facility,
suspended our quarterly dividend, and borrowed $10 million under the Paycheck Protection Program.
a.
As of December 31, 2020, our liquidity was $51.8 million and our leverage ratio of 2.68X is within our covenant of 3.50X.
Supply chain and distribution network - To date, we have not seen a material disruption in our access to supplies and equipment needed in the production of
coal. In the second and third quarter of 2020, we experienced delays in rail services primarily due to COVID-19, which improved in the fourth quarter of
2020.
Executive 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.
26
Mining Operations
In February 2020, we decided to permanently close the Carlisle Mine and to focus our efforts on lower-cost operations at Oaktown. Due to unforeseen geologic
conditions and other issues experienced in 2019, cost of producing coal at Carlisle was much higher than anticipated. When considering capital expenses, Carlisle did
not produce positive cash flow in 2019. The decision to permanently close Carlisle was made after a thorough review of future mining conditions, operations and
expected future coal market conditions. After closing Carlisle, we started relocating $23 million of Carlisle equipment and parts inventory that Oaktown will utilize
to reduce future capital expenditures. See Note 2 to our consolidated financial statements for a discussion on the impairment of the Carlisle Mine assets. After the
closure, we continue to operate two underground coal mines and one surface coal mine in southwestern Indiana with the following capacities:
Mine
Location
Oaktown 1*
Oaktown 2*
Ace in the Hole
Total
Oaktown, IN
Oaktown, IN
Clay City, IN
Annual
Tons Capacity
(in millions)
Surface/
Underground
Underground
Underground
Surface
Transportation
CSX, Truck Direct & Truck to NS
CSX, Truck Direct & Truck to NS
Truck to CSX & NS
4.0
4.0
0.1
8.1
* The Oaktown 1 & Oaktown 2 underground mines share a common surface facility.
All mines have the ability to truck coal to our Princeton Rail Loop, located near Princeton, IN, which is located on the NS Railroad.
Our Coal Contracts
In 2020, Sunrise sold 6.0 million tons of coal to 11 power plants in 5 different states across nine different customers. We continue to focus on increasing “Customer
Value”, meaning the total lifetime value of a customer’s business, to add and retain business. We work to increase “Customer Value” by acquiring more customers,
earning more business from existing ones and retaining customers longer. An example of acquiring more customers would be our investment in our Princeton Rail
Loop, which has enabled us to provide transportation flexibility and access to new customers. Though markets are currently challenging, we continue to see
opportunities to increase “Customer Value” over the long run.
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.
During 2019, we derived 70% of our revenue from four customers (8 power plants), with each of the four customers representing at least 10% of our coal sales.
Significant customers in 2020 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE: CNP), Orlando Utility Commission (OUC),
Hoosier Energy, an Indiana electric cooperative, 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 2020 sales, 74% were shipped to locations in the State of Indiana.
27
In Q4 2020, customer coal inventories and natural gas (a competitor to coal) inventory levels were both higher than normal, however, due to extreme winter
conditions in February 2021 inventories have declined. While customers will return to market this year, coal markets are still very challenging due to lingering
effects of 2020, continuing uncertain power demand in 2021 and weak coal export market conditions.
Year
2021
2022
Total
Contracted
tons
(millions)*
Estimated
price
per ton
5.1 $
5.1 $
10.2
39.40
39.25
* 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.
Of significant note, natural gas prices have been increasing since Q4 2020 and dramatically in the weather events of February 2021. Natural gas prices as of February
2021 for balance of year delivery have increased approximately $1.00/mmbtu over February 2020 prices for balance of 2020. Current balance of 2021 Henry Hub gas
prices are over $3.00/mmbtu which puts most coal generation in the money as compared to gas. Depending on how actual gas prices play out will significantly
impact our customers' coal generation and our sales opportunities.
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.
While most of our customer plants are expected to operate many years, Hoosier Energy announced in January 2020 that they intend to close their Merom Generating
Station in 2023. Merom represented 700,000 tons or ~11% of our sales volume in 2020. In addition, other utility customers are currently evaluating their generation
portfolios in light of expected future carbon reduction programs. Some utility customers have proposed shuttering certain plant units or entire plants pending any
final reviews.
Asset Impairment Review
See Note 2 to our consolidated financial statements.
Reserve Table - Controlled Tons (in millions):
Oaktown 1 (assigned)
Oaktown 2 (assigned)
Ace in the Hole (assigned)
Ace in the Hole #2 (unassigned)
Total
Assigned
Unassigned
Tons
Sold*
Annual
Capacity
Proven
Probable
Total
Sulphur #
BTU
2020 Year-End Reserves
3.4
2.1
0.2
—
5.7
4.0
4.0
0.1
—
8.1
38.3
27.3
0.1
1.0
66.7
7.0
7.6
—
—
14.6
6.0
5.6
2.0
3.5
11,500
11,600
11,100
11,100
45.3
34.9
0.1
1.0
81.3
80.3
1.0
81.3
*The table above excludes Carlisle tons sold of 0.3 million.
28
Our assigned underground coal reserves are high sulfur (5.0# – 6.5# SO2) with an average BTU content in the 11,200 -11,600 range. Our reserves have lower
chlorine (<0.12%) than average ILB reserves of 0.22%. Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%. The
relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants. As discussed
below, the Ace surface mine is low sulfur (~2.0# SO2) with an average BTU content of 11,100. We have no metallurgical coal reserves, only steam (thermal) coal
reserves. Below is a discussion of our current projects. Only seams greater than 4 feet in thickness are included in our underground reserves.
Our underground mines are room and pillar mines that utilize developed entries for ventilation and transportation. Continuous miners extract coal from rooms by
removing coal from the seam, leaving pillars to support the roof. Coal haulers are used to transport coal to a conveyor belt for transport to the surface.
Oaktown 1 Mine (underground) – Assigned
We have 45.3 million controlled, salable tons of the Indiana #V coal seam. We began 2020 with 47.9 million tons controlled. After accounting for current year
production, the remaining decrease is a result of revised mining plans relating to tons that were deemed unrecoverable due to geologic conditions. Oaktown 1
reserves are located in Knox County, IN.
Access to the Oaktown 1 Mine is via a 90-foot-deep box cut and a 2,200-foot slope, reaching coal in excess of 375 feet below the surface. In 2017, we added an
elevator 7 miles from the slope allowing miners to enter closer to the active face, thereby reducing unproductive daily travel time.
Oaktown 2 Mine (underground) – Assigned
We have 34.9 million controlled, saleable tons of the Indiana #V coal seam. We began 2020 with 39.0 million controlled tons. After accounting for current year
production, the remaining decrease relates to tons that were deemed unrecoverable due to geologic conditions based on new drilling. Oaktown 2 reserves are located
in both Knox County, Indiana and Lawrence County, Illinois.
Access to the Oaktown 2 Mine is via an 80-foot-deep box cut and a 2,600-foot slope, reaching coal in excess of 400 feet below the surface.
The two Oaktown mines are separated by a sandstone channel. The coal seam thickness ranges from 4 feet to over 9 feet. The Oaktown mines share the same wash
plant which is rated at 1,800 tons per hour. The two mines are connected to a rail loadout that can store two 120 car trains at once and is serviced by the CSX
Railroad and Indiana Railroad. Coal is also transported via truck to customers.
