UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
[ x ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2019 OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT O F 1934
“COAL KEEPS YOUR LIGHTS ON”
“COAL KEEPS YOUR LIGHTS ON”
Commission file number: 001‑3473
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: 303.839.5504
Securities registered pursuant to Section 12(b) of the Act:
84-1014610
(IRS Employer Identification No.)
47802
(Zip Code)
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Stock, $0.01 par value per share
HNRG
Nasdaq Capital Market
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☑
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ☐ No☑
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to
Rule 405 of Regulation S-T 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 (do not check if a small reporting company)
☑ 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 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 28, 2019 was $113,764,353 based on the closing
price reported that date by the NASDAQ of $5.51 per share.
As of March 6, 2020, we had 30,419,967, shares outstanding.
Portions of our Proxy Statement to be filed with the SEC in connection with our annual stockholders’ meeting are incorporated by reference into
Part III of this Form 10‑K. Our Annual Meeting of Shareholders will be held on May 29, 2020 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:
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changes in competition in coal markets and our ability to respond to such changes;
changes in coal prices, 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 new 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;
fluctuations in coal demand, prices, and availability;
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; and
other factors, including those discussed in “Item 1A. Risk Factors.”
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.
You should consider the information above when reading any forward-looking statements contained in this Annual Report on
Form 10‑K; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website
http://www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons
acting on our behalf.
ITEM 1. BUSINESS.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our
business.
Regulation and Laws
The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:
employee health and safety;
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air quality standards;
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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;
reclamation and restoration of mining properties after mining is completed;
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;
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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.
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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.
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
Stringent safety and health standards have been imposed by federal legislation since the Federal Coal Mine Health, and Safety Act
of 1969 (“CMHSA”) was adopted. The Federal Mine Safety and Health Act of 1977 (“FMSHA”), and regulations adopted pursuant
thereto, significantly expanded the enforcement of health and safety standards of the CMHSA, and imposed 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 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
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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;
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substantially increased civil penalties for regulatory violations;
training and availability of mine rescue teams;
underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and
post-accident two-way communications and electronic tracking systems.
MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations
and standards.
In 2014, MSHA began implementation of a finalized new regulation titled “Lowering Miner’s Exposure to Respirable Coal Mine
Dust, Including Continuous Personal Dust Monitors.” The final rule implemented a reduction in the allowable respirable coal mine
dust exposure limits, requires the use of sampling data taken from a single sample rather than an average of samples, and
increases oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for
ventilation plans at each mine, all of which increase mining costs. The second phase of the rule began in February 2016 and
requires additional sampling for designated and other occupations using the new continuous personal dust monitor technology,
which provides real-time dust exposure information to the miner. Phase three of the rule began in August 2016 and resulted in
lowering the current respirable dust level of 2.0 milligrams per cubic meter to 1.5 milligrams per cubic meter of air. Compliance with
these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the
hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations. MSHA has published a request for
information regarding engineering controls and best practices to lower miners’ exposure to respirable coal mine dust, which is
currently set to close on July 9, 2022. The comment period for this request for information will close on July 9, 2019. 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.
Additionally, in July 2014, MSHA proposed a rule addressing the “criteria and procedures for assessment of civil penalties.” Public
commenters have expressed concern that the proposed rule exceeds MSHA’s rulemaking authority and would result in
substantially increased civil penalties for regulatory violations cited by MSHA. MSHA last revised the process for proposing civil
penalties in 2006 and, as discussed above, civil penalties increased significantly. The notice-and-comment period for this proposed
rule has closed, and it is uncertain when, or if, MSHA will present a final rule addressing these civil penalties.
In January 2015, MSHA published a final rule requiring mine operators to install proximity detection systems on continuous mining
machines, over a staggered time frame ranging from November 2015 through March 2018. The proximity detection systems initiate
a warning or shutdown the continuous mining machine depending on the proximity of the machine to a miner. MSHA subsequently
proposed a rule requiring mine operators to also install proximity detection systems on other types of underground mobile mining
equipment. The comment period for this proposed rule closed on April 10, 2017, and it is uncertain when MSHA will promulgate a
final rule addressing the issue of proximity detection systems on underground mobile mining equipment, other than continuous
mining machines.
Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for
Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA’s request for
information. The comment period for the request for information was reopened and closed in January 2018.
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The comment period is scheduled to close 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.
In June 2018, MSHA published a request for information on Safety Improvement Technologies for Mobile Equipment at Surface
Mines and for Belt Conveyors at Surface and Underground Mines. The comment period for the request for information has closed.
It is uncertain whether MSHA will present a proposed rule pertaining to safety improvement technologies for mobile equipment at
surface mines or for belt conveyors at surface and underground mines.
Subsequent to 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 is set to expire on December 31, 2020.
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.
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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 tax on all current mining operations, the
proceeds of which are used to restore mines closed before 1977. The tax for surface-mined and underground-mined coal is $0.28
per ton and $0.12 per ton, respectively. 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. OSM
has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but to date, no
further action has been taken. These actions by OSM potentially could result in additional delays and costs associated with
obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.
Bonding Requirements
Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, and to satisfy other miscellaneous
obligations. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us and our competitors
to secure new surety bonds without posting collateral. In addition, surety bond costs have increased while the market terms of
surety bonds have generally become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may
demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by
federal and state laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and
cash flow.
Air Emissions
The 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
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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.
Since 2010, utilities have completed or formally announced the retirement or conversion of almost 700 coal-fired electric
generating units through 2030 in the United States.
In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may affect our operations,
directly or indirectly, include, but are not limited to, the following:
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The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric
generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise
allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s
sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that
require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional
sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by
switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or
“scrubbers,” or by reducing electricity generating levels. These requirements would not be supplanted by a
replacement rule for the Clean Air Interstate Rule (“CAIR”), discussed below.
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." 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. Initial non-attainment determinations related to the
revised sulfur dioxide standard became effective in October 2013. In addition, in January 2013, the EPA updated the
NAAQS for fine particulate matter emitted by a wide variety of sources including power plants, industrial facilities, and
gasoline and diesel engines, tightening the annual PM 2.5 standard to 12 micrograms per cubic meter. The revised
standard became effective in March 2013. In November 2013, the EPA proposed a rule to clarify PM 2.5
implementation requirements to the states for current 1997 and 2006 non-attainment areas. In July 2016, the EPA
issued a final rule for states to use in creating their plans to address particulate matter. In October 2015, the EPA
published a final rule that reduced the ozone NAAQS from 75 to 70 ppb and completed attainment/non-attainment
designations in July 2018. In March 2019, the EPA published a final rule that retained the current primary NAAQS for
sulfur oxide. 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 under the program.
Several of these lawsuits have settled, but others remain pending. In addition, there are proposals to modify the NSR
program as a part of the Affordable Clean Energy ("ACE") rule which is subject to current pending litigation as
discussed below. A final rule on NSR reforms is expected in March 2020. Depending on the ultimate resolution of
these cases, demand for coal could be affected.
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. Congress has
considered various proposals to reduce GHG emissions, and it is possible federal legislation could be adopted in the future.
Internationally, there is an international climate agreement (“Paris Agreement”) that does not create any binding obligations for
nations to limit their GHG emissions but includes pledges to voluntarily limit or reduce future emissions. These commitments could
further reduce demand and prices for fossil fuels. In November 2019, the United States announced its withdrawal from such
agreement, effective November 4, 2020. However, the United States may subsequently decide to rejoin the Paris Agreement or
another agreement at some point in the future. 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
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facilities. Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil
fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal
could be negatively impacted, which would have an adverse effect on our operations.
Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S.
Supreme Court’s 2007 decision that the EPA has authority to regulate GHG emissions. Although the U.S. Supreme Court’s holding
did not expressly involve the EPA’s authority to regulate GHG emissions from stationary sources, such as coal fueled power
plants, the EPA has determined on its own that it has the authority to regulate GHG emissions from power plants and issued a final
rule which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare.
On September 20, 2013, the EPA issued NSPS for carbon dioxide emissions from new fossil fuel-fired power plants. This rule was
finalized in 2015 and was immediately challenged by multiple parties. In August 2017, this rule was stayed by a federal appeals
court to allow the Trump administration’s EPA to review the NSPS rule. It is likely than any repeal or revisions to the NSPS will be
subject to legal challenges as well. Future implementation of the NSPS is uncertain at this time.
