UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
x ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2018 OR
¨ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 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)
1660 Lincoln Street, Suite 2700, Denver, Colorado
(Address of principal executive offices)
Issuer's telephone number: 303.839.5504
84-1014610
(IRS Employer Identification No.)
80264-2701
(Zip Code)
Securities registered pursuant to Section 12(b) of the Exchange Act:
Common Stock, par value $.01 per share
Name of each Exchange on which registered
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 þ
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 þ
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 þ
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 þ
No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. ¨
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)
þ
Accelerated filer
þ
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 þ
The aggregate market value of the common stock held by non-affiliates (public float) on June 29, 2018 was $125,602,524 based on the closing price
reported that date by the NASDAQ of $7.14 per share.
As of March 8, 2019, we had 30,244,599 shares outstanding.
Portions of our Proxy Statement to be filed with the SEC in connection with our annual stockholders’ meeting are incorporated by reference into
Part III of this Form 10-K. Our Annual Meeting of Shareholders will be held on May 23, 2019 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:
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
·
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 post-mine reclamation and
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;
a loss or reduction of benefits from certain tax deductions and credits;
difficulty obtaining commercial property insurance;
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.”
2
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- MDA for a discussion of our business.
Regulation and Laws
The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:
employee health and safety;
·
· mine permits and other licensing requirements;
air quality standards;
·
· water quality standards;
·
storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could reach
waterways or wetlands;
plant and wildlife protection;
reclamation and restoration of mining properties after mining is completed;
discharge of materials;
storage and handling of explosives;
·
·
·
·
· wetlands protection;
·
·
surface subsidence from underground mining; and
the effects, if any, that mining has on groundwater quality and availability.
In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has
adversely affected demand for coal. It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be
interpreted differently or more stringently enforced, any of which could have a significant impact on our mining operations or our customers’ ability to
use coal. For more information, please see risk factors described in “Item 1A. Risk Factors” below.
We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because
of the extensive and detailed nature of these regulatory requirements, particularly the regulatory system of the Mine Safety and Health
Administration (“MSHA”) where citations can be issued without regard to fault, and many of the standards include subjective elements, it is not
reasonable to expect any coal mining company to be free of citations. When we receive a citation, we attempt to remediate any identified condition
immediately. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those
costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of
coal mining for domestic coal producers.
Capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost
of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset
retirement obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations and mine
closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with
mine closures, future operating results would be adversely affected if these accruals were insufficient.
3
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.
The FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without
fault, and FMSHA requires imposition of a civil penalty for each cited violation. Negligence and gravity assessments and other factors can result in
the issuance of various types of orders, including orders requiring withdrawal from the mine or the affected area, and some orders can also result in
the imposition of civil penalties. The FMSHA also contains criminal liability provisions. For example, criminal liability may be imposed upon
corporate operators who knowingly and willfully authorize, order or carry out violations of the FMSHA, or its mandatory health and safety standards.
The Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) significantly amended the FMSHA, imposing more
extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and
expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new
or more stringent rules and policies on a variety of topics, including:
sealing off abandoned areas of underground coal mines;
·
· mine safety equipment, training, and emergency reporting requirements;
·
·
·
·
·
substantially increased civil penalties for regulatory violations;
training and availability of mine rescue teams;
underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;
flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and
post-accident two-way communications and electronic tracking systems.
4
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. On July 9, 2018, MSHA published a request for information to solicit
stakeholder comments, data, and information for the development of a framework to conduct a retrospective study on the impact of the final rule, as
well as a request for information and data on engineering controls and best practices used by mine operators to lower miners' exposure to respirable
coal dust. 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.
In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust. Following a comment period that
closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel
Exhaust Partnership to address the issues covered by MSHA's request for information. The comment period for the request for information was
reopened and closed in January 2018. The comment period was reopened again in March 2018 and is scheduled to close in March 2019. It is
uncertain what MSHA will do with this information.
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 closed on December 24, 2018. 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.
5
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 state and federal 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. As of January 1, 2019, the excise tax rates have
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.
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 CMHSA, as amended, and
various state statutes for the payment of medical and disability benefits to eligible recipients related to coal worker's pneumoconiosis, or black lung.
We also provide for these claims through self-insurance programs. Our actuarial calculations are based on numerous assumptions including
disability incidence, medical costs, mortality, death benefits, dependents and discount rates.
The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus
potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria. These
regulations may also increase black lung related medical costs by broadening the scope of conditions for which medical costs are reimbursable and
increase legal costs by shifting more of the burden of proof to the employer.
The Patient Protection and Affordable Care Act enacted in 2010 includes significant changes to the federal black lung program retroactive to 2005,
including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption
with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.
These changes could have a material impact on our costs expended in association with the federal black lung program.
Surface Mining Control and Reclamation Act
The Federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes establish operational, reclamation and
closure standards for all aspects of surface mining as well as many aspects of underground mining. Currently, ~96% of our production capacity
involves underground room and pillar mining (no surface subsidence), and ~4% involves surface mining. We do not engage in either mountain top
removal or long-wall mining. SMCRA nevertheless requires that comprehensive environmental protection and reclamation standards be met during
the course of and upon completion of our mining activities.
SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and
approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as
practicable. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining
operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence
of longwall mining and possibly other mining operations. We believe we are in compliance in all material respects with applicable regulations
relating to reclamation.
6
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.
The U.S. Office of Surface Mining Reclamation (“OSM”) published in November 2009 an Advance Notice of Proposed Rulemaking, announcing its
intent to revise the Stream Buffer Zone (“SBZ”) rule published in December 2008. The SBZ rule prohibits mining disturbances within 100 feet of
streams if there would be a negative effect on water quality. Environmental groups brought lawsuits challenging the rule, and in a March 2010
settlement, the OSM agreed to rewrite the SBZ rule. In January 2013, the environmental groups reopened the litigation against OSM for failure to
abide by the terms of the settlement. Oral arguments were heard on January 31, 2014. OSM published a notice in December 2014, to vacate the
2008 SBZ rule to comply with an order issued by the U.S. District Court for the District of Columbia. OSM reimplemented the 1983 SBZ rule.
Subsequent attempts by OSM to issue a revised stream protection rule met with Congressional opposition, ultimately resulting in the passage of a
resolution under the Congressional Review Act that revoked OSM's stream protection rule and prevents the agency from promulgating a
substantially similar rule absent future legislation. Whether Congress will enact future legislation to require a new stream protection rule remains
uncertain.