Ace in the Hole Mine (Ace) (surface) – Assigned
We have 0.1 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 to blend with high sulfur coal. Many utilities in the
southeastern U.S. have scrubbers with lower sulfur limits (4.5# SO2) which cannot accept the higher sulfur contents of the ILB (4.5# - 6.5# SO2). Blending high
sulfur coal to a lower sulfur specification enables us to market our high sulfur coals to more customers.
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.
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. Mine development is
expected to begin in early 2022.
29
Bulldog Reserves (underground) – Unassigned
We have leased roughly 19,300 acres in Vermilion County, Illinois near the village of Allerton. Based on our reserve estimates we currently control 30.6 million tons
of coal. A considerable amount of our leased acres has yet to receive any exploratory drilling. See Note 2 to our consolidated financial statements for a discussion
on the impairment of the Bulldog assets.
Unassigned reserves represent coal reserves that would require new mineshafts, mining equipment, and plant facilities before operations could begin on the property.
The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin.
Below is a map that shows the locations of our coal mines.
Railroad Legend:
CSX – CSX Railroad
INRD – Indiana Rail Road
ISRR – Indiana Southern Railroad
NS – Norfolk Southern Railway
30
Mine and Wash Plant Recovery and Capacity
Mine recovery
Wash plant recovery*
(Clean Tons)
Wash Plant Capacity
Oaktown 1
Oaktown 2
_____________________________
* Does not include out-of-seam material extracted during the mining process.
** Oaktown 1 and Oaktown 2 share the wash plant.
Liquidity and Capital Resources
49%
46%
80%
80%
8.0 million**
As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $52.6 million and $38.2 million for the years ended December 31, 2020
and 2019 respectively. Operating cash flow increased due primarily to positive changes in accounts receivable and inventory, which was offset by operating margins
from our coal operations decreasing in 2020 by $13.1 million due mostly to the 2.1 million ton reduction in coal sales. Operating margin per ton increased in 2020 to
$9.49/ton from $8.65/ton in 2019.
Our capital expenditure budget for 2021 is $23 million, of which $9 million is for maintenance capex. With the closure of the Carlisle Mine, equipment and parts
inventories totaling $23 million are being re-deployed to Oaktown and are expected to be fully utilized over the next 6 - 12 months, helping reduce our capital
expenditures in the future. We expect cash from operations for 2021 and the utilization of our revolver, if necessary, to fund our maintenance capital expenditures
and our debt service.
See Note 5 to our consolidated financial statements for discussion about our bank debt amendment in April 2020 and other actions discussed below that were taken in
2020 to improve liquidity as a result of the COVID-19 uncertainty.
Paycheck Protection Program and Payroll Tax Deferral
I.
Due to economic uncertainty as a result of COVID-19, on April 16, 2020, we entered into a promissory note evidencing an unsecured loan in the amount of
$10 million made to the Company under the Paycheck Protection Program (the “Loan”).
a.
As noted previously, uncertainty was created as a result of unexpected sales delays due to the impacts of COVID-19.
i.
ii.
Starting in March and continuing through Q2, sales were 30% lower than expected.
The receipt of funds under the PPP loan allowed the Company to avoid workforce reduction measures amidst a steep decline in revenue and
operating margins.
II.
Prior to the COVID-19 pandemic taking root in the United States, we idled and permanently closed the Carlisle Mine resulting in a reduction in force in Q1
2020.
a.
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. Based on the terms of the loan, after factoring in the
reduction in force prior to our application, we expect the loan to be forgiven following a successful audit by the Small Business Administration
(SBA). In December 2020, we applied for forgiveness of the full $10 million promissory note. On January 8, 2021, we were notified by the Lender
that they had approved the application for the full forgiveness of the $10 million note and had forwarded on to the SBA for final approval. The SBA
has 90 days from receipt of application from the Lender to make its determination as to the amount of forgiveness.
III.
In June 2020, we started to take advantage of the payroll tax deferral offered by the CARES act. We deferred $1.7 million in 2020, which will be due and
payable in two annual installments at the end of 2021 and 2022.
31
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 $16.3 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 totaling $27 million to cover ARO.
Capital Expenditures (capex)
For the year ended December 31, 2020, our capex was $20.7 million allocated as follows (in millions):
Oaktown – maintenance capex
Oaktown – investment
Other
Capex per the Consolidated Statements of Cash Flows
$
$
9.7
10.8
0.2
20.7
Results of Operations
I.
2020 Net Loss of $6.2 million, Adjusted EBITDA of $53.5 million
a.
b.
c.
Sales: 2020 shipments totaled 6.0 million tons. We agreed with our customers to defer 400,000 tons of 2020 shipments to 2021. As part of these
agreements, we were able to extend the term of multiple contracts for additional years.
i.
Coal inventory was reduced by $2.8 million during the year.
Production: 2020 production costs were $31.07/ton. 2019 costs were slightly better at $30.69/ton. Oaktown costs over that same period were $29.84
and $28.35, respectively. We closed the Carlisle Mine in February 2020 due to increased costs and then the COVID-19 pandemic began.
Cash Flow & Debt: We generated $52.6 million in operating cash flow during the year which we utilized to pay down our bank debt by
$42.4 million. We are also expecting the SBA to forgive an additional $10 million by April 8, 2021.
i.
As of December 31, 2020, our bank debt was $137.7 million, bringing our liquidity to $51.8 million and our leverage ratio to 2.68X,
comfortably within our covenant of 3.5X.
Reconciliation of GAAP “net loss” to non-GAAP “adjusted EBITDA” (in thousands), the most comparable GAAP financial measure.
2020
2019
Net loss
Income tax benefit
Loss from Hourglass Sands
(Income) loss from equity method investments
DD&A
Asset impairment
ARO accretion
Loss (gain) on disposal of assets
Unrealized gain on marketable securities
Interest Expense
Other amortization
Change in fair value of fuel hedges
Stock-based compensation
Adjusted EBITDA
$
$
(6,220) $
(2,658)
270
(1,054)
39,636
1,799
1,381
38
(14)
13,030
5,760
322
1,211
53,501 $
(59,854)
(22,347)
540
527
48,554
77,882
1,272
(90)
(593)
15,998
5,039
—
1,833
68,761
Management believes that the presentation of such additional financial measures provides useful information to investors regarding our performance and results of
operations because these measures when used in conjunction with related GAAP financial measures, (i) provide additional information about our core operating
performance and ability to generate and distribute cash flow, (ii) provide investors with the financial and analytical framework upon which management bases
financial, operation, compensation, and planning decisions, and (iii) present measurements that investors, rating agencies, and debt holders have indicated are
useful in assessing our results.
32
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, 2020, 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.