In August 2015, the EPA issued its final Clean Power Plan ("CPP") 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. Additionally, in October 2017 the EPA proposed to repeal the CPP, although the final outcome of this action and the
pending litigation regarding the CPP is uncertain at this time. 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 Clean
Power Plan and promulgation of the ACE rule. The EPA’s attempts to replace the CPP with the ACE rule are currently subject to
litigation, 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
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January 2020, CEQ issued a proposed revision to NEPA regulations that seeks to clarify the extent to which direct, indirect, and
cumulative environmental impacts from a proposed project, including GHG emissions, should be examined under NEPA; however,
the final form or impact of any such revisions is uncertain at this time.
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 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. In 2019, New Jersey and Pennsylvania each announced they were
joining RGGI.
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 the Canadian provinces of British Columbia, Novia Scotia and Quebec
remain. 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. A challenge to the EPA’s exercise of
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this authority was made in the U.S. District Court for the District of Columbia, and in March 2012, that court ruled that the EPA
lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. In April 2013, the D.C. Circuit Court
of Appeals reversed this decision and authorized the EPA to retroactively veto portions of a Section 404 permit. The U.S. Supreme
Court denied a request to review this decision. 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. In June 2018, the EPA Administrator issued
a memorandum directing the EPA’s Office of Water to promulgate draft regulations eliminating the use of the EPA’s Section 404
authority before a Section 404 permit application has been filed, or after a permit has been issued. To date, the EPA has not
issued a proposed rule.
Total Maximum Daily Load (“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a
pollutant that an impaired water body 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. A 2015 rulemaking by the EPA to revise the standard was quickly challenged and
nationwide implementation was blocked by a federal appeals court. Should the 2015 rule take effect, or should a different rule
expanding the definition of what constitutes a water of the United States be promulgated as 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. In December 2018, the EPA and the Corps of Engineers issued a proposed rule to
“determine the scope of ‘waters of the United States’” subject to federal jurisdiction. This proposal would lessen the number of
waterbodies subject to the CWA as compared to the 2015 Rule. In January 2020, the EPA finalized its rule regarding the scope of
Waters of the United States”. Litigation surrounding these developments is ongoing and we cannot predict the outcome at this
time.
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.
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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. 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.
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
regulation. 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.
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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.
Employees
As of December 31, 2019, we had 915 full-time employees and temporary miners, of which 907 are Sunrise Coal employees and
temporary miners. With the closing of the Carlisle Mine, our head count has been reduced to 768.
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, phone 303.839.5504 and Sunrise
Coal’s corporate office is at the same location, phone 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis.
ITEM 1A. RISK FACTORS.
Risks Related to our Business
Global economic conditions or economic conditions in any of the industries in which our customers operate as well as
sustained uncertainty in financial markets may 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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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 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.
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.
New tariffs and other trade measures could adversely affect 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. The Trump
Administration has imposed tariffs on steel and aluminum and a broad range of other products imported into the United States. 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.
According to the most recent information from the Energy Information Administration, since 2000, coal's share of United States
electricity production has fallen from 53% to 24%, while natural gas' share has increased from 16% to 39%.
The domestic electric utility industry accounts for ~92% 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
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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.
For example, to the extent implemented as originally finalized, the EPA’s CPP could likely incentivize additional electric generation
from natural gas and renewable sources, and Congress has extended tax credits for renewables. In addition, a number of states
have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of
power. Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make
alternative fuel sources more competitive with coal. A decrease in coal consumption by the domestic electric utility industry could
adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash from operations.
Extensive environmental laws and regulations affect coal consumers and have corresponding effects on the demand for
coal as a fuel source.
Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides,
mercury and other compounds emitted into the air from coal-fired electric power plants, which are the ultimate consumers of much
of our coal. These laws and regulations can require significant emission control expenditures for many coal-fired power plants, and
various new and proposed laws and regulations may require further emission reductions and associated emission control
expenditures. These laws and regulations may affect demand and prices for coal. There is also continuing pressure on 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.
Increased regulation to address climate change (particularly GHG emissions) and uncertainty regarding such regulation
could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for
our products, decrease our revenues and reduce our profitability.
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, including perceived impacts on global climate issues, are resulting in
increased regulation of fossil fuels. in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts
affecting the investment community, which could significantly affect demand for our products or our securities. Global climate
issues continue to attract public and scientific attention. Some scientists have concluded that increasing concentrations of GHGs in
the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and
severity of storms, droughts and floods and other climatic events. Increasing government attention is being paid to global climate
issues and to emissions of GHGs, including emissions due to fossil fuels.
Federal and possibly state governments may impose significant restrictions on fossil-fuel exploration, production and use if
pledges made by certain candidates seeking various political offices were enacted into law. Some proposals include bans on
hydraulic fracturing of oil & gas wells, bans on new leases for production of minerals on federal properties, and imposing restrictive
requirements on new pipeline infrastructure or fossil-fuel export facilities. Other energy legislation and initiatives could include 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 or regional GHG cap and
trade programs. Depending on the particular program, we 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 companies engaged in the exploration and production of
fossil fuels in state and federal courts, alleging various legal theories to recover for the impacts of alleged global warming effects,
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 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 concerned about the potential effects of climate change 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. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent
years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign
citizenry concerned about climate change not to provide funding for fossil fuel producers. In recent years, the insurance industry
has been subject to similar
intense lobbying efforts by environmental activist to restrict coverages available for fossil fuel producers.
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 may result in us restricting or cancelling mining activities, incurring liability for
infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic
manner. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced
electricity consumption, and consumer and corporate preferences for non-fossil fuel sources, including alternative energy sources,
could cause prices and sales of our coal to materially decline and could cause our costs to increase and adversely affect our
revenues and results of operations.
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.
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 2019, approximately 87% 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
17
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 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. With the addition of the new power plants that we began shipping to in 2018, we reduced the
concentration from customers representing at least 10% of our coal sales from 82% in 2018. 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.
Litigation resulting from disputes with our customers may result in substantial costs, liabilities, and loss of revenues.
From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among
other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that
suspend performance obligations under the particular contract. Disputes may occur in the future, and we may not be able to
resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition
and results of operations.
Our 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.
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;
·
·
·
·
·
· weather conditions, such as heavy rains, flooding, ice and other natural events affecting operations, transportation or
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;
customers;
accidental mine water discharges and other geological conditions;
seismic activities, ground failures, rock bursts or structural cave-ins or slides;
·
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·
·
·
·
·
·
·
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
may increase substantially in the future and may 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 may go out of business or be otherwise
unable to fulfill their contractual obligations or may 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 may try to hamper fossil fuel companies by other means including pressuring
insurance and surety companies into restricting access to certain needed coverages.
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.
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. Please read “Item 1. Business—Regulations and Laws.”
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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. For more information, please
read “Item 1. Business—Regulation and Laws—Mine Health and Safety Laws.”
We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash
flow and profitability.
Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating
to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over
time. Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to
comment on permit applications and otherwise participate in the permitting process, including through court intervention.
Accordingly, permits required to conduct our operations may not be issued, maintained or renewed, or may not be issued or
renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations.
Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar
approvals could reduce our production, cash flow, and profitability. Please read “Item 1. Business—Regulations and Laws—Mining
Permits and Approvals.”
The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the
CWA. Various 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. Please read “Item 1. Business—Regulations and Laws—Water Discharge.”
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.
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.
21
The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our
profitability to decline.
Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them
to be mined at competitive costs and to meet the quality needed by our customers. Because we deplete our reserves as we mine
coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically
recoverable. Replacement reserves may not be available when required or, if available, may not be mineable at costs comparable
to those of the depleting mines. We may not be able to accurately assess the geological characteristics of any reserves that we
acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may
have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by
such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt
agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the
inability to acquire coal properties on commercially reasonable terms.
The estimates of our coal reserves may prove inaccurate and could result in decreased profitability.
The estimates of our coal reserves may vary substantially from actual amounts of coal we are able to recover economically. All of
the reserves presented in this Annual Report on Form 10‑K constitute proven and probable reserves. There are numerous
uncertainties inherent in estimating quantities of reserves, including many factors beyond our control. Estimates of coal reserves
necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results.