In December 2009, the United States Environmental Protection Agency (“EPA”) issued proposed rules on coal combustion residues (“CCRs”) in
2010. This final rule was published in December 2014. The EPA's 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 our competitors and us 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 state and federal laws would have a material adverse effect on our ability
to produce coal, which could affect our profitability and cash flow.
7
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 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 state and federal 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 coal a less attractive fuel alternative in the planning and building of
power plants in the future. A significant reduction in coal’s 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 over 600
coal-fired electric generating units through 2030 in the United States, nearly 40% of the U.S. coal fleet.
In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may affect our operations, directly or indirectly,
include, but are not limited to, the following:
·
·
The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities.
Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions
allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected
facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions.
In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the
EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems,
or “scrubbers,” or by reducing electricity generating levels. These requirements would not be supplanted by a replacement rule for the
Clean Air Interstate Rule (“CAIR”), discussed below.
The CAIR calls for power plants in 28 states and Washington, D.C. to reduce emission levels of sulfur dioxide and nitrogen oxide
pursuant to a cap-and-trade program similar to the system in effect for acid rain. In June 2011, the EPA finalized the Cross-State Air
Pollution Rule (“CSAPR”), a replacement rule for CAIR, which would have required 28 states in the Midwest and eastern seaboard to
reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. Under CSAPR,
the first phase of the nitrogen oxide and sulfur dioxide emissions reductions would have commenced in 2012 with further reductions
effective in 2014. However, in August 2012, the D.C. Circuit Court of Appeals vacated CSAPR, finding the EPA exceeded its statutory
authority under the CAA and striking down the EPA’s decision to require federal implementation plans (“FIPs”), rather than SIPs, to
implement mandated reductions. In its ruling, the D.C. Circuit Court of Appeals ordered the EPA to continue administering CAIR but
proceed expeditiously to promulgate a replacement rule for CAIR. The U.S. Supreme Court granted the EPA’s certiorari petition
appealing the D.C. Circuit Court of Appeals’ decision and heard oral arguments in December 2013. In April 2014, the U.S. Supreme
Court reversed and remanded the D.C. Circuit Court of Appeals’ decision, concluding that the EPA’s approach is lawful. CSAPR has
been reinstated, and the EPA began implementation of Phase 1 requirements in January 2015. In September 2016, the EPA finalized
the CSAPR Update to respond to the remand by the D.C. Circuit Court of Appeals. Implementation of Phase 2 began in 2017. In
December 2018, the EPA determined that the CSAPR Update rule satisfies "good neighbor" obligations for the 2008 national ambient
air quality standards ("NAAQS") for ground-level ozone. Litigation is pending against the CSAPR Update in the D.C. Circuit Court of
Appeals. The impacts of CSAPR Update are unknown at the present time due to the implementation of Mercury and Air Toxic
Standards ("MATS"), discussed below, and the significant number of coal retirements that have resulted and that potentially will result
from MATS.
8
·
·
·
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.
Appeals were filed, and oral arguments were heard by the D.C. Circuit Court of Appeals in December 2013. In April 2014, the D.C.
Circuit Court of Appeals upheld MATS. In June 2015, the U.S. Supreme Court remanded the final rule back to the D.C. Circuit holding
that the agency must consider cost before deciding whether regulation is necessary and appropriate. In December 2015, the EPA
issued, for comment, the proposed Supplemental 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.
In January 2013, the EPA issued final Maximum Achievable Control Technology (“MACT”) standards for several classes of boilers and
process heaters, including large coal-fired boilers and process heaters (“Boiler MACT”), which require owners of industrial, commercial,
and institutional boilers to comply with standards for air pollutants, including mercury and other metals, fine particulates, and acid gases
such as hydrogen chloride. Businesses and environmental groups have filed legal challenges to Boiler MACT in the D.C. Circuit Court
of Appeals and petitioned the EPA to reconsider the rule. In December 2014, the EPA announced reconsideration of the standard and
will accept public comment on five issues for its standards on area sources, will review three issues related to its major-source boiler
standards, and four issues relating to commercial and solid waste incinerator units. Before reconsideration, the EPA estimated the
rule would affect 1,700 existing major source facilities with an estimated 14,316 boilers and process heaters. While some owners would
make capital expenditures to retrofit boilers and process heaters, a number of boilers and process heaters could be prematurely
retired. Retirements are likely to reduce the demand for coal. In August 2016, the D.C. Circuit Court of Appeals vacated a portion of
the rule while remanding portions back to the EPA. In December 2016, the D.C. Circuit Court of Appeals agreed to the EPA request to
remand the rule back to the EPA without vacatur. In March 2018, the D.C. Circuit affirmed the rule's startup and shutdown work practice
standards but remanded a portion of the rule to reconsider the EPA's decision to adopt the 130 ppm carbon monoxide limits. The
impact of the regulations will depend on the EPA's reconsideration and the outcome of subsequent legal challenges.
The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the 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. Industry and state petitioners have filed challenges to the final
rule as have several environmental groups. Attainment dates for the new standards range between 2013 and 2030, depending on the
severity of the non-attainment. In April 2017, the D.C. 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 2015 Rule. In July 2009, the D.C. Circuit Court of Appeals vacated part of
a rule implementing the ozone NAAQS and remanded certain other aspects of the rule to the EPA for further consideration. In
June 2013, the EPA proposed a rule for implementing the 2008 ozone NAAQS. Under a consent decree published in the Federal
Register in January 2017, the EPA has agreed to review the NAAQS for nitrogen oxides with a final decision due by 2018 and review
the NAAQS for sulfur oxide with a final decision due by 2019. In July 2017, the EPA proposed to retain the current NAAQS for nitrogen
oxides. The comment period for the proposal closed in September 2017. In June 2018, the EPA proposed to retain the existing sulfur
oxide standards. The comment period for the proposal closed in August 2018. 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.
9
·
·
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 June 2018, the EPA proposed to
retain the existing sulfur oxide standards. The comment period for the proposal closed in August 2018.
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. Depending on the ultimate resolution of these cases, demand for coal could be affected.
Carbon Dioxide Emissions
Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide, which is considered a GHG. 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, the Kyoto Protocol set binding emission targets for developed
countries that ratified it (the U.S. did not ratify, and Canada officially withdrew from its Kyoto commitment in 2012) to reduce their global GHG
emissions. The Kyoto Protocol was nominally extended past its expiration date of December 2012, with a requirement for a new legal construct to
be put into place by 2015. The United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an
international climate agreement (Paris Agreement). Although this agreement does not create any binding obligations for nations to limit their GHG
emissions, it does include pledges to voluntarily limit or reduce future emissions. These commitments could further reduce demand and prices for
our coal. In June of 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement, which has a four-year exit process.