Revenue:
Coal sales
Other
Total revenue
Costs and expenses:
Operating costs and expenses
DD&A
ARO accretion
Coal exploration costs
SG&A
Bank interest
Non-cash interest
Asset Impairment*
Total cost and expenses
Mar-31
2020
Jun-30
2020
Sep-30
2020
Dec-31
2020
Total 2020
$
61,932 $
606
62,538
48,469
10,627
333
253
2,978
2,654
3,060
—
68,374
50,473
1,608
52,081
36,165
10,217
343
208
2,678
2,842
(8)
—
52,445
64,754 $
374
65,128
64,925 $
623
65,548
46,570
9,315
348
174
3,131
2,709
(380)
1,799
63,666
54,753
9,485
357
133
2,807
2,452
(299)
—
69,688
242,084
3,211
245,295
185,957
39,644
1,381
768
11,594
10,657
2,373
1,799
254,173
Income (loss) before income taxes
(5,836)
(364)
1,462
(4,140)
(8,878)
Less income taxes:
Current
Deferred
Total income taxes
Net income (loss)
Net income (loss) per share:
Basic and diluted
Weighted average shares outstanding:
Basic and diluted
(524)
(1,652)
(2,176)
—
(618)
(618)
(74)
(387)
(461)
—
597
597
(3,660) $
254 $
1,923 $
(4,737) $
(598)
(2,060)
(2,658)
(6,220)
(0.12) $
0.01 $
0.06 $
(0.15) $
(0.20)
$
$
30,420
30,423
30,465
30,475
30,446
33
Revenue:
Coal sales
Other
Total revenue
Costs and expenses:
Operating costs and expenses
DD&A
ARO accretion
Coal exploration costs
SG&A
Bank interest
Non-cash interest
Asset Impairment*
Total cost and expenses
Mar-31
2019
Jun-30
2019
Sep-30
2019
Dec-31
2019
Total 2019
$
85,235 $
4,078
89,313
71,113 $
1,197
72,310
82,883 $
213
83,096
78,205 $
538
78,743
62,419
11,738
309
280
2,984
3,012
1,607
—
82,349
54,001
12,096
314
208
3,475
2,933
2,436
—
75,463
71,363
11,778
320
347
2,926
2,801
757
—
90,292
60,083
12,960
329
390
3,463
2,765
(313)
77,882
157,559
317,436
6,026
323,462
247,866
48,572
1,272
1,225
12,848
11,511
4,487
77,882
405,663
Income (loss) before income taxes
6,964
(3,153)
(7,196)
(78,816)
(82,201)
Less income taxes:
Current
Deferred
Total income taxes
Net income (loss)
Net income (loss) per share:
Basic and diluted
Weighted average shares outstanding:
Basic and diluted
(229)
193
(36)
78
113
191
(426)
(3,047)
(3,473)
52
(19,081)
(19,029)
(525)
(21,822)
(22,347)
7,000 $
(3,344) $
(3,723) $
(59,787) $
(59,854)
0.23 $
(0.11) $
(0.12) $
(1.95) $
(1.95)
$
$
30,245
30,245
30,249
30,274
30,253
*Impairment and tax effects primarily related to the decision to idle the Carlisle Mine. See Note 2 to our Consolidated Financial Statements.
34
Quarterly coal sales and cost data follow (in 000’s, except for per ton data and wash plant recovery percentage):
All Mines
Tons produced
Tons sold
Coal sales
Average price/ton
Wash plant recovery in %
Operating costs
Average cost/ton
Margin
Margin/ton
Capex
Maintenance capex
Maintenance capex/ton
All Mines
Tons produced
Tons sold
Coal sales
Average price/ton
Wash plant recovery in %
Operating costs
Average cost/ton
Margin
Margin/ton
Capex
Maintenance capex
Maintenance capex/ton
2020 v. 2019
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1st 2020
2nd 2020
3rd 2020
4th 2020
T4Qs
1,701
1,526
61,932
40.58
$
$
74%
$
$
$
$
$
$
$
48,334
31.67
13,598
8.91
5,999
3,470
2.27
1,468
1,244
50,473
40.57
$
$
76%
$
$
$
$
$
$
$
36,001
28.94
14,472
11.63
4,006
2,578
2.07
1,234
1,585
64,754
40.85
$
$
71%
$
$
$
$
$
$
$
46,444
29.30
18,310
11.55
3,995
1,365
0.86
1,233
1,613
64,925
40.25
$
$
68%
$
$
$
$
$
$
$
54,640
33.87
10,285
6.38
6,661
2,342
1.45
5,636
5,968
242,084
40.56
185,419
31.07
56,665
9.49
20,661
9,755
1.63
1st 2019
2nd 2019
3rd 2019
4th 2019
T4Qs
2,205
2,130
85,235
40.02
$
$
73%
$
$
$
$
$
$
$
62,271
29.24
22,964
10.78
8,840
6,672
3.13
2,003
1,807
71,113
39.35
$
$
71%
$
$
$
$
$
$
$
53,915
29.84
17,198
9.52
9,448
6,164
3.41
1,891
2,118
82,883
39.13
$
$
70%
$
$
$
$
$
$
$
71,372
33.70
11,511
5.43
8,981
5,537
2.61
2,122
2,015
78,205
38.81
$
$
74%
$
$
$
$
$
$
$
60,082
29.82
18,123
8.99
8,264
4,115
2.04
8,221
8,070
317,436
39.34
247,640
30.69
69,796
8.65
35,533
22,488
2.79
For 2020, we sold 5,968,000 tons at an average price of $40.56/ton. For 2019, we sold 8,070,000 tons an average price of $39.34/ton. The increase in average price
per ton is the result of our changing contract mix caused by the expiration of contracts and the acquisition of new contracts.
Operating costs for our coal mines averaged $31.07/ton and $30.69/ton for the years ended December 31, 2020 and 2019, respectively. Oaktown costs over that same
period were $29.84 and $28.35, respectively. We encountered challenging mining conditions at Oaktown 2 in Q4 2020. We expect operating costs for our coal
mines to return to $29-$30/ton in 2021.
Operating costs associated for the idled Prosperity mine were $1.0 million and $1.5 million for the years ending December 31, 2020 and 2019, respectively. We
expect operating costs to be $1.0 million in 2021.
Other operating income decreased $2.8 million in 2020. The largest contributor to this decrease was the sale of overriding royalty interests in certain oil producing
properties for $2.9 million reported in 2019. Our investment in Sunrise Energy contributed $1.1 million to income in 2020 but incurred a loss of $0.5 million 2019.
Other items contributing to the difference include the sale of scrap and other non-producing assets in 2020.
DD&A decreased $8.9 million in 2020. A portion of our assets are depreciated based on raw production which decreased in 2020, thus as production decreases so
does our DD&A.
SG&A expenses decreased $1.3 million in 2020 due to lower payroll, commissions, and consulting fees as sales and project activity have declined due to COVID-
19. We expect SG&A for 2021 to be $12 million.
Our Sunrise Coal employees and contractors totaled 682 at December 31, 2020, compared to 907 at December 31, 2019. The significant reduction is due mostly to
the closure of the Carlisle Mine in February 2020.
35
Signs of Improvement for the Coal Market
I.
Gas prices are increasing.
a.
b.
c.
Nymex gas prices (a competitor to coal) averaged $1.99 in 2020, the lowest average in over two decades. Spot Nymex gas prices on 2/16/21 were
$3.21/mmbtu, a price where Indiana coal plants (74% of our customer base) are dispatching in front of gas plants. Gas prices are higher in nearly
every market as natural gas inventories have moved from a surplus to the 5-year average to a deficit during Q1 2021. Thus, gas markets are rising in
an effort to encourage gas producers to increase production.
Oil and gas rig counts are still anemic. As of February 12, 2021, rig counts are 397 vs. the 2018/2019 peak of 1,085, a 63% decline.
Gas targeted rigs as of October 23, 2020 are 90 vs. the 2018/2019 peak of 198, a 55% decline.
II.
Coal export prices are improving
a.
b.
API 4 (Asia) is ~$80/tonne for 2021, up 17% versus end of Q3 2020.
API 2 (Europe) is ~$66/tonne for 2021, up 10% versus end of Q3 2020.
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, 2020, 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 2020 was 30% compared to 27% for 2019. The tax rate for the years ended December 31, 2020 and 2019 are not predictive of future
tax rates. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis, which is a permanent difference. 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 deferred tax accounts, and the estimates used in our impairment analysis are our only
critical accounting estimates.