These factors and assumptions relate to:
·
·
·
·
·
·
geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our
experiences in areas where we currently mine;
the percentage of coal in the ground ultimately recoverable;
historical production from the area compared with production from other producing areas;
the assumed effects of regulation and taxes by governmental agencies;
future improvements in mining technology; and
assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and
development and reclamation costs.
For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications
of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by
different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue, and
expenditures with respect to our reserves will likely vary from estimates, and these variations may be material. Any inaccuracy in
the estimates of our reserves could result in higher than expected costs and decreased profitability.
Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in
other areas of the U.S., which could affect the mining operations and cost structures of these areas.
The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them
difficult and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available,
may not be mineable at costs comparable to those characteristic of the depleting mines. In addition, permitting, licensing and other
environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming
to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to
use coal produced by, our mines.
Unexpected increases in raw material costs could significantly impair our operating profitability.
Our coal mining operations are affected by commodity prices. We use significant amounts of steel, petroleum products, and other
raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room-and-
pillar method of mining. Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron
and steel fluctuate significantly and may change unexpectedly. 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.
22
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease
obligations and, therefore, our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such
as mine closure or reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may
demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals.
Because we are required by state and federal law to have these bonds in place before mining can commence or continue, failure
to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our
ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or
unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions
on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.
Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or
financial loss.
Like most companies, we have become increasingly dependent upon digital technologies, including information systems,
infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data,
communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as
other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist
or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the
systems or infrastructure of third parties, could lead to corruption or loss of our proprietary data and potentially sensitive data,
delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records,
environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not
protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could
have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber
incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective
measures or to investigate and remediate any vulnerability to cyber incidents.
Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated
as a result of future legislation.
In past years, members of Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently
applicable to coal companies, including the percentage depletion allowance with respect to coal properties. No legislation with that
effect has been proposed, but the elimination of those provisions would negatively impact our financial statements and results of
operations.
Public health threats could have an adverse effect on our operations and financial results.
Public health threats and other highly communicable diseases, outbreaks of which have already occurred in various parts of the
world, could adversely impact our operations, the operations of our customers and the global economy.
In particular, the outbreak in December 2019 of a novel coronavirus (COVID-19) in China has resulted in quarantines, restrictions
on travel to and from China and a decrease in economic activity in China, the world’s second largest economy. To date, these
impacts have not had a material adverse effect on our business but no assurance can be given that they will not have such an
effect, or that any further spread of the novel coronavirus (COVID-19) will not have a material adverse effect on our business,
operations and financial results.
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 have 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. During the year ended December 31, 2019, we recorded $77.9 million of impairment charges related to such
factors, as further described in Note 2 to the accompanying consolidated financial statements. These factors may trigger the
recognition of additional impairment charges in the future, which could have a substantial impact on our results of operations.
23
Risks Related to Our Indebtedness and Liquidity
If we are unable to comply with the covenants contained in our credit agreement, the lenders could declare all amounts
outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial
condition and operations.
As disclosed in Note 5 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a Minimum
Debt Service Coverage Ratio (consolidated adjusted EBITDA/annual debt service) of 1.25 to 1 and (ii) a Maximum Leverage Ratio
(consolidated funded debt/trailing twelve months adjusted EBITDA) not to exceed 3.00 to 1, which also decreases in future periods
further reducing the maximum leverage permitted. On December 31, 2019, our debt service coverage ratio was 1.84, and our
leverage ratio was 2.62. Therefore, we were in compliance with these two ratios.
Our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.
On December 31, 2019, our debt was $180 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 to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness
could have similar or greater restrictions.
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 eighteen 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.
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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 at 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.
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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 30.4% is held by our officers, directors
and their affiliates.
At March 2, 2020, we had 231 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.
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. Additionally, we own 100% of the
Class A shares of Hourglass Sands, LLC (Hourglass), a frac sand dry plant in the State of Colorado. Based on weak market
conditions for frac sand in Colorado for the foreseeable future, we are impairing the assets to fair market value as of December 31,
2019. See Note 2 to our consolidated financial statements for further discussion.
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. Operating only Oaktown will significantly decrease costs in 2020 as compared to 2019 allowing
additional EBITDA per ton in 2020. We will remove $24 million of Carlisle equipment and parts inventory and utilize those assets
at Oaktown which will further 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 will operate two underground coal mines and one
surface coal mine in southwestern Indiana with the following capacities:
Mine
Oaktown 1*
Oaktown 2**
Ace in the Hole
Total
Location
Oaktown, IN
Oaktown, IN
Clay City, IN
Surface/
Underground
Underground
Underground
Surface
Annual
Tons Capacity
(in millions)
4.0
4.0
0.3
8.3
Transportation
CSX, Truck Direct & Truck to NS
CSX, Truck Direct & Truck to NS
Truck to CSX & NS
* The Oaktown 1 & Oaktown 2 underground mines share a common surface facility.
26
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 2019, Sunrise sold a record 8.1 million tons of coal to 14 power plants in 7 different states. Though we served more plants in
2018, tonnage in 2019 increased significantly due to new customers buying more tons. The total estimated coal consumption of
our 2019 customers is 165% greater than our 2017 customer base.
Year
2019
2018
2017
Estimated Tonnage
Demand of
# of Plants
Served
# of States
Served
Customers Served
(millions)
Tons Sold % of Customer
(millions)
Supply
14
17
9
7
8
3
42.9
42.9
16.2
8.1
7.4
6.6
18.9 %
17.2 %
40.7 %
We have gained more customers by focusing on increasing “Customer Value”, meaning the total lifetime value of a customer’s
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 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. With the addition of the new power plants that we began shipping to in 2018, we reduced the
concentration from customers representing at least 10% of our coal sales from 82% in 2018.
Our significant customers include Vectren Corporation, a wholly owned subsidiary of CenterPoint Energy (NYSE: CNP), Duke
Energy Corporation (NYSE: DUK), Hoosier Energy, an electric cooperative, Orlando Utility Commission (OUC), and Indianapolis
Power & Light Company (IPL), a wholly owned subsidiary of The AES Corporation (NYSE: AES).
Of our 2019 sales, 74% were shipped to locations in the State of Indiana. We anticipate our coal shipments utilizing the following
modes of transportation in 2020:
CSX Railroad
CSX/INRD
Truck
NS Railroad
Total
44 %
23 %
23 %
10 %
100 %
Currently, domestic coal inventories and natural gas (a competitor to coal) inventory levels are high and will take time to
normalize. Thus, for 2020 and 2021 we have reduced our targeted tons to 6.7 million tons annually, of which we are 100% sold for
2020 and 79% sold for 2021. For 2020, we have reduced our contracted tons in the table below to the minimum amounts that
customers are contractually obligated to take.
27
Year
2020
2021
2022
Total
Targeted
tons
(millions)
6.7
6.7
7.0
20.4
Contracted
tons
(millions)*
6.7
5.3
5.3
17.3
%
Committed
100 % $
79 %
76 %
85 %
Estimated
price
per ton
$ 40.00
$ 40.00
$ 40.50
* 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.
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.
With the following exception, our customer plants are expected to have many years of life. In January 2020, Hoosier Energy
announced that they intend to close their Merom Generating Station in 2023. Merom represents 700,000 tons or ~10% of our
sales volume in 2020.
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 #
2019 Year-End Reserves
4.1
2.3
0.3
—
6.7
4.0
4.0
0.3
—
8.3
39.4
31.1
0.3
1.0
71.8
8.5
7.9
—
—
16.4
6.1
5.7
1.8
3.5
47.9
39.0
0.3
1.0
88.2
87.2
1.0
88.2
BTU
11,500
11,600
11,200
11,100
_____________
*The table above excludes Carlisle tons sold of 1.4 million.
Our assigned underground coal reserves are high sulfur (5.0# – 6.5# SO2) with an average BTU content in the 11,400 -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 11,200. 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.