Future participation in the Paris Agreement by the U.S. remains uncertain. However, many states, regions and governmental bodies have adopted
GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired
electric generating facilities. Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil
fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be
negatively impacted, which would have an adverse effect on our operations.
Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S. Supreme Court’s
2007 decision in Massachusetts v. Environmental Protection Agency that the EPA has authority to regulate GHG emissions. In 2009, the EPA
issued a final rule, known as the “Endangerment Finding,” declaring that GHG emissions, including carbon dioxide and methane, endanger public
health and welfare and that six GHGs, including carbon dioxide and methane, emitted by motor vehicles endanger both the public health and
welfare.
10
In May 2010, the EPA issued its final “tailoring rule” for GHG emissions, a policy aimed at shielding small emission sources from CAA permitting
requirements. The EPA’s rule phases in various GHG-related permitting requirements beginning in January 2011. Beginning July 1, 2011, the EPA
requires facilities that must already obtain NSR permits (new or modified stationary sources) for other pollutants to include GHGs in their permits for
new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000
tons per year. These permits require that the permittee adopt the Best Available Control Technology (“BACT”). In June 2014, the U.S. Supreme
Court invalidated the EPA’s position that power plants and other sources can be subject to permitting requirements based on their GHG emissions
alone. For CO2 BACT to apply, CAA permitting must be triggered by another regulated pollutant (e.g., SO2).
As a result of revisions to its preconstruction permitting rules that became fully effective in 2011, the EPA now requires new sources, including coal-
fired power plants, to undergo control technology reviews for GHGs (predominantly carbon dioxide) as a condition of permit issuance. These
reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as
increase litigation risk for and so discourage development of coal-fired power plants. The EPA has also issued final rules requiring the monitoring
and reporting of greenhouse gas emissions from certain sources.
In March 2012, the EPA proposed New Source Performance Standards (“NSPS”) for carbon dioxide emissions from new fossil fuel-fired power
plants. The proposal requires new coal units to meet a carbon dioxide emissions standard of 1,000 lbs. CO2/MWh, which is equivalent to the
carbon dioxide emitted by a natural gas combined cycle unit. In January 2014, the EPA formally published its re-proposed NSPS for carbon dioxide
emissions from new power plants. The re-proposed rule requires an emissions standard of 1,100 lbs. CO2/MWh for new coal-fired power plants.
To meet such a standard, new coal plants would be required to install carbon capture and storage (“CCS”) technology. In August 2015, the EPA
released final rules requiring newly constructed coal-fired steam electric generating units (“EGUs”) to emit no more than 1,400 lbs CO2/MWh (gross)
and be constructed with CCS to capture 16% of CO2 produced by an electric generating unit burning bituminous coal. At the same time, the EPA
finalized GHG emissions regulations for modified and existing power plants. The rule for modified sources required reducing GHG emissions from
any modified or reconstructed source and could limit the ability of generators to upgrade coal-fired power plants thereby reducing the demand for
coal. In April 2017, the EPA published notice in the federal register that the agency has initiated a review of the NSPS for new and modified fossil
fuel-fired power plants and that, following the review, the EPA will initiate reconsideration proceedings to suspend, revise or rescind this NSPS.
Challenges to the NSPS have been filed in U.S. Court of Appeal for the D.C. Circuit and oral arguments were set for April 2017; however, in April
2017, the U.S Court of Appeal for the D.C. Circuit ordered the NSPS case held in abeyance for an EPA review of the rule. In December 2018, the
EPA re-proposed the NSPS with a standard reflecting the performance of currently demonstrated supercritical technologies with an emission limit of
1,900 lbs. CO2/MWh for large units (heat input greater than 2,000 MMBtu/hour) and subcritical technologies with an emission limit of 2,000 lbs.
CO2/MWh for small units. 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 CO 2
emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP
before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision. By its terms, this stay will remain in
effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may
be granted. The Supreme Court's stay applies only to the EPA's regulations for CO 2 emissions from existing power plants and will not affect the
EPA's standards for new power plants. It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP.
Additionally, in October 2017 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. In connection with this proposed repeal, the EPA issued an Advance Notice of Proposed Rulemaking ("ANPRM") in
December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. The ANPRM seeks comment
regarding what the EPA should include in a potential new, existing-source regulation under the Clean Air Act of GHG emissions from electric utility
generating units that it may propose. In August 2018, the EPA 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. The EPA's attempts to
replace the CPP with the ACE rule are currently subject to litigation, and we cannot predict the final outcome.
11
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 rejected 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 coal-fired power plants 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 coal-fired power and may affect long-term demand for
our coal. Finally, a federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that
they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on
procedural grounds. The U.S. Supreme Court overturned that decision in June 2011, holding that federal common law provides no basis for public
nuisance claims against utilities due to their carbon dioxide emissions. The U.S. Supreme Court did not, however, decide whether similar claims
can be brought under state common law. As a result, despite this favorable ruling, tort-type liabilities remain a concern.
In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal
agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National
Environmental Policy Act (“NEPA”). These groups assert that the environmental analyses in question do not adequately consider the climate
change impacts of these particular projects. In December 2014, the Council on Environmental Quality (“CEQ”) released updated draft guidance
discussing how federal agencies should consider the effects of GHG emissions and climate change in their NEPA evaluations. The guidance
encourages agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably
foreseeable emissions and effects. This guidance could create additional delays and costs in the NEPA review process or in our operations, or
even an inability to obtain necessary federal approvals for our future operations, including due to the increased risk of legal challenges from
environmental groups seeking additional analysis of climate impacts. In April 2017, CEQ withdrew its final 2016 guidance on how federal agencies
should incorporate climate change and GHG considerations into NEPA reviews of federal actions; however, the potential remains for CEQ to issue
similar guidance in the future.
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. New Jersey is expected to rejoin RGGI, and
the recently elected governors of Pennsylvania and Virginia have expressed interest in 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, in November 2011, six
states withdrew, leaving California and the four Canadian provinces as members. At a January 2012 stakeholder meeting, this group confirmed a
commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national
approaches in both Canada and the U.S. to reduce GHG emissions. It is likely that these regional efforts will continue.
12
It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with coal
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 coal 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.