The reserve estimates are used in the DD&A calculation and in our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our
DD&A expense and impairment test may be affected.
The fair value of our interest rate swaps is determined using a discounted future cash flow model based on the key assumption of anticipated future interest rates and
related credit adjustment considerations.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in
these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions
and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position.
New Accounting Standards
See “Item 8. Financial Statements – Note 1. Summary of Significant Accounting Policies” for a discussion of new accounting standards.
36
ITEM 8. FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statement of Stockholders’ Equity
Notes to Consolidated Financial Statements
37
38
40
41
42
44
45
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of Hallador Energy Company
Opinion on the Financial Statements
We have audited the accompanying balance sheets of Hallador Energy Company (the “Company”) as of December 31, 2020, and 2019, the related statements of
operations, cash flows, and stockholders' equity for each of the years in the two-year period ended December 31, 2020, 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, 2020, and 2019, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31,
2020, 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 Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to
be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially
challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken
as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or
disclosures to which they relate.
The Impact of Proven and Probable Reserves on Mining Properties - Refer to Note 1 to the financial statements.
Critical Audit Matter Description
The Company’s net property, plant and equipment balance was $309.4 million as of December 31, 2020 and related depreciation, depletion, and amortization was
$39.6 million for the year ended December 31, 2020. These balances, which include mining properties, are recorded at cost. Other than land and most mining
equipment, mining properties are depreciated using the units-of-production method over the estimated recoverable reserves. 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. 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.
We identified the assessment of the impact of proven and probable reserves on mining properties as a critical audit matter as there are significant judgments by
management, including the use and oversight of management’s specialist, when developing the estimate of proven and probable reserves. 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.
38
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 Company’s internal control over financial reporting to identify the types potential misstatement, assess the factors that
affect the risks of material misstatement, and design further audit procedures.
● We evaluated the completeness and accuracy of the underlying information used by management in determining the estimate of proven and probable
reserves by assessing the methodology used in estimating proven and probable reserves by management and its specialist.
● We evaluated the significant assumptions utilized by management in determining its estimate including future coal prices, production costs, capital
expenditures and anticipated timing of extraction by comparison to historical results and the operational status and forecast of the related mine.
● We evaluated the work of management’s specialist by analyzing their objectivity, experience, and qualifications.
● We analyzed the depreciation, depletion, and amortization calculation for compliance with authoritative guidance, and recalculated it.
Income taxes and Uncertain Tax Positions - Refer to Notes 1 and 9 to the financial statements.
Critical Audit Matter Description
The Company’s net deferred income tax liability was $2.8 million as of December 31, 2020 and the related total income tax benefit was $2.7 million for the year
ended December 31, 2020. 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. Filing positions in all of the federal and state jurisdictions where the Company is required to file income tax returns are
analyzed by the Company, 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 income taxes and uncertain tax positions as a critical audit matter due to the multiple jurisdictions in which the Company operates, the industry in
which the Company operates in, and the complexity of tax laws and regulations. Performing audit procedures and evaluating audit evidence obtained related to
these considerations 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 Company’s internal control over financial reporting to identify the types potential misstatement, assess the factors that
affect the risks of material misstatement, and design further audit procedures.
● We evaluated the completeness and accuracy of deferred income taxes and the income tax provision by agreement to material tax filings.
● We assessed the reasonableness of the various judgments and estimates inherent in management’s assessment of their tax obligation and uncertain tax
positions, including analysis over forecasts and tax elections.
● We involved our tax specialists with our evaluation of management’s judgments related uncertain positions by analyzing the related tax law, statutes, and
regulations and their application to the Company’s positions.
● We evaluated the assumptions and estimates used by management in the context of other audit evidence obtained during the audit.
/S/PLANTE & MORAN, PLLC
We have served as the Company’s auditor since 2003.
Denver, Colorado
March 8, 2021
39
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
Consolidated Balance Sheets
As of December 31,
(in thousands)
2020
2019
PART I - FINANCIAL INFORMATION
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash
Certificates of deposit
Accounts receivable
Prepaid income taxes
Inventory
Parts and supplies
Prepaid expenses
Total current assets
Property, plant and equipment, at cost:
Land and mineral rights
Buildings and equipment
Mine development
Total property, plant and equipment, at cost
Less - accumulated DD&A
Total property, plant and equipment, net
Investment in Sunrise Energy
Other assets
Total assets
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS, AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net
Current portion of PPP note
Accounts payable and accrued liabilities
Total current liabilities
Long-term liabilities:
Bank debt, net
PPP note
Deferred income taxes
Asset retirement obligations
Other
Total long-term liabilities
Total liabilities
Redeemable noncontrolling interests
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
Common stock, $.01 par value, 100,000 shares authorized; 30,610 and 30,420 issued and outstanding, respectively
Additional paid-in capital
Retained earnings
Total stockholders’ equity
Total liabilities, redeemable noncontrolling interests, and stockholders’ equity
$
See accompanying notes.
40
$
$
$
8,041 $
4,030
—
14,414
—
24,663
8,903
3,282
63,333
115,853
352,115
93,635
561,603
(252,245)
309,358
3,181
8,258
384,130 $
34,311 $
5,490
31,409
71,210
97,307
4,510
2,824
16,177
2,842
123,660
194,870
4,000
—
306
103,399
81,555
185,260
384,130 $
8,799
4,512
245
25,580
1,562
28,297
11,775
1,678
82,448
114,722
351,614
84,160
550,496
(220,780)
329,716
3,139
10,324
425,627
33,044
—
31,800
64,844
140,594
—
4,884
15,694
4,081
165,253
230,097
4,000
—
304
102,215
89,011
191,530
425,627
Hallador Energy Company
Consolidated Statements of Operations
For the years ended December 31,
(in thousands, expect per share data)
REVENUE AND OTHER INCOME:
Coal sales
Other operating income
Total revenue and other income
COSTS AND EXPENSES:
Operating costs and expenses
DD&A
ARO accretion
Exploration costs
SG&A
Interest (1)
Asset impairment
Total costs and expenses
LOSS BEFORE INCOME TAXES
INCOME TAX BENEFIT:
Current
Deferred
Total income tax benefit
NET LOSS
NET LOSS PER SHARE:
Basic and diluted
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic and diluted
(1) Bank interest
Non-cash interest:
Change in interest rate swap valuation
Amortization of debt issuance costs
Other
Total non-cash interest
Total interest
See accompanying notes.