28
Oaktown 1 Mine (underground) – Assigned
We have 47.9 million controlled, salable tons of the Indiana #V coal seam. We began 2019 with 54.4 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 39.0 million controlled, saleable tons of the Indiana #V coal seam. We began 2019 with 43.4 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 0.3 million controlled, saleable tons at our Ace mine. The Ace mine is near Clay City, Indiana in Clay County and 42 road
miles northeast of the Carlisle 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 2021.
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
Oaktown 1
Oaktown 2
Mine recovery
Wash plant recovery*
(Clean Tons)
49 %
46 %
81 %
81 %
8.0 million**
Wash Plant Capacity
* 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
As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $38.2 million and $51.6 million for
the years ended December 31, 2019 and 2018 respectively. Operating cash flow decreased due to : (1) operating margins from
our coal operations decreased in 2019 by $7.0 million due to increased operating costs related primarily to the Carlisle Mine, (2)
management chose to increase inventory at the end of 2019 in anticipation of the winter shipping season, which resulted in an
additional $8.3 million in inventory over 2018, and (3) other changes in working capital items that are strictly timing related.
Our capital expenditure budget for 2020 is $20 million, of which $11 million is for maintenance capex. With the closure of the
Carlisle Mine, equipment and parts inventories totaling $23 million will be re-deployed to Oaktown and are expected to be fully
utilized over the next 12 months, helping reduce our capital expenditures in the future. We expect cash from operations for 2020
and the utilization of our revolver, if necessary, to fund our maintenance capital expenditures, debt service, and our dividend.
See Note 5 to our consolidated financial statements for discussion about our bank debt.
Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded reclamation
obligations of $15.8 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, 2019, our capex was $35.5 million allocated as follows (in millions):
Oaktown – maintenance capex
Oaktown – investment
Carlisle - maintenance capex
Ace - investment
Other
Capex per the Consolidated Statements of Cash Flows
$
$
19.3
10.4
3.1
1.6
1.1
35.5
31
Results of Operations
The following table 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 following table presents our unaudited quarterly results of operations for the eight quarters ended December 31, 2019. This
table includes all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair presentation of
our consolidated operating results for the quarters presented.
Dec-31
2019
Sep-30
2019
Jun-30
2019
Mar-31
2019
Dec-31
Sep-30
2018
2018
Jun-30
2018
Mar-31
2018
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
Income (loss) before income
taxes
Less income taxes:
Current
Deferred
Total income taxes
$
78,205 $ 82,883 $
538
78,743
213
83,096
71,113 $
1,197
72,310
85,235 $ 89,019 $ 79,055 $ 56,922 $ 66,787
77
66,864
667
79,722
321
57,243
709
89,728
4,078
89,313
60,083
12,960
329
390
3,463
2,765
(313)
77,882
157,559
71,363
11,778
320
347
2,926
2,801
757
—
90,292
54,001
12,096
314
208
3,475
2,933
2,436
—
75,463
62,419
11,738
309
280
2,984
3,012
1,607
—
82,349
69,619
11,403
301
374
2,958
3,364
2,640
—
90,659
60,230
10,815
293
279
2,519
3,377
(116)
—
77,397
38,874
11,120
291
315
2,474
2,781
1,534
—
57,389
46,640
10,829
282
217
3,890
2,360
348
—
64,566
(78,816)
(7,196)
(3,153)
6,964
(931)
2,325
(146)
2,298
52
(19,081)
(19,029)
(426)
(3,047)
(3,473)
78
113
191
(229)
193
(36)
(1,362)
(2,167)
(3,529)
(204)
(385)
(589)
(19)
(104)
(123)
(203)
369
166
Net income (loss)
$
(59,787) $
(3,723) $
(3,344) $
7,000 $
2,598 $
2,914 $
(23) $
2,132
Net income (loss) per share:
Basic and diluted
$
(1.95) $
(0.12) $
(0.11) $
0.23 $
0.09 $
0.09 $
— $
0.07
Weighted average shares
outstanding:
Basic and diluted
30,274
30,249
30,245
30,245
30,180
30,177
29,980
29,955
*Impairment and tax effects primarily related to the decision to idle the Carlisle Mine. See Note 2 to our Consolidated Financial
Statements.
32
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
2019 v. 2018
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
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
1st 2018
1,975
1,707
66,787
39.13
$
$
69 %
$
$
$
$
$
$
$
46,640
27.32
20,147
11.80
10,428
5,772
3.38
2nd 2018
1,983
1,477
56,922
38.54
$
$
73 %
$
$
$
$
$
$
$
38,809
26.28
18,113
12.26
7,784
5,058
3.42
1,891
2,118
82,883
39.13
$
$
70 %
$
$
$
$
$
$
$
71,372
33.70
11,511
5.43
8,981
5,537
2.61
3rd 2018
1,713
1,962
79,055
40.29
$
$
72 %
$
$
$
$
$
$
$
60,132
30.65
18,923
9.64
5,856
4,639
2.36
2,122
2,015
78,205
38.81
$
$
74 %
$
$
$
$
$
$
$
60,082
29.82
18,123
8.99
8,264
4,115
2.04
4th 2018
1,938
2,219
89,019
40.12
$
$
68 %
$
$
$
$
$
$
$
69,364
31.26
19,655
8.86
8,996
7,186
3.24
8,221
8,070
317,436
39.34
247,640
30.69
69,796
8.65
35,533
22,488
2.79
T4Qs
7,609
7,365
291,783
39.62
214,945
29.18
76,838
10.43
33,064
22,655
3.08
For 2019, we sold 8,070,000 tons at an average price of $39.34/ton. For 2018, we sold 7,365,000 tons an average price of
$39.62/ton. The decrease 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 $30.69/ton and $29.18/ton for the years ended December 31, 2019 and 2018,
respectively. We encountered challenging mining conditions at Oaktown 2 in Q3 2019, and the re-opening of the Carlisle Mine in
July 2018 increased our costs over the prior year. With the closure of the Carlisle Mine, we expect operating costs for our coal
mines to return to $28‑$30/ton in 2020.
Operating costs associated for the idled Prosperity mine were $1.5 million and $1.3 million for the years ending December 31,
2019 and 2018, respectively. We expect operating costs to be $1.3 million in 2020.
Other income increased $4.3 million in 2019. The largest contributor to this increase was the sale of overriding royalty interests in
certain oil producing properties for $2.9 million. Other items contributing to the increase include the sale of scrap and other non-
producing assets in 2019.
DD&A increased approximately $4.4 million in 2019. A portion of our assets are depreciated based on raw production which
increased in 2019, thus as production increases so does our DD&A. Additionally, in July 2018, we began depreciating assets
relating to the Carlisle Mine that had been idled since 2015.
SG&A expenses increased approximately $1.0 million in 2019 due to additional hiring and business development expenses. We
expect SG&A for 2020 to be $12 million.
33
Our Sunrise Coal employees and contractors totaled 907 at December 31, 2019, compared to 842 at December 31, 2018. With
the closing of the Carlisle Mine, our head count has been reduced to 760 as of February 29, 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, 2019, 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 2019 was 27% compared to (116)% for 2018. The negative ETR in 2018 is due mostly to the
statutory depletion deduction which is in excess of our book income. The tax rate for the years ended December 31, 2019 and
2018 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.
34
ITEM 8. FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Comprehensive Income (Loss)
Consolidated Statements of Cash Flows
Consolidated Statement of Stockholders’ Equity
Notes to Consolidated Financial Statements
35
36
38
39
40
42
43
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors
Hallador Energy Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying balance sheets of Hallador Energy Company (the “Company”) as of December 31, 2019, and
2018, the related statements of comprehensive income (loss), stockholders' equity, and cash flows for each of the years in the two-
year period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). We also have
audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal
Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the
“COSO framework”).
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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the two-
year period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of
America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as
of December 31, 2019, based on criteria established in the COSO framework.
Basis for Opinion
The Company's management is responsible for these financial statements, for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying
Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s
financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public
accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) 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
audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements 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. Our audit of internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design
and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our
opinions.
36
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of
the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
We have served as the Company’s auditor since 2003.