Water Discharge
The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on
effluent discharge into waters and the discharge of dredged or fill material into the waters of the U.S. Regular monitoring, as well as compliance
with reporting requirements and performance standards, is a precondition for the issuance and renewal of permits governing the discharge of
pollutants into water. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of wetlands
and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact
wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits
required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under
existing and possible future “fill” permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for
such mitigation projects is difficult to ascertain with certainty and may increase in the future. Although more stringent permitting requirements may
be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.
The U.S. Army Corps of Engineers (“Corps of Engineers”) maintains two permitting programs under CWA Section 404 for the discharge of dredged
or fill material: one for “individual” permits and a more streamlined program for “general” permits. In June 2010, the Corps of Engineers suspended
the use of “general” permits under Nationwide Permit 21 (“NWP 21”) in the Appalachian states. In February 2012, the Corps of Engineers reissued
the final 2012 NWP 21. The Center for Biological Diversity later filed a notice of intent to sue the Corps of Engineers based on allegations the 2012
NWP 21 program violated the Endangered Species Act (“ESA”). The Corps of Engineers and National Marine Fisheries Service (“NMFS”) have
completed their programmatic ESA Section 7 consultation process on the Corps of Engineers’ 2012 NWP 21 package, and NMFS has issued a
revised biological opinion finding that the NWP 21 program does not jeopardize the continued existence of threatened and endangered species and
will not result in the destruction or adverse modification of designated critical habitat. However, the opinion contains 12 additional protective
measures the Corps of Engineers will implement in certain districts to “enhance the protection of listed species and critical habitat.” While these
measures will not affect previously verified permit activities where construction has not yet been completed, several Corps of Engineers districts with
mining operations will be impacted by the additional protective measures going forward. These measures include additional reporting and
notification requirements, potential imposition of new regional conditions and additional actions concerning cumulative effects analyses and
mitigation. Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream
impoundments. The CWA authorizes the EPA to review Section 404 permits issued by the Corps of Engineers, and in 2009, the EPA began
reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia. Currently, significant uncertainty exists regarding the
obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.
The EPA also has statutory “veto” power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that
the permit will have an “unacceptable adverse effect.” In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a
previously issued permit for Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in
Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to
the EPA’s exercise of this 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.
13
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 stayed nationwide by the U.S. Court of Appeals for the Sixth
Circuit and stayed for certain primarily western states by a United States District Court in North Dakota. In January 2018, the Supreme Court
determined that the circuit courts do not have jurisdiction to hear challenges to the 2015 rule, removing the basis for the Sixth Circuit to continue its
nationwide stay. Additionally, the EPA has promulgated a final rule that extends the applicability date of the 2015 rule for another two years in order
to allow the EPA to undertake a rulemaking on the question of what constitutes a water of the United States. In the meantime, judicial challenges to
the 2015 rulemaking are likely to continue to work their way through the courts along with challenges to the recent rulemaking that extends the
applicability date of the 2015 rule. For now, the EPA and the Corps of Engineers will continue to apply the existing standard for what constitutes a
water of the United States as determined by the Supreme Court in the Rapanos case and post-Rapanos guidance. Should the 2015 rule take effect,
or should a different rule expanding the definition of what constitutes a 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 issued a proposed rule to revise the definition "to increase CWA program
predictability and consistency by increasing clarity as to the scope of 'waters of the United States' federally regulated under the Act." 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 corresponding state laws regulating hazardous waste affect coal mining
operations by imposing requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous wastes. Many
mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by
statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous
substances. In addition, each state has its own laws regarding the proper management and disposal of waste material. While these laws impose
ongoing compliance obligations, such costs are not believed to have a material impact on our operations.
In June 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion by-products (“CCB”). The proposed rule set
forth two very different options for regulating CCB under RCRA. The first option called for regulation of CCB as a hazardous waste under Subtitle C,
which creates a comprehensive program of federally enforceable requirements for waste management and disposal. The second option utilized
Subtitle D, which would give the EPA authority to set performance standards for waste management facilities and would be enforced primarily
through citizen suits. The proposal leaves intact the Bevill exemption for beneficial uses of CCB. In April 2012, several environmental organizations
filed suit against the EPA to compel the EPA to take action on the proposed rule. Several companies and industry groups intervened. A consent
decree was entered on January 29, 2014.
14
The EPA finalized the CCB rule on December 19, 2014, setting nationwide solid, nonhazardous waste standards for CCB disposal. On April 17,
2015, the EPA finalized regulations under the solid waste provisions of Subtitle D of RCRA and not the hazardous waste provisions of Subtitle C
which became effective on October 19, 2015. The EPA affirms in the preamble to the final rule that “this rule does not apply to CCR placed in active
or abandoned underground or surface mines.” Instead, “the U.S. Department of Interior (“DOI”) and EPA will address the management of CCR in
mine fills in a separate regulatory action(s).” While classification of CCB as a hazardous waste would have led to more stringent restrictions and
higher costs, this regulation may still increase our customers’ operating costs and potentially reduce their ability to purchase coal.
On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards (“ELG”), revising the regulations for the Steam
Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in
wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three
decades. The combined effect of the CCR and ELG regulations has forced power generating companies to close existing ash ponds and will likely
force the closure of certain older existing coal-burning power plants that cannot comply with the new standards. These regulations add costs to the
operation of coal-burning power plants on top of other regulations like the 2014 regulations issued under Section 316(b) of the CWA that affects the
cooling water intake structures at power plants in order to reduce fish impingement and entrainment. Individually and collectively, these regulations
could, in turn, impact the market for our products. In April 2017, the EPA granted petitions for reconsideration and an administrative stay of all future
compliance deadlines for the ELG rule. In August 2017, the EPA granted petitions for reconsideration of the CCR rule. In July 2018, the EPA
published a final rule to revise requirements and extend the deadlines from the 2015 rule. In August 2018, the DC Circuit issued a decision that
imposed additional restrictions and addressed all remaining issues in the litigation on the 2015 CCR rule. This court decision could make it more
difficult for the EPA to reform the 2015 rule.
Endangered Species Act
The federal 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 mining-related
impacts. If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered, we could be subject
to additional regulatory and permitting requirements.
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.
15
Suppliers
The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products,
lubricants, electricity, fuel, and tires. Although we have many long, well-established relationships with our key suppliers, we do not believe that we
are dependent on any of our individual suppliers other than for purchases of electricity. The supplier base providing mining materials has been
relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principle supplier; however,
supplier competition continues to develop.