41
$
$
$
2020
2019
242,084 $
3,211
245,295
185,957
39,644
1,381
768
11,594
13,030
1,799
254,173
317,436
6,026
323,462
247,866
48,572
1,272
1,225
12,848
15,998
77,882
405,663
(8,878)
(82,201)
(598)
(2,060)
(2,658)
(6,220) $
(525)
(21,822)
(22,347)
(59,854)
(0.20) $
(1.95)
30,446
30,253
$
10,653 $
68
2,296
13
2,377
13,030 $
$
11,511
2,186
2,095
206
4,487
15,998
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
OPERATING ACTIVITIES:
Net loss
Deferred income taxes
Equity (income) loss – Sunrise Energy
Cash distribution - Sunrise Energy
DD&A
Asset impairment
Loss (gain) on sale of assets
Unrealized gain on marketable securities
Gain on sale of royalty interests in oil properties
Change in fair value of interest rate swaps
Change in fair value of fuel hedge
Amortization and write off of deferred financing costs
Accretion of ARO
Stock-based compensation
Change in current assets and liabilities:
Accounts receivable
Inventory
Parts and supplies
Prepaid income taxes
Accounts payable and accrued liabilities
Other
Cash provided by operating activities
42
2020
2019
(6,220) $
(2,060)
(1,054)
1,125
39,644
1,799
38
(14)
—
68
322
2,296
1,381
1,211
11,166
2,893
2,872
1,562
(1,405)
(3,048)
52,576 $
(59,854)
(21,822)
527
—
48,572
77,882
(90)
(593)
(2,949)
2,186
—
2,095
1,272
1,833
(7,312)
(8,603)
(2,130)
1,044
3,608
2,577
38,243
$
$
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
(continued)
INVESTING ACTIVITIES:
Capital expenditures
Proceeds from sale of royalty interests in oil properties
Proceeds from sale of equipment
Proceeds from sale of marketable securities
Proceeds from maturities of certificates of deposit
Investment in Sunrise Energy
Cash used in investing activities
FINANCING ACTIVITIES:
Payments on bank debt
Borrowings of bank debt
Proceeds from PPP note
Deferred financing costs
Taxes paid on vesting of RSUs
Dividends
Cash used in financing activities
Decrease in cash, cash equivalents, and restricted cash
Cash, cash equivalents, and restricted cash, beginning of year
Cash, cash equivalents, and restricted cash, end of year
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents
Restricted cash
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense
Right-of-use assets acquired by operating lease
See accompanying notes.
43
$
$
$
$
$
$
2020
2019
(20,688) $
—
56
2,310
245
(113)
(18,190)
(49,662)
7,250
10,000
(1,903)
(75)
(1,236)
(35,626)
(1,240)
13,311
12,071 $
8,041 $
4,030
12,071 $
(35,533)
2,949
134
2,007
245
—
(30,198)
(42,063)
33,750
—
(1,192)
(358)
(4,965)
(14,828)
(6,783)
20,094
13,311
8,799
4,512
13,311
10,791 $
11,639
1,199 $
—
5,849
800
BALANCE, DECEMBER 31, 2018
Stock-based compensation
Stock issued on vesting of RSUs
Taxes paid on vesting of RSUs
Dividends
Net loss
BALANCE, DECEMBER 31, 2019
Stock-based compensation
Stock issued on vesting of RSUs
Taxes paid on vesting of RSUs
Dividends
Net loss
Other
BALANCE, DECEMBER 31, 2020
Hallador Energy Company
Consolidated Statement of Stockholders’ Equity
(in thousands)
Common Stock Issued
Shares
Amount
Paid-in
Capital
Retained
Earnings
Additional
Total
Stockholders'
Equity
30,245 $
—
297
(122)
—
—
30,420
—
193
(80)
—
—
77
30,610
302 $
0
2
—
—
—
304
—
1
—
—
—
1
306
100,742 $
1,833
(2)
(358)
—
—
102,215
1,211
(1)
(75)
—
—
49
103,399
153,830 $
—
—
—
(4,965)
(59,854)
89,011
—
—
—
(1,236)
(6,220)
—
81,555
254,874
1,833
—
(358)
(4,965)
(59,854)
191,530
1,211
—
(75)
(1,236)
(6,220)
50
185,260
See accompanying notes.
44
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.
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, 2020 and 2019, 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.
45
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 (proved and probable) reserves. We
are using credit-adjusted risk-free discount rates ranging from 5.0% to 10% to discount the obligation. 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. In the event we are not able to perform reclamation, we have surety bonds totaling $27 million to cover ARO.
The table below (in thousands) reflects the changes to our ARO:
Balance, beginning of year
Accretion
Revisions
Payments
Balance, end of year
Less current portion
Long-term balance, end of year
Interest Rate Swaps
Year Ended December 31,
2019
2020
15,764 $
1,381
—
(868)
16,277
(100)
16,177 $
14,646
1,272
95
(249)
15,764
(70)
15,694
$
$
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 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.
46
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, and (v) estimates used in our impairment analysis and measurement of impairments.
Long-term Contracts
As of December 31, 2020, we are committed to supplying our customers up to a maximum of 21.6 million tons of coal through 2027 of which 13.7 million tons are
priced.
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.
For 2019, we derived 70% of our coal sales from four customers, each representing at least 10% of our coal sales. 68% of our accounts receivable was from
three customers, each representing more than 10% of the December 31, 2019 balance.
Stock-based Compensation
Stock-based compensation 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 year ended December 31, 2020, there were no material COVID-19 related impairment charges
recorded for long-lived assets.
Carlisle Mine
Due to softness in the market in Q4 2019 and the elevated cost structure of the Carlisle Mine, we made the decision to idle the Carlisle Mine during Q4 2019 with the
intent to recommence production in 2020, and accordingly, we conducted an evaluation of impairment on the Carlisle Mine utilizing a discounted future cash flow
model using the income approach. We utilized a discount rate of 10% in discounting the estimated cash flows. Other key assumptions included the anticipated
demand of overall tons of coal over the remaining life of the mine, the average selling price per ton of coal, operating cost per ton and expected future capital
expenditures to support the anticipated production levels. We also assessed the impairment based upon the potential closure of the mine which was being
contemplated at the time and considered both scenarios in determining the amount of impairment at December 31, 2019. Based on our review, we recorded an
impairment of $65.7 million related to the Carlisle Mine as of December 31, 2019, which included buildings, land, rail, mine development, equipment, and advanced
royalties. Buildings, land, and rail were impaired to their estimated salvage value. The remaining salvage value of land and buildings at the Carlisle Mine
was estimated at $1.8 million as of December 31, 2019. The fair value of the assets used in our impairment assessment was determined using a market approach based
on recent sales of similar property. Subsequent to year end during late Q1 2020 we determined that it was economically prudent to permanently close the Carlisle
Mine. Equipment totaling $23 million is being redeployed and utilized at the Oaktown mines. No additional impairment costs were recorded during 2020 as a result of
the decision to close the Carlisle Mine. Exit and disposal costs to close the mine were $1.1 million, which were recorded as current period costs in Q1 and Q2
of 2020. We also evaluated whether the closure of the Carlisle Mine should be considered a discontinued operation and concluded while the mine does have discrete
separately identifiable cashflows a strategic shift in our business had not occurred therefore the closure of the mine was not considered a discontinued operation under
ASC 205-20.
Bulldog Reserves
As a result of the Carlisle Mine impairment, we determined that an impairment of the Bulldog Reserves was also necessary. With the closure of the Carlisle Mine, it
became apparent that the likelihood of construction and opening of Bulldog was reduced. Based on our review, we recorded an impairment of $9.2 million as of
December 31, 2019, which included land and advanced royalties, and was a complete impairment of all assets.
47
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, 2020, and December 31, 2019, coal inventory includes NRV
adjustments of $1.6 million and $2.0 million, respectively.
(4) OTHER LONG-TERM ASSETS (IN THOUSANDS)
Advanced coal royalties
Marketable equity securities available for sale, at fair value (restricted)*
Other
Total other assets
* Held by Sunrise Indemnity, Inc., our wholly owned captive insurance company.
(5) BANK DEBT
December 31,
2020
2019
6,449 $
—
1,809
8,258 $
6,105
2,296
1,923
10,324
$
$
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, and our dividend is suspended until our leverage ratio falls below 2.0X.