/S/PLANTE & MORAN, PLLC
Denver, Colorado
March 9, 2020
37
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
Consolidated Balance Sheets
As of December 31,
(in thousands, except per share data)
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash (Note 13)
Certificates of deposit
Marketable securities
Accounts receivable
Prepaid income taxes
Inventory (Note 3)
Parts and supplies, net of allowance of $274 and $1,595, respectively
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 (Note 16)
Other assets (Note 4)
Total assets
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS, AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net (Note 5)
Accounts payable and accrued liabilities (Note 6)
Total current liabilities
Long-term liabilities:
Bank debt, net (Note 5)
Deferred income taxes (Note 9)
Asset retirement obligations (ARO)
Other
Total long-term liabilities
Total liabilities
Redeemable noncontrolling interests (Note 17)
Stockholders' equity:
$
$
$
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
Common stock, $.01 par value, 100,000 shares authorized; 30,420 and 30,245 issued and outstanding,
respectively
Additional paid-in capital
Retained earnings
Total stockholders’ equity
Total liabilities, redeemable noncontrolling interests, and stockholders’ equity
$
See accompanying notes.
38
2019
2018
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
4,619
15,694
4,346
165,253
230,097
4,000
—
304
102,215
89,011
191,530
425,627
$
$
$
$
15,502
4,592
488
1,842
18,428
2,606
20,507
9,645
11,368
84,978
130,897
365,481
140,990
637,368
(224,730)
412,638
3,666
14,217
515,499
25,392
26,421
51,813
155,655
26,441
14,586
8,130
204,812
256,625
4,000
—
302
100,742
153,830
254,874
515,499
Hallador Energy Company
Consolidated Statements of Comprehensive Income (Loss)
For the years ended December 31,
(in thousands, expect per share data)
2019
2018
$
317,436 $
6,026
323,462
REVENUE AND OTHER INCOME:
Coal sales
Other operating income (Note 8)
Total revenue and other income
COSTS AND EXPENSES:
Operating costs and expenses
DD&A
ARO accretion
Exploration costs
SG&A
Interest
Asset impairment
(1)
Total costs and expenses
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX BENEFIT (NOTE 9):
Current
Deferred
Total income tax benefit
NET INCOME (LOSS)
NET INCOME (LOSS) PER SHARE (NOTE 14):
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
291,783
1,774
293,557
215,363
44,167
1,167
1,185
11,841
16,288
—
290,011
3,546
(1,788)
(2,287)
(4,075)
7,621
247,866
48,572
1,272
1,225
12,848
15,998
77,882
405,663
(82,201)
(525)
(21,822)
(22,347)
(59,854) $
$
$
(1.95) $
0.25
30,253
30,074
$
11,511 $
2,186
2,095
206
4,487
15,998 $
$
11,883
2,182
2,024
199
4,405
16,288
See accompanying notes.
39
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
2019
2018
OPERATING ACTIVITIES:
Net income
Deferred income taxes
Equity loss – Sunrise Energy
DD&A
Asset impairment
Loss (gain) on sale of assets
Unrealized (gain) loss on marketable securities
Gain on sale of royalty interests in oil properties
Change in fair value of interest rate swaps
Amortization and write off of deferred financing costs
Accretion of ARO
Stock-based compensation
Allowance for parts and supplies inventory obsolescence
Change in current assets and liabilities:
Accounts receivable
Inventory
Parts and supplies
Prepaid income taxes
Prepaid expenses
Accounts payable and accrued liabilities
Other
Cash provided by operating activities
40
$
$
(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
2,577
3,608
—
38,243
$
$
7,621
(2,287)
187
44,167
—
561
226
—
2,182
2,024
1,167
3,170
800
(1,666)
(7,703)
(402)
293
(4,853)
5,701
382
51,570
Hallador Energy Company
Consolidated Statement 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
Proceeds from sale of Savoy
Cash used in investing activities
FINANCING ACTIVITIES:
Payments on bank debt
Borrowings of bank debt
Deferred financing costs
Proceeds from noncontrolling interests (Note 14)
Taxes paid on vesting of RSUs
Dividends
Cash used in financing activities
Increase (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
Cash received for income taxes, net
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Capital expenditures included in accounts payable and prepaid expense
Right-of-use assets acquired by operating lease
See accompanying notes.
41
2019
2018
(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 $
11,639
1,569
$
(35,091)
—
77
—
1,007
8,000
(26,007)
(38,793)
19,000
(730)
4,000
(298)
(4,942)
(21,763)
3,800
16,294
20,094
15,502
4,592
20,094
11,433
2,081
5,849
800
$
(4,837)
—
$
$
$
$
$
Hallador Energy Company
Consolidated Statement of Stockholders’ Equity
(in thousands)
Common Stock Issued
Amount
Shares
Additional
Paid-in
Capital
Retained
Earnings
BALANCE, DECEMBER 31, 2017
29,955 $
299
$
97,873 $
150,236
$
Total
Stockholders'
Equity
$
249,323
AOCI*
915
Impact from adoption of new accounting
standards
Stock-based compensation
Stock issued on vesting of RSUs
Taxes paid on vesting of RSUs
Dividends
Net income
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
—
—
345
(55)
—
—
30,245
—
297
(122)
—
—
30,420 $
—
3
—
—
—
302
—
2
—
—
—
304
—
3,170
(3)
(298)
100,742
1,833
(2)
(358)
—
—
102,215 $
$
915
—
—
—
(4,942)
7,621
153,830
—
—
—
(4,965)
(59,854)
89,011
(915)
—
—
—
—
—
—
—
—
—
—
—
— $
$
—
3,170
—
(298)
(4,942)
7,621
254,874
1,833
—
(358)
(4,965)
(59,854)
191,530
* Accumulated Other Comprehensive Income
See accompanying notes.
42
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 segments include the 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 these segments 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 location 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, 2019 and 2018, 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. 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.
43
If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this
review indicates that the carrying value of the asset will not be recoverable through estimated undiscounted future net cash flows
related to the asset over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset to its
estimated fair value. See Note 2 for further discussion of impairments.
Mine Development
Costs of developing new mines, including asset retirement obligation assets, or significantly expanding the capacity of existing
mines, are capitalized and amortized using the units-of-production method over estimated recoverable reserves.
Asset Retirement Obligations (ARO) – Reclamation
At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated
fair value, with a corresponding charge to mine development. Obligations are typically incurred when we commence development
of underground and surface mines and include reclamation of support facilities, refuse areas and slurry ponds.
Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from
the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production
method over estimated recoverable (proved and probable) reserves. We are using discount rates ranging from 5.0% to
10%. 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
Statement of Cash Flows
Year Ended December 31,
2019
2018
$
$
14,646
1,272
95
(249)
15,764
(70)
15,694
$
$
$
13,806
1,167
—
(327)
14,646
(60)
14,586
Cash equivalents include investments with maturities when purchased of three months or less.
44
Income Taxes
Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on pretax financial
income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences
between income tax and financial reporting and principally relate to differences in the tax basis of assets and liabilities and their
reported amounts, using enacted tax rates in effect for the year in which differences are expected to reverse.
Net Income (Loss) per Share
Basic net income (loss) per share is computed on the basis of the weighted average number of shares of common stock
outstanding during the period using the two-class method for our common shares and RSUs which share in the Company’s
earnings. Diluted net income (loss) per share is computed on the basis of the weighted average number of shares of common
stock plus the effect of dilutive potential common shares outstanding during the period. Dilutive potential common shares include
restricted stock units and are included in basic net income (loss) per share, using the two-class method.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates
and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the
date of the financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual amounts
could differ from those estimates. The most significant estimates included in the preparation of the financial statements relate to:
(i) deferred income tax accounts, (ii) coal reserves, (iii) depreciation, depletion, and amortization, (iv) estimates relating to interest
rate swaps, and (v) estimates used in our impairment analysis and measurement of impairments.
Long-term Contracts
As of December 31, 2019, we are committed to supplying our customers up to a maximum of 22.9 million tons of coal through
2024 of which 14.5 million tons are priced.
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.
For 2018, we derived 82% of our coal sales from four customers, each representing at least 10% of our coal sales. 77% of our
accounts receivable was from five customers, each representing more than 10% of the December 31, 2018 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.