Illinois Basin (ILB)
The coal industry underwent a significant transformation in the early 1990s, as greater environmental accountability was established in the electric
utility industry. Through the U.S. Clean Air Act, acceptable baseline levels were established for the release of sulfur dioxide in power plant
emissions. In order to comply with the new law, most utilities switched fuel consumption to low-sulfur coal, thereby stripping the ILB of over 50
million tons of annual coal demand. This strategy continued until mid-2000 when a shortage of low-sulfur coal drove up prices. This price increase
combined with the assurance from the U.S. government that the utility industry would be able to recoup their costs to install scrubbers caused
utilities to begin investing in scrubbers on a large scale. With scrubbers, the ILB has re-opened as a significant fuel source for utilities and has
enabled them to burn lower cost high sulfur coal.
The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana and western Kentucky. The ILB is centrally
located between four of the largest regions that consume coal as fuel for electricity generation (East North Central, West South Central, West North
Central and East South Central). The region also has access to sufficient rail and water transportation routes that service coal-fired power plants in
these regions as well as other significant coal consuming regions of the South Atlantic and Middle Atlantic.
U. S. Coal Industry
The major coal production basins in the U.S. include Central Appalachia (CAPP), Northern Appalachia (NAPP), Illinois Basin (ILB), Powder River
Basin (PRB) and the Western Bituminous region (WB). CAPP includes eastern Kentucky, Tennessee, Virginia and southern West Virginia. NAPP
includes Maryland, Ohio, Pennsylvania and northern West Virginia. The ILB includes Illinois, Indiana and western Kentucky. The PRB is located in
northeastern Wyoming and southeastern Montana. The WB includes western Colorado, eastern Utah and southern Wyoming. Hallador, through its
wholly-owned subsidiary Sunrise Coal, LLC, mines coal exclusively in the ILB.
Coal type varies by basin. Heat value and sulfur content are important quality characteristics and determine the end use for each coal type.
Coal in the U.S. is mined through surface and underground mining methods. The primary underground mining techniques are longwall mining and
continuous (room-and-pillar) mining. The geological conditions dictate which technique to use. Our mines utilize the continuous mining technique. In
continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of
air. Continuous mining equipment cuts the coal from the mining face. Generally, openings are driven 20’ wide, and the pillars are rectangular in
shape measuring 40’x 40’. As mining advances, a grid-like pattern of entries and pillars is formed. Roof bolts are used to secure the roof of the
mine. Battery cars move the coal to the conveyor belt for transport to the surface. The pillars can constitute up to 50% of the total coal in a seam.
The United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. We compete against large
producers such as Peabody Energy Corporation (NYSE: BTU), Alliance Resource Partners (Nasdaq: ARLP), and other private producers.
Employees
We have 848 full-time employees and temporary miners, of which 842 are Sunrise Coal employees and temporary miners.
16
Other
We have no significant patents, trademarks, licenses, franchises or concessions.
Our Denver office is located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504 and Sunrise Coal's corporate office
is located at 1183 East Canvasback Drive, Terre Haute, Indiana 47802, phone 812.299.2800. Terre Haute is approximately 70 miles west of
Indianapolis. Our website is www.halladorenergy.com.
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. 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.
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, including supply side reforms promulgated in China and continued expected
growth in demand for seaborne coal in India; 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.
17
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. Recently, the Trump
Administration 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 announced 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, 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, annual production for U.S. coal has fallen from 1.1
billion tons to 691 million tons.
The domestic electric utility industry accounts for ~93% of domestic coal consumption. The amount of coal consumed by the domestic electric utility
industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of
competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled generation has the
potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators.
Future environmental regulation of GHG emissions also could accelerate a decline in coal demand. In addition, state and federal 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.
18
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 plants, and various new and proposed laws and regulations
may require further emission reductions and associated emission control expenditures. These laws and regulations may affect demand and prices
for coal. There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants,
particularly coal-fired power plants. Further, far-reaching federal regulations promulgated by the EPA in the last 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 of GHG emissions could result in increased operating costs and reduced demand for coal as a fuel source, which
could reduce demand for our products, decrease our 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. On December 15, 2009, the
EPA published the Endangerment Finding asserting that emissions of carbon dioxide and other GHGs present an endangerment to public health
and the environment, and the EPA has begun to regulate GHG emissions pursuant to the CAA. The EPA previously finalized an NSPS to regulate
GHG emissions from new power plants; however, the EPA published notice in the federal register in April 2017 that the agency has initiated a
review of the NSPS for new and modified fossil fuel-fired power plants and that, following the review, the EPA will initiate reconsideration
proceedings to suspend, revise or rescind this NSPS. The finalized standard requires CCS, a technology that is not yet commercially feasible
without government subsidies and that has not been demonstrated in the marketplace. This requirement, to the extent implemented as originally
finalized, effectively prevents construction of new coal-fired power plants. In December 2018, the EPA re-proposed the NSPS with a standard
reflecting the performance of currently demonstrated supercritical technologies with an emission limit of 1,900 lbs. CO2/MWh for large units (heat
input greater than 2,000 MMBtu/hour) and subcritical technologies with an emission limit of 2,000 lbs. CO2/MWh for small units. In August 2015, the
EPA issued its final CPP rules that establish carbon pollution standards for existing power plants, called CO 2 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 Circuit Court even issued a
decision. By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme
Court through any certiorari petition that may be granted. The Supreme Court's stay applies only to the EPA's regulations for CO2 emissions from
existing power plants and will not affect the EPA's standards for new power plants. It is not yet clear how either the Circuit Court or the Supreme
Court will rule on the legality of the CPP. Additionally, in October 2017 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. In connection with this proposed repeal, the EPA issued an ANPRM in
December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. In August 2018, the EPA
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. If the effort to replace the NSPS and CPP is unsuccessful and the rules were upheld at
the conclusion of this appellate process and were implemented in their current form, demand for coal would likely be further decreased, potentially
significantly, and our business would be adversely impacted. Please read “Item 1. Business—Regulation and Laws— Air Emissions ” and “—
Carbon Dioxide Emissions .”
19
Numerous political and regulatory authorities and governmental bodies, as well as environmental activist groups, are devoting
substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and
internationally, thereby further reducing the demand and pricing for coal and potentially materially and adversely impacting our future
financial results, liquidity and growth prospects.
Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased
regulation of coal combustion in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the
investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and
scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate
changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events.
Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered
concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is
being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants.
Federal, state and local governments may pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which
may decrease demand for our coal products. The CPP is one of a number of developments aimed at limiting GHG emissions which could limit the
market for some of our products by encouraging electric generation from sources that do not generate the same amount of GHG emissions.