During 2020, we reduced our bank debt by $42.4 million, which as of December 31, 2020 was $137.7 million. Bank debt is comprised of term debt ($68 million as
of December 31, 2020) and a $120 million revolver ($69.7 million borrowed as of December 31, 2020). 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, 2020, we had additional borrowing capacity of $43.8 million under the revolver and total liquidity of $51.8 million. Our additional borrowing
capacity is net of $5.7 million in outstanding letters of credit as of December 31, 2020 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. These costs were deferred and are being amortized over the term of the loan. Unamortized costs as of December 31, 2020 and 2019 were $6.1 million and
$6.5 million, respectively. Additional costs incurred with the April 15 amendment were $1.9 million.
48
Bank debt, less debt issuance costs, is presented below (in thousands):
Current bank debt
Less unamortized debt issuance cost
Net current portion
Long-term bank debt
Less unamortized debt issuance cost
Net long-term portion
Total bank debt
Less total unamortized debt issuance cost
Net bank debt
Covenants
December 31,
2020
2019
36,750 $
(2,439)
34,311 $
100,988 $
(3,681)
97,307 $
137,738 $
(6,120)
131,618 $
34,912
(1,868)
33,044
145,238
(4,644)
140,594
180,150
(6,512)
173,638
$
$
$
$
$
$
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
December 31, 2020
March 31, 2021 and June 30, 2021
September 30, 2021 and December 31, 2021
March 31, 2022 and each fiscal quarter thereafter
Ratio
3.50 to 1.00
3.25 to 1.00
3.00 to 1.00
2.50 to 1.00
As of December 31, 2020, our Leverage Ratio of 2.68 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, 2020, our Debt Service Coverage Ratio of 1.22 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 $53 million of the revolver. At December
31, 2020, 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 ($121 million) and 3.5% on the
remainder ($16.7 million).
Future Maturities (in thousands):
2021
2022
2023
Total
36,750
25,725
75,263
137,738
$
49
Paycheck Protection Program
On April 16, 2020, we entered into an unsecured promissory note in the amount of $10 million under the Paycheck Protection Program (the “PPP Note”).
The Paycheck Protection Program 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"). The PPP note was funded through First Financial Bank, N.A. (the “Lender”).
The annual interest rate on the PPP Note is 1.00%. Monthly principal and interest payments were originally deferred for six months after the date of the loan, but the
deferral has been extended to 2021. If the note is not forgiven, monthly payments of ~$1.1 million will commence in August 2021 with maturity of April 2022. The
PPP Note contains customary events of default relating to, among other things, payment defaults, making materially false and misleading representations to the
SBA or Lender, or breaching the terms of the Loan Documents. The occurrence of an event of default may result in the repayment of all amounts outstanding,
collection of all amounts owing from the Company, or filing suit and obtaining a judgment against the Company.
Under the terms of the CARES Act, PPP loan recipients can apply for and be granted forgiveness for all or a portion of the loan granted under the PPP. Such
forgiveness will be determined, subject to limitations, based on the use of loan proceeds for payment of payroll costs and any covered payments of mortgage
interest, rent, and utilities. In the event the PPP Loan, or any portion thereof, is forgiven pursuant to the PPP, the amount forgiven is applied to outstanding
principal. The Company used all proceeds from the PPP Loan to maintain payroll and utility payments.
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.
In December 2020, we applied for forgiveness of the full $10 million promissory note. On January 8, 2021, we were notified by the Lender that they had approved
the application for the full forgiveness of the $10 million note and had forwarded on to the SBA for final approval. The SBA has 90 days from receipt of
application from the Lender to make its determination as to the amount of forgiveness. There can be no assurance that any portion of the PPP loan will be forgiven.
If the SBA determines that the Company was not initially eligible under the program or concludes that the Company did not have an adequate basis for making the
good-faith certification of the necessity of the loan at the time of application, the loan could become payable on demand. The SBA retains the right to review the
Company's loan file for a period subsequent to the date the loan is forgiven or paid in full, with the potential for the SBA to pursue legal remedies at its discretion.
(6) ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (IN THOUSANDS)
Accounts payable
Accrued property taxes
Accrued payroll
Workers' compensation reserve
Group health insurance
Other
Total accounts payable and accrued liabilities
(7) REVENUE
December 31,
2020
2019
14,785 $
2,566
1,621
2,988
1,800
7,649
31,409 $
16,115
2,835
2,151
3,446
2,500
4,753
31,800
$
$
Effective January 1, 2018, we adopted ASU 2014-09. The adoption of this standard did not impact the timing of revenue recognition on our consolidated balance
sheets or consolidated statements of comprehensive income (loss).
50
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. 74% and 74% of our coal revenue for the years ended December 31, 2020 and 2019, 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 $493 million, which represent the average fixed prices on our
committed contracts as of December 31, 2020. We expect to recognize approximately 78% of this revenue in 2021 and 2022, with the remainder recognized
thereafter.
We have remaining performance obligations relating to contracts with price reopeners of approximately $237 million, which represents our estimate of the expected
re-opener price on committed contracts as of December 31, 2020. We expect to recognize all of this revenue beginning in 2022.
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.
51
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. 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. This deferred
revenue is included in accounts payable and accrued liabilities in our consolidated balance sheets when consideration is received, and revenue is not recognized until
the performance obligation is satisfied. We are rarely paid in advance of performance, but we currently are carrying $0.3 million in deferred revenue recorded in our
condensed balance sheets as of December 31, 2020 related to coal storage for one customer.
(8) OTHER OPERATING INCOME (IN THOUSANDS)
Equity income (loss) - Sunrise Energy
MSHA reimbursements
Gain on sale of royalty interests in oil properties
Miscellaneous
(9) INCOME TAXES
Year Ended December 31,
2019
2020
1,054 $
400
—
1,757
3,211 $
(527)
575
2,949
3,029
6,026
$
$
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
State income taxes, net of federal benefit
Percentage depletion
Valuation allowance
Stock-based compensation
Return to provision adjustments
Other
2020
2019
$
$
(1,865) $
(644)
(2,154)
1,275
67
(60)
723
(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):
Long-term deferred tax assets:
Net operating loss
Valuation allowance
Interest limitation carryforward
Capital loss carryforward
Alternative minimum tax credit
Stock-based compensation
Other
Total long-term deferred tax assets:
Coal properties
Net deferred tax liability
2020
2019
$
$
24,081 $
(1,275)
—
525
—
179
529
24,039
(26,863)
(2,824) $
52
(17,262)
(3,831)
(1,475)
—
326
(78)
(27)
(22,347)
18,956
—
1,801
555
524
135
1,029
23,000
(27,884)
(4,884)
Our effective tax rate (ETR) for 2020 was 30% compared to 27% for 2019. The tax rate for the years ended December 31, 2020 and 2019 are not predictive of future
tax rates. Historically, our actual ETRs have differed from the statutory effective rates primarily due to the benefit received from statutory depletion allowances. The
deduction for statutory depletion does not necessarily change proportionately to changes in income before income taxes.
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 state NOL carryforwards will not be realized. In
recognition of this, we have provided a valuation allowance of $1.3 million and $0 on the deferred tax assets related to these state NOL carryforwards as of
December 31, 2020 and 2019, 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 SG&A. Tax returns filed with the IRS
and state entities generally remain subject to examination for three years after filing.
At December 31, 2020, we had approximately $89 million and $123 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 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 2040 if they are not utilized.