New Accounting Standards Issued and Adopted
In February 2016, the FASB issued ASU 2016‑02, Leases (Topic 842) (ASU 2016‑02). ASU 2016‑02 increases transparency and
comparability among organizations by requiring lessees to record right-to-use assets and corresponding lease liabilities on the
balance sheet and disclose key information about lease arrangements. The new guidance classifies leases as either finance or
operating, with classification affecting the pattern of income recognition in the statement of income. ASU 2016‑02 is effective for
fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.
The FASB issued clarifications, updates and implementation guidance to ASU 2016‑02, such as ASU 2018‑11, Leases (Topic 842)
(ASU 2018‑11) which provides practical expedients for transition to Topic 842. ASU 2018‑11 provides an option to apply the
transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented and permits
lessors to not separate non-lease components from the associated lease component if certain conditions are met.
45
We adopted ASU 2016‑02 effective January 1, 2019 and elected the option to not restate comparative periods in transition and
also elected the practical expedients within the standard which permits us to not reassess our prior conclusions about lease
identification, lease classification and initial direct costs. Additionally, the Company made an election to not separate lease and
non-lease components for all leases and will not use hindsight. The adoption of the standard had no impact on the Company’s
consolidated income statement or statement of cash flows. Effective January 1, 2019, we recorded a right-to-use asset and
corresponding lease liability of $0.5 million.
New Accounting Standards Issued and Not Yet Adopted
In June 2016, the FASB issued ASU 2016‑13, Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on
Financial Instruments (ASU 2016‑13). ASU 2016‑13 changes the impairment model for most financial assets and certain other
instruments to require the use of a new forward-looking "expected loss" model that generally will result in earlier recognition of
allowances for losses. The new standard will require disclosure of significantly more information related to these items. ASU
2016‑13 is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early
adoption permitted for the fiscal year beginning after December 15, 2018, including interim periods. We are currently evaluating the
effect of adopting ASU 2016‑13, but do not anticipate it will have a material impact on our condensed consolidated financial
statements.
(2) LONG-LIVED ASSET IMPAIRMENTS
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 with the intent to recommence production in 2021, 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 is 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 have determined that
it is economically prudent to permanently close the Carlisle Mine. Equipment totaling $23 million is expected to be redeployed and
utilized at the Oaktown mines. We do not anticipate significant additional impairment costs to be recorded during Q1 2020 as a
result of the decision to close the Carlisle Mine. We anticipate exit and disposal costs to close the mine to be $3.0 million, which
will be 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
In December 2019, as a result of the Carlisle Mine impairment, we determined than an impairment of the Bulldog Reserves was
also necessary. The Bulldog permit was issued in April 2019 and we have been responding to challenges to the permit since that
time. 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 is a complete impairment of all assets. The fair value of the assets used in our assessment was
determined using a market approach.
46
Hourglass Sands
In December 2019, due to softness in the pricing of frac sand market, we determined that an impairment of the Hourglass Sands
project was necessary. Based on our review, we recorded an impairment of $2.9 million as of December 31, 2019, which included
inventory, land, mine development, buildings and equipment. The fair value of the assets used in our assessment was determined
using a market approach. The remaining fair market value of inventory, equipment, and buildings at Hourglass Sands is $1.9
million as of December 31, 2019.
(3) INVENTORY
Inventory is valued at lower of average cost or net realizable value (NRV). As of December 31, 2019, and December 31, 2018,
coal inventory includes NRV adjustments of $2.0 million and $1.3 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,
2019
2018
$
$
6,105
2,296
1,923
10,324
$
$
10,186
1,909
2,122
14,217
On September 30, 2019, we executed an amendment to our credit agreement with PNC, administrative agent for our lenders. The
primary purposes of the amendment were to extend the maturity by 16 months to September 2023 and to modify pricing to reduce
the interest rate by 50 basis points over the remainder of the term.
Our bank debt is comprised of term debt ($103 million as of December 31, 2019) and a $120 million revolver ($77 million borrowed
as of December 31, 2019). The term debt amortization concludes with a final payment in March 2023. The revolver matures
September 2023. Our debt is recorded at cost which approximates fair value due to the variable interest rates in the agreement
and is collateralized by our assets.
Liquidity
Our bank debt at December 31, 2019 was $180 million. As of December 31, 2019, we had additional borrowing capacity of $26
million and total liquidity of $35 million. Liquidity consists of our additional borrowing capacity, cash and cash equivalents, and
certificates of deposit.
Fees
Unamortized bank fees and other costs incurred in connection with the initial facility and subsequent amendments totaled $7.2
million as of our most recent amendment in September 2019. These costs were deferred and are being amortized over the term of
the loan. Unamortized costs as of December 31, 2019 and 2018, were $6.5 million and $7.4 million, respectively.
47
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,
2019
2018
34,912
(1,868)
33,044
145,238
(4,644)
140,594
180,150
(6,512)
173,638
$
$
$
$
$
$
27,563
(2,171)
25,392
160,900
(5,245)
155,655
188,463
(7,416)
181,047
$
$
$
$
$
$
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, 2019 through September 30, 2020
December 31, 2020 through September 30, 2021
December 31, 2021 and each fiscal quarter thereafter
Ratio
3.00 to 1.00
2.75 to 1.00
2.50 to 1.00
As of December 31, 2019, our Leverage Ratio of 2.62 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 1.25 to 1 through the maturity of the credit facility.
As of December 31, 2019, our Debt Service Coverage Ratio of 1.84 was in compliance with the requirements of the credit
agreement.
Rate
The interest rate on the facility ranges from LIBOR plus 2.25% to LIBOR plus 4.00%, depending on our Leverage Ratio. 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, 2019, we are paying LIBOR at the swap rate of 2.92% plus 3.00% for a total interest
rate of 5.92%. With the increase in the leverage ratio at December 31, 2019, the interest rate for 2020 will return to the swap rate
of 2.92% plus 3.5% for a total interest rate of 6.42% until such time the ratio falls below 2.50.
Future Maturities (in thousands):
2020
2021
2022
2023
Total
48
$
$
34,912
36,750
25,725
82,763
180,150
(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,
2019
2018
16,115
2,835
2,151
3,446
2,500
4,753
31,800
$
$
11,939
2,763
1,825
3,670
2,200
4,024
26,421
$
$
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).
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.
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 73% of our coal revenue for the years ended
December 31, 2019 and 2018, respectively, was sold to customers in the State of Indiana with the remainder sold to customers in
Florida, North Carolina, Kentucky, Alabama, 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
49
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 $585 million, which represent the
average fixed prices on our committed contracts as of December 31, 2019. We expect to recognize approximately 48% of this
revenue in 2020, with the remainder recognized thereafter.
We have remaining performance obligations relating to contracts with price reopeners of approximately $266 million, which
represents our estimate of the expected re-opener price on committed contracts as of December 31, 2019. We expect to recognize
all of this revenue beginning in 2020.
The tons used to determine the remaining performance obligations are subject to adjustment in instances of force majeure and
exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.
Contract Balances
Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable,
contract assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether
consideration is conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is
unconditional. Under the typical payment terms of our contracts with customers, the customer pays us a base price for the coal,
increased or decreased for any quality adjustments. Amounts billed and due are recorded as trade accounts receivable and
included in accounts receivable in our consolidated balance sheets. 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 and do not currently have any deferred
revenue recorded in our consolidated balance sheets.
(8) OTHER OPERATING INCOME (IN THOUSANDS)
Equity loss - Sunrise Energy
Loss on disposal of Savoy
MSHA reimbursements
Gain on sale of royalty interests in oil properties
Miscellaneous
Year Ended December 31,
2019
2018
(527)
—
575
2,949
3,029
6,026
$
$
(187)
(538)
1,013
—
1,486
1,774
$
$
50
(9) INCOME TAXES
Our income tax is different than the expected amount computed using the applicable federal and state statutory income tax
rates. 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
Stock-based compensation
Captive insurance
Return to provision adjustments
Other
$
$
2019
(17,262) $
(3,831)
(1,475)
326
(271)
(78)
244
(22,347) $
2018
737
(654)
(3,278)
(15)
—
(592)
(273)
(4,075)
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
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
2019
2018
$
18,956 $
1,801
555
524
135
1,294
23,265
(27,884)
$
(4,619) $
17,194
441
10
1,049
613
985
20,292
(46,733)
(26,441)
Our effective tax rate (ETR) for 2019 was 27% compared to (116)% for 2018. The negative ETR in 2018 is due mostly to the
statutory depletion deduction which was in excess of our book income. The tax rate for the years ended December 31, 2019 and
2018 are not predictive of future tax rates. Historically, our actual ETRs have been lower than the statutory effective rate primarily
due to the benefit received from statutory depletion allowances. The deduction for statutory depletion does not necessarily change
proportionately to changes in income before income taxes.