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries, could also
result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures. For example, the
agreement resulting from the 2015 United Nations Framework Convention on Climate Change contains voluntary commitments by numerous
countries to reduce their GHG emissions and could result in additional firm commitments by various nations with respect to future GHG emissions.
These commitments could further disfavor coal-fired generation, particularly in the medium to long-term.
Internationally, a growing number of countries are passing new laws and regulations that could have an adverse impact on demand for coal. For
example, China's latest five-year plan calls for reducing the share of coal in terms of the country's total energy consumption to 58 percent by 2020
from 64 percent in 2015. The plan also calls for China to increase the share of electricity it generates from nuclear and renewable energy sources to
20 percent. Separately, in Europe, multiple countries have announced their intent to phase out existing coal-fired power plants between 2025 and
2030. In addition, in December 2018, the European Union announced that it would be phasing out subsidies for coal plants unless facilities meet a
performance standard of 550 grammes of CO2 per kilowatt hour. All of these developments have the potential to adversely impact demand for coal
in international markets.
There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public
pension funds, universities, and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to
companies engaged in the extraction of fossil fuel reserves. In California, for example, legislation requires California’s state pension funds to divest
investments in companies that generate 50% or more of their revenue from coal mining. Other activist campaigns have urged banks to cease
financing coal-driven businesses. As a result, several major banks have enacted such policies. The impact of such efforts may adversely affect the
demand for and price of securities issued by us, and impact our access to the capital and financial markets.
In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a
source of electricity generation. Collectively, these actions and campaigns could adversely impact our future financial results, liquidity and growth
prospects.
20
Government regulations have resulted and could continue to result in significant retirements of coal-fired electric generating units.
Retirements of coal-fired electric generating units decrease the overall capacity to burn coal and negatively impact coal demand.
Since 2010, utilities have formally announced the retirement or conversion of over 600 coal-fired electric generating units through 2030. These
announced retirements and conversions amount to nearly 120,000 megawatts (“MW”) or approximately 40% of the 2010 total coal electric
generating capacity. As of 2018, it is estimated that a little over half of these announced retirements have been completed. Most of these
retirements and conversions have been attributed to EPA regulations, although other factors such as an aging coal fleet and low natural gas prices
have also played a role. The reduction in coal electric capacity negatively impacts overall coal demand. Additional regulations and other factors
could lead to additional retirements and conversions and, thereby, additional reductions in the demand for coal.
We or our customers could be subject to tort claims based on the alleged effects of climate change .
In 2004, eight states and New York City sued five electric utility companies in Connecticut v. American Electric Power Co. Invoking the federal and
state common law of public nuisance; plaintiffs sought an injunction requiring defendants to abate their contribution to the nuisance of climate
change by capping carbon dioxide emissions and then reducing them. In June 2011, the U.S. Supreme Court issued a unanimous decision holding
that the plaintiffs’ federal common law claims were displaced by federal legislation and regulations. The U.S. Supreme Court did not address the
plaintiffs’ state law tort claims and remanded the issue of preemption for the district court to consider. While the U.S. Supreme Court held that
federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, tort-type liabilities remain a
possibility and a source of concern. Proliferation of successful climate change litigation could adversely impact demand for coal and ultimately have
a material adverse effect on our business, financial condition and results of operations.
The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not
extend existing or enter into new long-term contracts for coal.
In 2018, approximately 84% of our sales were under contracts having a term greater than one year, which we refer to as long-term contracts. Long-
term sales contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts.
From time to time industry conditions may make it more difficult for us to enter into long-term contracts with our electric utility customers, and if
supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended
period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire,
which could subject a portion of our revenue stream to the increased volatility of the spot market.
Some of our long-term coal sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the
termination of the contract or the suspension of purchases by customers.
Some of our long-term contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener
provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree
on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins.
Accordingly, long-term contracts may provide only limited protection during adverse market conditions. In some circumstances, failure of the parties
to agree on a price under a reopener provision can also lead to early termination of a contract.
Several of our long-term contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the
occurrence or continuation of certain events that are beyond the customer’s reasonable control. Such events may include labor disputes,
mechanical malfunctions and changes in government regulations, including changes in environmental regulations rendering use of our coal
inconsistent with the customer’s environmental compliance strategies. Additionally, most of our long-term contracts contain provisions requiring us
to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications can result in economic penalties, rejection
or suspension of shipments or termination of the contracts. In the event of early termination of any of our long-term contracts, if we are unable to
enter into new contracts on similar terms, our business, financial condition and results of operations could be adversely affected.
21
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 2018, we derived 82% of our revenue from four customers (10 power plants), with each of the four customers representing at least 10% of
our coal sales. With the addition of 8 new power plants that we began shipping to in 2018, we expect to reduce the concentration from customers
representing at least 10% of our coal sales to 70% in 2019. 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:
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;
· 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 customers;
·
·
·
·
·
·
·
·
·
accidental mine water discharges and other geological conditions;
seismic activities, ground failures, rock bursts or structural cave-ins or slides;
fires;
employee injuries or fatalities;
labor-related interruptions;
increased reclamation costs;
inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;
fluctuations in transportation costs and the availability or reliability of transportation; and
unexpected operational interruptions due to other factors.
22
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.
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.”
State and federal laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations.
Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards. Implementing
and complying with these laws and regulations has increased and will continue to increase our operational expense and to have an adverse effect
on our results of operation and financial position. For more information, please read “Item 1. Business—Regulation and Laws— Mine Health and
Safety Laws .”
We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash flow and
profitability.
Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various
environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. Regulatory
authorities exercise considerable discretion in the timing and scope of permit issuance. The public has the right to comment on permit applications
and otherwise participate in the permitting process, including through court intervention. Accordingly, permits required to conduct our operations
may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability
to economically conduct our mining operations. Limitations on our ability to conduct our mining operations due to the inability to obtain or renew
necessary permits or similar approvals could reduce our production, cash flow, and profitability. Please read “Item 1. Business—Regulations and
Laws— Mining Permits and Approvals .”
The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA. Various
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 .”
23
In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting
process, or even an inability to obtain permits, permit modifications or permit renewals necessary for our operations.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our
production or by impairing our ability to supply coal to our customers.
Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical
factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our
coal production less competitive than coal produced from other sources. Disruption of transportation services due to weather-related problems,
flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal
to our customers. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting
in decreased revenues. If there are disruptions of the transportation services provided by our primary rail carriers that transport our coal and we are
unable to find alternative transportation providers to ship our coal, our business could be adversely affected.
Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For
instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the
terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more
expensive on a per-mile basis than coal shipments originating in the western U.S. Historically, high coal transportation rates from the western coal
producing areas into certain eastern markets limited the use of western coal in those markets. Lower rail rates from the western coal producing
areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers. In the event of
further reductions in transportation costs from western coal producing areas, the increased competition with certain eastern coal markets could have
a material adverse effect on our business, financial condition and results of operations.
It is possible that states in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal
trucks on public roads. Such legislation and enforcement efforts could result in shipment delays and increased costs. An increase in transportation
costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.
We may not be able to successfully grow through future acquisitions.
We have expanded our operations by adding and developing mines and coal reserves in existing, adjacent and neighboring properties. We
continually seek to expand our operations and coal reserves. Our future growth could be limited if we are unable to continue to make acquisitions,
or if we are unable to successfully integrate the companies, businesses or properties we acquire. We may not be successful in consummating any
acquisitions and the consequences of undertaking these acquisitions are unknown. Moreover, any acquisition could be dilutive to earnings. Our
ability to make acquisitions in the future could require significant amounts of financing that may not be available to us under acceptable terms and
may be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the
lack of suitable acquisition candidates.
Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.
If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline, and we could
experience a material adverse effect on our business, financial condition, or results of operations. Expansion and acquisition transactions involve
various inherent risks, including:
·
uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks,
contingent and other liabilities (including environmental or mine safety liabilities) of, expansion and acquisition opportunities;
24
·
·
·
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.
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;
25
·
·
·
·
historical production from the area compared with production from other producing areas;
the assumed effects of regulation and taxes by governmental agencies;
future improvements in mining technology; and
assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and
reclamation costs.
For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based
on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same
engineers at different times, may vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely vary from
estimates, and these variations may be material. Any inaccuracy in the estimates of our reserves could result in higher than expected costs and
decreased profitability.
Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the
U.S., which could affect the mining operations and cost structures of these areas.
The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to
mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs
comparable to those characteristic of the depleting mines. In addition, permitting, licensing and other environmental and regulatory requirements
associated with certain of our mining operations are more costly and time-consuming to satisfy. These factors could materially adversely affect the
mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines.
Unexpected increases in raw material costs could significantly impair our operating profitability.
Our coal mining operations are affected by commodity prices. We use significant amounts of steel, petroleum products, and other raw materials in
various pieces of mining equipment, supplies and materials, including the roof bolts required by the room-and-pillar method of mining. Steel prices
and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change
unexpectedly. There may be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in
the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant fluctuations in our
profitability.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and,
therefore, our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or
reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional
collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to
have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other guarantees or
security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors,
including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to
renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing
arrangements.
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.
26
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 or results of operations.
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 3 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 3.75 to 1, which also decreases in future periods further reducing the maximum leverage permitted.
On December 31, 2018, our debt service coverage ratio was 2.12, and our leverage ratio was 2.55. 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, 2018, our debt was $188 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.
Risk Related to Possible Future Impairment Charge
Bulldog Reserves
In October 2017, we entered into an agreement to sell land associated with the Bulldog reserves for $4.9 million. As part of the transaction, we will
hold the rights to repurchase the property for 8 years. Because of the likelihood of exercising the repurchase option, we are accounting for the sale
as a financing transaction. The Bulldog assets had an aggregate net carrying value of $15 million at December 31, 2018. Also in October 2017, the
Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. In October 2018,
we paid the required fee and bond and the permit is expected to be issued in the near future. We have determined that no impairment is necessary.
If estimates inherent in the assessment change, it may result in future impairment of the assets.
27
ITEM 1B. UNRESOLVED STAFF COMMENTS . None.
ITEM 2. PROPERTIES.
See Item 7 MDA 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 seventeen years’ experience estimating coal reserves.
Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories.
Under these standards, coal within 1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable
category. Only seams greater than 4’ in thickness are included in our underground reserves. All reserves are stated as a final salable product.
Prior to acquiring coal mineral leases, title abstractors conduct a preliminary title search on the property. This information provides a strong
indication of the coal owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us the rights to explore
and mine the property. Prior to mining, attorneys review the chain of mineral ownership to verify the lessor is the mineral owner. Prior to purchasing
coal properties, we follow a similar process
ITEM 3. LEGAL PROCEEDINGS. None
ITEM 4. MINE SAFETY DISCLOSURES:
Safety is a core value for us. As such we have dedicated a great deal of time, energy, and resources to creating a culture of safety. Thus, we are
very proud of the mine rescue team at Sunrise Coal whose current list of achievements include 1 st place at the 2018 Indiana Mine Rescue
Association Contest which was held in June 2018 and top 3 finishes at several other contests over the last year.
See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.
28
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 35% is held by our officers, directors and their affiliates.
At March 8, 2019, we had 197 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 5 to our consolidated financial statements.
29
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 mining company in the State of Colorado which has not yet commenced full-scale operations, and we are consolidating the activity of
Hourglass in these statements.
We operate three underground coal mines and one surface coal mine in southwestern Indiana with the following capacities:
Mine
Oaktown 1*
Oaktown 2**
Carlisle
Ace in the Hole
Total
Location
Oaktown, IN
Oaktown, IN
Carlisle, IN
Clay City, IN
Surface/
Underground
Underground
Underground
Underground
Surface
Annual
Tons Capacity
(in millions)
4.0
4.0
2.2
0.3
10.5
Transportation
CSX, Truck Direct & Truck to NS
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.
** Oaktown 2 & Carlisle’s underground reserves are contiguous.
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 2018, Sunrise sold coal to 17 power plants in 8 different states. This is a dramatic increase in customers versus 2017 where Sunrise served 9
power plants in 3 states. The total estimated coal consumption of our 2018 customers is 165% greater than our 2017 customer base.
Year
2018
2017
# of Plants
Served
17
9
# of States
Served
8
3
Estimated Tonnage
Demand of
Customers Served
(millions)
42.9
16.2
Tons Sold
(millions)
7.4
6.6
% of Customer
Supply
17.2%
40.7%
This increase in customers is the result of three fundamental changes in our market that have increased demand and reduced supply.
1. A large Indiana industrial customer has decided to close their coal mines and purchase coal from Sunrise under long-term contracts.
2. The addition of our new Princeton Loop has allowed us to access new markets served by the Norfolk and Southern Railroad (NS).