(10) STOCK COMPENSATION PLANS
Restricted Stock Units (RSUs)
The table below shows the number of RSUs available for issuance at December 31, 2020:
Total authorized RSUs in Plan approved by shareholders
Stock issued out of the Plan from vested grants
Non-vested grants
RSUs available for future issuance
Non-vested grants at December 31, 2018
Granted – weighted average share price on grant date was $3.98
Vested – weighted average share price on vesting date was $2.95
Forfeited
Non-vested grants at December 31, 2019
Granted – weighted average share price on grant date was $.90
Vested – weighted average share price on vesting date was $.92
Forfeited
Non-vested grants at December 31, 2020
RSU Vesting Schedule
Vesting Year
2021
2022
2023
4,850,000
(3,091,049)
(324,250)
1,434,701
789,250
17,000
(297,250)
(20,500)
488,500
40,000
(193,250)
(11,000)
324,250
RSUs Vesting
305,250
9,000
10,000
324,250
Vested shares had a value of $0.2 million for 2020, and $0.9 million for 2019, 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 $0.5 million based on the March 4, 2021 closing stock price of $1.63.
For the years ended December 31, 2020 and 2019 stock-based compensation was $1.2 million and $1.8 million, respectively. For 2021, based on existing RSUs
outstanding, stock-based compensation expense is estimated to be $1.1 million, with nominal amounts of expense in 2022 and 2023.
53
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.
(11) 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
2,221 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
$19.0 million not including premiums.
Our employee benefit expenses for the years ended December 31 are below (in thousands):
Health benefits, including premiums
401(k) matching
Deferred bonus plan
Total
$
$
2020
2019
13,173 $
1,797
679
15,649 $
16,228
2,510
727
19,465
Of the amounts in the above table, $15.0 million and $18.9 million are recorded in operating costs and expenses for 2020 and 2019, respectively with the remainder
in SG&A.
Our mine employees are also covered by workers’ compensation and such costs for 2020 and 2019, were approximately $1.9 million and $3.1 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. We have a safety-conscious workforce, and based on our
experience modifier, our claims are averaging 24% below that of our peers in underground coal mining in the state of Indiana.
(12) 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
Weighted average remaining lease term in years
Weighted average discount rate
54
2020
$
235
3.18
6.0%
Future minimum lease payments under non-cancellable leases as of December 31, 2020 were as follows (in thousands):
Year
2021
2022
2023
2024
Total minimum lease payments
Less imputed interest
Total operating lease liability
As reflected on balance sheet:
Other long-term liabilities
Amount
203
206
173
60
642
(40)
602
602
$
$
$
$
At December 31, 2020, we had approximately $602,000 right-of-use operating lease assets recorded within “buildings and equipment” on the Consolidated Balance
Sheet.
(13) 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 $269 million and $273 million as of December 31, 2020 and December 31, 2019, respectively.
Restricted cash of $4.0 million and $4.5 million as of December 31, 2020, and December 31, 2019, respectively, represents cash held and controlled by a third party
and is restricted for future workers’ compensation claim payments.
(14) 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:
Numerator:
Net loss
Less loss allocated to RSUs
Net loss allocated to common shareholders
Denominator:
Weighted average number of common shares outstanding
Net loss per share:
Basic and diluted
55
Year Ended December 31,
2019
2020
$
$
(6,220) $
94
(6,126) $
(59,854)
907
(58,947)
30,446
30,253
$
(0.20) $
(1.95)
(15) 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 $68 million as of December 31, 2020, both with maturities of May 2022. Fuel hedges include
1.0 million gallons of diesel fuel that are subject to pricing fluctuations with a minimum of $1.79/gallon and a maximum of $2.00/gallon through December 2021.
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 2020 which incorporate Level 3 non-recurring fair
value measures as further discussed in Note 2.
The following table summarizes our financial assets and liabilities measured on a recurring basis at fair value at December 31, 2020 and 2019 by respective level of
the fair value hierarchy (in thousands):
December 31, 2020
Liabilities:
Fuel hedge
Interest rate swaps
December 31, 2019
Assets:
Fuel hedge
Marketable securities - restricted (Note 4)
Liabilities:
Interest rate swaps
Level 1
Level 2
Level 3
Total
$
$
$
$
$
— $
—
— $
— $
2,296
2,296 $
— $
— $
—
— $
— $
—
— $
— $
297 $
3,893
4,190 $
25 $
—
25 $
3,825 $
297
3,893
4,190
25
2,296
2,321
3,825
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, 2018
Change in estimated fair value
Ending balance, December 31, 2019
Change in estimated fair value
Ending balance, December 31, 2020*
$
$
(1,639)
(2,161)
(3,800)
(390)
(4,190)
-------------------------------
*Recorded in accounts payable and accrued liabilities and other liabilities in the Balance Sheet to these Consolidated Financial Statements.
56
(16) 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, 2020 and December 31, 2019, was $3.2 million and $3.1 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.
(17) 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.
57
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
Disclosure Controls
We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to be disclosed in our SEC
reports is recorded, processed, summarized and reported within the time periods specified in the SEC’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, 2020. Based on that evaluation, our
management concluded that our ICFR was effective at December 31, 2020.
There were no significant changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2020 that have materially
affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
58
Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 14 of Part III of this Report is incorporated by
reference from our definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of our fiscal year ended December 31,
2020.
PART III
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
See Item 8 for an index of our financial statements.
Our exhibit index is as follows:
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009. (1)
3.1
By-laws of Hallador Energy Company, effective December 24, 2009 (2)
3.2
Description of Securities (3)
4.1
2009 Stock Bonus Plan (4)*
10.1
Third Amended and Restated Credit Agreement dated May 21, 2018 (5)
10.2
Second Amendment to the Third Amended and Restated Credit Agreement as of September 30, 2019 (6)
10.3
Third Amendment to the Third Amended and Restated Credit Agreement and Waiver (7)
10.4
US SBA Loan (PPP) dated April 16, 2020 (7)
10.5
Amended and Restated Hallador Energy Company 2008 Restricted Stock Unit Plan (8)
10.6
Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement* (8)
10.7
Hallador Energy Company Four-Year Plan* (9)
10.8
Hallador Energy Company 2020 Compensation Plan adopted March 5, 2020 *(10)
10.9
Code of Ethics for Senior Financial Officers (11)
14
List of Subsidiaries (12)
21.1
Consent of Plante & Moran, PLLC (12)
23.1
SOX 302 Certification - President and CEO (12)
31.1
SOX 302 Certifications - CFO (12)
31.2
SOX 302 Certifications - CAO (12)
31.3
SOX 906 Certification (12)
32
95
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 with the Inline XBRL document)
IBR to Form 8-K dated December 31, 2009
IBR to Form 10-K/A dated June 29, 2020
IBR to Form 10-K dated March 9, 2020
IBR to Form S-8 dated December 1, 2009
IBR to Form 10-Q dated August 6, 2018
IBR to Form 10-Q dated November 4, 2019
IBR to Form 10-Q dated May 11, 2020
IBR to Form DEF 14A dated April 11, 2017
IBR to Form 10-Q dated August 8, 2017
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
(10) IBR to Form 10-K/A dated June 12, 2020
(11)
IBR to Form 10KSB dated April 14, 2006
(12) Filed herewith.
* Management Agreements
59
ITEM 16. FORM 10-K SUMMARY.
As this item is optional, no summary is presented.