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, 2019, we had approximately $68 million and $100 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 2039 if they are not utilized.
51
(10) STOCK COMPENSATION PLANS
Restricted Stock Units (RSUs)
The table below shows the number of RSUs available for issuance at December 31, 2019:
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, 2017
Granted – weighted average share price on grant date was $5.76
Vested – weighted average share price on vesting date was $6.21
Forfeited
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
RSU Vesting Schedule
Vesting Year
2020
2021
2022
4,850,000
(2,977,652)
(488,500)
1,383,848
944,500
202,000
(344,750)
(12,500)
789,250
17,000
(297,250)
(20,500)
488,500
RSUs Vesting
176,250
303,250
9,000
488,500
Vested shares had a value of $0.9 million for 2019, and $2.1 million for 2018, 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 6, 2020 closing stock price of $0.95.
For the years ended December 31, 2019 and 2018 stock-based compensation was $1.8 million and $3.2 million, respectively. For
2020, 2021, and 2022 based on existing RSUs outstanding, stock-based compensation expense is estimated to be $1.2 million,
$1.1 million, and $0.0 million, respectively.
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.
52
(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 2,803 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 $17.0 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
$
$
2019
2018
16,228 $
2,510
727
19,465 $
13,020
1,861
722
15,603
Of the amounts in the above table, $18.9 million and $15.1 million are recorded in operating costs and expenses for 2019 and
2018, respectively with the remainder in SG&A.
Our mine employees are also covered by workers’ compensation and such costs for 2019 and 2018, were approximately $3.1 and
$3.0 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
2019
$
322
4.00
6.0 %
53
Future minimum lease payments under non-cancellable leases as of December 31, 2019 were as follows (in thousands):
Year
2020
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
235
201
206
174
59
875
(75)
800
800
$
$
$
$
At December 31, 2019, we had approximately $800,000 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 10 mining units dispersed over 22 miles.
The historical cost of such equipment was approximately $273 million and $255 million as of December 31, 2019 and December
31, 2018, respectively. As of February 29, with the closure of the Carlisle Mine, we are now operating seven mining units
dispersed over 10 miles.
Restricted cash of $4.5 million and $4.6 million as of December 31, 2019, and December 31, 2018, respectively, represents cash
held and controlled by a third party and is restricted for future workers’ compensation claim payments.
(14) NET INCOME (LOSS) PER SHARE
We compute net income (loss) per share using the two-class method, which is an allocation formula that determines net income
(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 income (loss) per share:
Numerator:
Net income (loss)
Less loss (earnings) allocated to RSUs
Net income (loss) allocated to common shareholders
Denominator:
Year Ended December 31,
2019
2018
$
$
(59,854)
907
(58,947)
$
$
7,621
(185)
7,436
Weighted average number of common shares outstanding
30,253
30,074
Net income (loss) per share:
Basic and diluted
$
(1.95)
$
0.25
54
(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 which are observable, either directly or indirectly, for substantially
the full term of the asset or liability. We have no Level 2 instruments.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement
and less observable from objective sources (i.e., supported by little or no market activity). Our Level 3 instruments are comprised
of interest rate swaps and impairment measurements. The fair values of our swaps were estimated using discounted cash flow
calculations based upon forward interest-rate yield curves. Although we utilize third-party broker quotes to 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 Q4 of 2019 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,
2019 and 2018 by respective level of the fair value hierarchy (in thousands):
Level 1
Level 2
Level 3
Total
December 31, 2019
Assets:
Marketable securities - restricted (Note 4)
$
2,296 $
— $
— $
2,296
Liabilities:
Interest rate swaps
December 31, 2018
Assets:
Marketable securities
Marketable securities - restricted (Note 4)
Liabilities:
Interest rate swaps
$
— $
— $
3,825 $
3,825
$
$
$
1,842 $
1,909
3,751 $
— $
—
— $
— $
—
— $
1,842
1,909
3,751
— $
— $
1,639 $
1,639
The table below highlights the change in fair value of the interest rate swaps which are based on a discounted future cash flow
model (in thousands):
Ending balance, December 31, 2017
Change in estimated fair value
Ending balance, December 31, 2018
Change in estimated fair value
Ending balance, December 31, 2019*
-------------------------------
*Recorded in other liabilities in the Balance Sheet to these Consolidated Financial Statements.
$
$
543
(2,182)
(1,639)
(2,186)
(3,825)
55
(16) EQUITY METHOD INVESTMENTS
Savoy Energy, L.P.
On March 9, 2018 we sold our entire 30.6% partnership interest to Savoy for $8 million. The carrying value of the investment
included in our consolidated balance sheets as of December 31, 2017, was $8.0 million. Our net proceeds were $7.5 million after
commissions paid to a related party, which were applied to our bank debt as required under the agreement. The sale resulted in a
loss of $538,000 for the year ended December 31, 2018.
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, 2019 and December 31, 2018, was $3.1 million and $3.7 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. See Note 2 to these consolidated financial
statements for further discussion.
(18)
SUBSEQUENT EVENTS
In January 2020, we declared a dividend of $.04 per share to shareholders of record as of January 31, 2020. The dividend was
paid on February 14, 2020.
56
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
Not applicable.
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, 2019.
Based on that evaluation, our management concluded that our ICFR was effective at December 31, 2019. Plante & Moran, PLLC
has audited and reported on our financial statements and our ICFR as of December 31, 2019. Their report is contained in this
Form 10‑K.
There were no significant changes in our internal control over financial reporting that occurred during the quarter ended
December 31, 2019 that have materially affected or are reasonably likely to materially affect our internal control over financial
reporting.
57
ITEM 9B. OTHER INFORMATION
EXECUTIVE OFFICER COMPENSATION
On March 5, 2020, the Compensation Committee approved a new Two-Year Compensation Plan (the “New Plan”), which terminates and
replaces the Four-Year Compensation Plan adopted in June 2017 (the “Old Plan”). The New Plan is intended to ensure retention of
executive and key personnel of the Corporation and address executive and key personnel compensation. The Plan is effective on January 1,
2020 and ends on March 31, 2022.
Under the New Plan, our executive officers receive salary, restricted stock units (RSUs), and an annual discretionary bonus as recommended
by the compensation committee to the board.
Restricted Stock Units
Mr. Brent K. Bilsland, our President and CEO, had 137,500 RSUs under the Old Plan that were cancelled. Mr. Lawrence D. Martin, our
CFO, had 75,000 RSUs under the Old Plan that were cancelled.
Mr. Bilsland will receive 137,500 RSUs under the New Plan. Mr. Martin will receive 75,000 RSUs under the new plan. The RSUs issued
under the New Plan will vest/lapse 50% each year on December 16, 2020 and December 16, 2021, or otherwise by the terms of the RSU
Plan and the applicable award agreements.
Two Year Plan Annual Base Salaries for 2020-2021
New annual salaries are set forth below:
· Mr. Bilsland’s salary shall be $500,000 per year
· Mr. Martin’s salary shall be $300,000 per year.
58
PART III
The information required for Items 10‑14 is hereby incorporated by reference to that certain information in our Proxy Statement to
be filed with the SEC during April 2020.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
59
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
See Item 8 for an index of our financial statements.
Our exhibit index is as follows:
3.1
3.2
4.1
10.1
10.2
10.3
10.5
10.6
10.7
14
21.1
23.1
31.1
31.2
31.3
32
95
101
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(1)
(4)
(8)
(3)
(1)
(2)*
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009.
By-laws of Hallador Energy Company, effective December 24, 2009
Description of Securities
2009 Stock Bonus Plan
Third Amended and Restated Credit Agreement dated May 21, 2018
Second Amendment to the Third Amended and Restated Credit Agreement as of September 30, 2019
Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement
Amended and Restated Hallador Energy Company 2008 Restricted Stock Unit Plan
Hallador Energy Company Four-Year Plan
Code of Ethics for Senior Financial Officers.
List of Subsidiaries
Consent of Plante & Moran, PLLC
SOX 302 Certification - President and CEO
SOX 302 Certifications - CFO
SOX 302 Certifications - CAO
SOX 906 Certification
Mine Safety Disclosure
Interactive data files.
(8)*
* (7)
* (5)
(8)
(8)
(8)
(8)
(8)
(5)
(8)
(8)
(8)
IBR to Form 8‑K dated December 31, 2009
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 8-K dated May 17, 2017
IBR to Form 10‑Q dated August 8, 2017
IBR to Form 8-k dated May 20, 2010
(8)
Filed herewith.
* Management Agreements
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 9, 2020
Date: March 9, 2020
HALLADOR ENERGY COMPANY
/s/LAWRENCE D. MARTIN
Lawrence D. Martin
/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 9, 2020
Director
March 9, 2020
Board Chairman, President and CEO
March 9, 2020
Director
March 9, 2020
61
Exhibit 4.1
DESCRIPTION OF SECURITIES
Exhibit 4.1
As of March 6, 2020, Hallador Energy Company (the “Corporation”) had one class of securities registered under
Section 12 of the Securities Exchange Act of 1934, as amended, which is common stock, as contained in Item
4.”Description of Securities” in Form S-8 Registration Statement (File No. 333-163431) filed with the Securities
and Exchange Commission on December 1, 2009, and incorporated herein by reference.
The following is a description of the rights of our authorized stock and related provisions of our Second Restated
Articles of Incorporation and Bylaws, as amended (collectively, our “Organizational Documents”). This description
is qualified in its entirety by, and should be read in conjunction with, our Organizational Documents.
Authorized Stock
We have a total of 110,000,000 shares authorized for issuance, which consists of 100,000,000 shares of
common stock, par value $0.01, and 10,000,000 shares of preferred stock, par value $0.10. The common and
preferred stock are fully paid and nonassessable.
Description of Common Stock
Voting - Each shareholder of record shall have one vote for each share of common stock standing in his name
on the books of the Corporation and entitled to vote. Cumulative voting shall not be allowed in the election of
directors or for any other purpose.
At all meetings of shareholders, one-third of the shares entitled to vote at such meeting represented in person or
by proxy shall constitute a quorum, and at any meeting at which a quorum is present, the affirmative vote of a
majority of the shares represented at such meeting and entitled to vote on the subject matters shall be the act of
the shareholders; except that the following actions shall require the affirmative vote or concurrence of the holders
of at least a majority of all of the outstanding shares of the Corporation entitled to vote thereon: (1) adopting an
amendment or amendments to these Articles, (2) lending money to, guaranteeing the obligations of or otherwise
assisting any of the directors of the Corporation, (3) authorizing the sale, lease, exchange or other disposition of
all or substantially all of the property and assets of the Corporation, with or without its goodwill, not in the usual
and regular course of business, (4) approving a plan of merger or consolidation, (5) adopting a resolution
submitted by the Board of Directors to dissolve the Corporation, and (6) adopting a resolution submitted by the
Board of Directors to revoke voluntary dissolution proceedings.
Shareholder Consent to Action - Any action required or permitted under Colorado law to be taken by the
shareholders may be taken by the shareholders without a meeting as evidenced by the written consent of the
shareholders holding at least a majority of all of the outstanding shares of the Corporation entitled to vote
thereon, unless a greater percentage is required by Colorado law or these Articles.
Transfer Agent and Registrar - The transfer agent and registrar for our common stock is Computershare Trust
Company, N.A.
Listing - Our common stock is listed on The Nasdaq Capital Market under the symbol “HNRG”.
Preferred Stock Description
Preferred stock may be issued in one or more series or classes with designations, preferences, limitations and
relative rights determined by our board of directors without any vote or action by our shareholders, subject to
limitations prescribed by Colorado law and the provisions of our Organizational Documents.
Any of the voting powers, designations, preferences, rights and qualifications, limitations or restrictions of any
such series of preferred stock may be made dependent upon facts ascertainable outside of our Organizational
Documents or of any amendment hereto, or outside the resolution or resolutions providing for the issue of such
stock adopted by the Board of Directors pursuant to authority expressly vested in it by these provisions, provided
that such facts and the manner in which such facts shall operate upon the voting powers, designations,
preferences, rights and qualifications, limitations or restrictions of such series of stock are clearly and expressly
set forth in the resolution or resolutions providing for the issue of such stock adopted by the Board of Directors.
Dividend Rights
Common and preferred stock are entitled to dividends if declared by our board of directors out of legally available
funds.
Payments upon Partial Liquidation
The Board of Directors may from time to time distribute to the shareholders in partial liquidation, out of either
stated capital or capital surplus of the Corporation, a portion of its assets, in cash or property, subject to the
limitations contained in the statutes of Colorado.
No Preemptive or Preferential Rights
No holder of any shares of any class of stock of the Corporation shall, as such holder, have any preemptive or
preferential right to receive, purchase, or subscribe to (1) any unissued or treasury shares of any class of stock,
whether now or hereafter authorized, of the Corporation, (2) any obligations, evidences of indebtedness, or other
securities of the Corporation convertible into or exchangeable for, or carrying or accompanied by any rights to
receive, purchase, or subscribe to, any such unissued or treasury shares, (3) any warrant or option for the
purchase of, any of the foregoing securities, or (4) any other securities that may be issued or sold by the
Corporation, other than such (if any) as the Board of Directors of the Corporation, in its sole and absolute
discretion, may determine from time to time.
Exhibit 21.1
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.
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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 9, 2020 relating to the financial statements as of
and for the years ended December 31, 2019 and 2018, and the effectiveness of internal control over financial reporting as of
December 31, 2019, which appears in this Form 10-K.
Denver, CO
March 9, 2020
/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) 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;
b) 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;
c) 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
d) 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) 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
b) 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 9, 2020
/s/BRENT K. BILSLAND
Brent K. Bilsland, President and CEO
CERTIFICATION
I, Lawrence D. Martin, certify that:
Exhibit 31.2
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) 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;
b) 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;
c) 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
d) 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) 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
b) 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 9, 2020
/s/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO
CERTIFICATION
I, R. Todd Davis, certify that:
Exhibit 31.3
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) 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;
b) 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;
c) 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
d) 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) 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
b) 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 9, 2020
/s/R. TODD DAVIS
R. Todd Davis, CAO
CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Hallador Energy Company (the "Company"), on Form 10-K for the period ended December
31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), 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:
Exhibit 32
(1)
(2)
March 9, 2020
March 9, 2020
March 9, 2020
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934;
and
The information contained in the Report fairly presents, in all material respects, the financial condition and results
of operations of the Company.
/s/BRENT K. BILSLAND
By; Brent K. Bilsland, President and CEO
/s/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO
/s/R. TODD DAVIS
R. Todd Davis
Exhibit 95 - Mine Safety Disclosure
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 rule making may require
disclosures to be filed in a different format than the following.
The table that follows outline required disclosures and citations/orders issued to us by MSHA during 2019. 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
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
Year Ending 2019
Section
104(a )
Citations
Section
104(b)
Orders
Section
104(d)
Citations/Orders
Section
107(a )
Orders
Section
110(b)(2)
Violations
Proposed
MSHA
Assessments
(In thousands)
23
0
0
19
37
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
$
26.75
0
$
0.00
0
$
0.95
0
$
35.50
0
$
54.20
0
$
2.00
0
$
0.00
Section
104(e)
Notice
Yes/No
Section
104(e)
POV
Yes/No
Mining
Related
Fatalities
Lega l
Actions
Pending
Legal
Actions
Initiated
Lega l
Actions
Resolved
No
No
No
No
0
0
0
0
0
0
0
0
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
‐
No
No
No
No
No
No
No
No
No
No
Contest of Contest
Citations/
Orders
of
Penalties
0
0
0
0
0
0
0
0
0
0
0
1
0
1
0
0
1
0
1
0
Complaints Complaints Applications Appeals of
Decisions/
of Discharge/
of
Compensation Discrimination
of Temp.
Relief
0
0
0
1
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
Orders
0
0
0
0
0
0
0