60
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
SIGNATURES
Date: March 8, 2021
Date: March 8, 2021
HALLADOR ENERGY COMPANY
/s/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO
/s/R. TODD DAVIS
R. Todd Davis, CAO
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
/s/DAVID HARDIE
David Hardie
/s/BRYAN LAWRENCE
Bryan Lawrence
/s/BRENT BILSLAND
Brent Bilsland
/s/DAVID J. LUBAR
David J. Lubar
Director
March 8, 2021
Director
March 8, 2021
Board Chairman, President and CEO
March 8, 2021
Director
March 8, 2021
61
Exhibit 21.1
List of Subsidiaries
Edwardsport Construction Company, LLC
Gibson County Logistics, LLC
Hallador Sands, LLC
Hourglass Sands, LLC
High Point Land Holdings LLC
Oaktown Fuels Mine No. 1, LLC
Oaktown Fuels Mine No. 2, LLC
Prosperity Mine, LLC
Railpoint Solutions, LLC
SFI Coal Sales, LLC
Summit Terminal, LLC
Sunrise Administrative Services, LLC
Sunrise Coal LLC
Sunrise Energy, LLC
Sunrise Indemnity, Inc.
Sunrise Land Holdings, LLC
Sycamore Coal, Inc.
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Exhibit 23.1
We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (Nos. 333-163431 and 333-171778) of Hallador Energy
Company (the "Company") of our report dated March 8, 2021 relating to the financial statements as of and for the years ended December 31, 2020 and 2019,
which appears in this Form 10-K.
Denver, CO
March 8, 2021
/s/Plante & Moran, PLLC
Exhibit 31.1
CERTIFICATION
I, Brent K. Bilsland, certify that:
1. I have reviewed this annual report on Form 10-K of Hallador Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to
adversely affect the registrant's ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over
financial reporting.
March 8, 2021
/s/ BRENT K. BILSLAND
Brent K. Bilsland, Chairman, President and CEO
Exhibit 31.2
CERTIFICATION
I, Lawrence D. Martin, certify that:
1. I have reviewed this annual report on Form 10-K of Hallador Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to
adversely affect the registrant's ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over
financial reporting.
March 8, 2021
/s/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO
Exhibit 31.3
CERTIFICATION
I, R. Todd Davis, certify that:
1. I have reviewed this annual report on Form 10-K of Hallador Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial
condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange
Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and
have:
a)
b)
c)
d)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure
that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities,
particularly during the period in which this report is being prepared;
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles;
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of
the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a)
b)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to
adversely affect the registrant's ability to record, process, summarize and report financial information; and
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over
financial reporting.
March 8. 2021
/S/R. TODD DAVIS
R. Todd Davis, CAO
CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with this Annual Report (the "Report"), of Hallador Energy Company (the "Company"), on Form 10-K for the period ended December 31, 2020 as
filed with the Securities and Exchange Commission on the date hereof the undersigned, in the capacities and date indicated below, each hereby certifies pursuant to
18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
Exhibit 32
March 8, 2021
March 8, 2021
March 8, 2021
By:
/S/BRENT K. BILSLAND
Brent K. Bilsland, Chairman, President and CEO
By:
/S/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO
By:
/S/R. TODD DAVIS
R. Todd Davis, CAO
Mine Safety Disclosure
Exhibit 95
Our principles at Sunrise Coal, LLC are safety, honesty, and compliance. We firmly believe that these values compose a dedicated workforce and with that, come
high production. The core to this is our strong training programs that include accident prevention, workplace inspection and examination, emergency response and
compliance. We work with the Federal and State regulatory agencies to help eliminate safety and health hazards from our workplace and increase safety and
compliance awareness throughout the mining industry.
We are regulated by the Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977 (“Mine Act”). MSHA inspects
our mines on a regular basis and issues various citations and orders when it believes a violation has occurred under the Mine Act. We present information below
regarding certain violations which MSHA has issued with respect to our mines. While assessing this information please consider that the number and cost of
violations will vary depending on the MSHA inspector and can be contested and appealed, and in that process, are often reduced in severity and amount, and are
sometimes dismissed.
The disclosures listed below are provided pursuant to the Dodd-Frank Act. We believe that the following disclosures comply with the requirements of the Dodd-
Frank Act; however, it is possible that future SEC rulemaking may require disclosures to be filed in a different format than the following.
The table that follows outlines required disclosures and citations/orders issued to us by MSHA during the year ended December 31, 2020. The citations and orders
outlined below may differ from MSHA`s data retrieval system due to timing, special assessed citations, and other factors.
Definitions:
Section 104(a) Significant and Substantial Citations “S&S”: An alleged violation of a mining safety or health standard or regulation where there exists a
reasonable likelihood that the hazard outlined will result in an injury or illness of a serious nature.
Section 104(b) Orders: Failure to abate a 104(a) citation within the period of time prescribed by MSHA. The result of which is an order of immediate withdraw
of non-essential persons from the affected area until MSHA determines the violation has been corrected.
Section 104(d) Citations and Orders: An alleged unwarrantable failure to comply with mandatory health and safety standards.
Section 107(a) Orders: An order of withdraw for situations where MSHA has determined that an imminent danger exists.
Section 110(b)(2) Violations: An alleged flagrant violation issued by MSHA under section 110(b)(2) of the Mine Act.
Pattern or Potential Pattern of Violations: A pattern of violations of mandatory health or safety standards that are of such a nature as could have significantly and
substantially contributed to the cause and effect of coal mine health or safety hazards under section 104(e) of the Mine Act or a potential to have such a pattern.
Contest of Citations, Orders, or Proposed Penalties: A contest proceeding may be filed with the Commission by the operator or miners/miner’s representative to
challenge the issuance or penalty of a citation or order issued by MSHA.
MSHA Federal Mine ID#`s:
(12-02349 – Carlisle Mine, sealed in May 2020) (12-02465 – Carlisle Preparation Plant) (12-02460 – Ace in the Hole Mine) (12-02394 – Oaktown Fuels No. 1)
(12-02418 – Oaktown Fuels No. 2)
(12-02462 – Oaktown Fuels Preparation Plant) (12-02249 – Prosperity Mine)
Section
104(a)
Citations
Section
104(b)
Orders
Section
104(d)
Citations/Orders
Section
107(a)
Orders
Section
110(b)(2)
Violations
2020
Mine ID#
12-02349
12‐02465
12‐02460
12‐02394
12‐02418
12‐02462
12‐02249
Mine ID#
12-02349
12‐02465
12‐02460
12‐02394
12‐02418
12‐02462
12‐02249
Mine ID#
12-02349
12‐02465
12‐02460
12‐02394
12‐02418
12‐02462
12‐02249
0
0
0
36
20
1
0
0
0
0
0
0
0
0
Section
104(e)
Notice
Yes/No
No
No
No
No
No
No
No
Section
104(e)
POV
Yes/No
No
No
No
No
No
No
No
Mining
Related
Fatalities
Contest of
Citations/
Orders
Contest
of
Penalties
Complaints
of
Compensation
0
0
0
1
2
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Legal
Actions
Pending
Complaints
of Discharge/
Discrimination
Proposed
MSHA
Assessments
(In thousands)
0
0
0
0
0
0
0
$
$
$
$
$
$
$
1.80
0.00
0.40
55.95
27.20
0.50
0.00
Legal
Actions
Initiated
Legal
Actions
Resolved
Applications
of Temp.
Relief
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Appeals of
Decisions/
Orders
0
0
0
0
0
0
0
0
0
0
0
0
0
0