3. A greater percentage of Illinois Basin (ILB) coal is going to export, thus tightening supply. This has led to new customers contracting
with Sunrise for the first time. Our eight new customers currently represent an average of ~3% of sales each but have the ability to
become much larger customers in the future.
30
§
There has been much debate as to the sustainability of ILB exports. IHS Markit reports that for every 1 megawatt of coal fired
power generation that is being closed in the world (mostly in the U.S. and Europe), 3 to 4 megawatts of coal fired power
generation is being built (mostly in Asia). At this time, we do not see enough new coal supply coming online and feel ILB coal
exports will be needed to meet this new demand throughout the world.
During 2018, we derived 82% of our revenue from four customers (10 power plants), with each of the four customers representing at least 10% of
our coal sales. With the addition of the eight new power plants that we began shipping to in 2018, we expect to reduce the concentration from
customers representing at least 10% of our coal sales to 70% in 2019.
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 2018 sales, 73% were shipped to locations in the State of Indiana. We anticipate our coal shipments utilizing the following modes of
transportation in 2019:
CSX Railroad
CSX/INRD
Truck
NS Railroad
Total
44%
23%
23%
10%
100%
2018 brought the return of long-term contracts. We were successful in signing multiple contracts ranging from 2-4 years in length. When looking at
2019 through 2022, we have 25.2 million tons sold. Thus, we have ~78% of our sales contracted over the next four years at an ~8.0 million-ton
annualized pace. The table below reflects our projected tons.
Year
2019
2020
2021
2022
Total
Targeted tons
(millions)
Contracted tons*
(millions)
% Committed
Estimated price
per ton
8.2
8.0
8.0
8.0
32.2
7.9
6.7
5.3
5.3
25.2
96% $
84% $
66%
66%
78%
40.00
41.00
*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. All customer plants are expected to be long-lived, with only
one plant potentially being retired in 2023.
Vectren Corporation filed a petition on February 20, 2018 with the Indiana Utility Regulatory Commission (IURC) proposing to retire Culley Unit 2
and Brown Units 1 and 2 and replace the coal fired units with a new Combined Cycle Gas Turbine Generation Facility. The retirement of these units,
if the petition is approved, would represent a reduction of ~1.1MM tons of Estimated Customer Demand starting in late 2023. The Sierra Club,
Citizens Action Coalition, Indiana Office of Utility Consumer Counselor, Indiana Coal Council, Alliance Resource Partners and Sunrise Coal filed a
petition with IURC requesting that Vectren’s request be denied.
31
Asset Impairment Review
See Note 2 to our consolidated financial statements.
Reserve Table - Controlled Tons (in millions):
Tons
Sold
Annual
Capacity
Proven
Probable
Total
Sulphur #
BTU
2018 Year-End Reserves
Oaktown 1 (assigned)
Oaktown 2 (assigned)
Carlisle (assigned)
Ace in the Hole (assigned)
Ace in the Hole #2 (unassigned)
Bulldog (unassigned)
Total
Assigned
Unassigned
3.9
2.7
0.4
0.4
-
-
7.4
4.0
4.0
2.2
0.3
-
-
10.5
43.8
34.5
21.0
0.5
1.0
16.2
117.0
10.6
8.9
1.5
-
-
14.4
35.4
6.0
5.6
5.6
1.9
3.5
4.5
11,400
11,600
11,500
11,200
11,100
11,300
54.4
43.4
22.5
0.5
1.0
30.6
152.4
120.8
31.6
152.4
Our assigned underground coal reserves are high sulfur (5.0# – 6.5#) 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#) 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.
Oaktown 1 Mine (underground) – Assigned
We have 54.4 million controlled, salable tons of the Indiana #V coal seam. We began 2018 with 51.1 million tons controlled. The increase is a result
of new drilling and new leases, after accounting for current year production. 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 43.4 million controlled, saleable tons of the Indiana #V coal seam. We began 2018 with 42.9 million controlled tons. The increase is a
result of new drilling and new leases, after accounting for current year production. 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.
32
The two Oaktown mines are separated by a sandstone channel. The coal seam thickness ranges from 4 feet to over 9 feet. The Oaktown mines
share the same wash plant which is rated at 1,800 tons per hour. The two mines are connected to a rail loadout that can store two 120 car trains at
once and is serviced by the CSX Railroad and Indiana Railroad. Coal is also transported via truck to customers.
Carlisle Mine (underground) – Assigned
We have 22.5 million controlled, saleable tons at our Carlisle Mine. We began 2018 with 27.3 million controlled tons. Besides production, the
remainder of the decrease relates to tons that were deemed unrecoverable due to geologic and economic conditions based on new drilling. The
mine is located near the town of Carlisle, Indiana in Sullivan County and became operational in January 2007. The coal is accessed with a slope to a
depth of 340'. The coal is mined in the Indiana #V coal seam which is highly volatile bituminous coal and has been extensively mined by
underground and surface methods in the general area. The coal thickness in the project area is 4' to 7'. The Carlisle Mine is completely developed,
but was idle for the entirety of 2017. In July 2018, we restarted production at the Carlisle Mine.
Ace in the Hole Mine (Ace) (surface) – Assigned
We have .5 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# SO 2 ), 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 and Carlisle to blend
with high sulfur coal. Many utilities in the southeastern U.S. have scrubbers with lower sulfur limits (4.5# SO 2 ) which cannot accept the higher sulfur
contents of the ILB (4.5# - 6.5# SO 2 ). 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.
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. We began 2018 with 35.8 million controlled tons. The decrease is due to the expiration of a lease that may be renewed in
the future. A considerable amount of our leased acres has yet to receive any exploratory drilling.
In October 2017, we entered into an agreement to sell land associated with the Bulldog reserves for $4.9 million. As part of the transaction, we will
hold the rights to repurchase the property for eight years. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us
that our mine application, along with modifications, was acceptable. In October 2018, we paid the required fee and bond and the permit is expected
to be issued in the near future.
33
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 2020.
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
34
Mine and Wash Plant Recovery and Capacity
Oaktown 1
Oaktown 2
Carlisle
Bulldog
* 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
Mine recovery
49%
48%
53%
45%
Wash plant
recovery*
81%
81%
81%
77%
Wash Plant
Capacity
(Clean Tons)
8.0 million**
3.4 million
As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $51.6 million and $65.8 million for the years ended
December 31, 2018 and 2017 respectively. We have increased our coal inventory by $6.4 million in anticipation of larger sales in 2019, to build a
base of inventory at the Princeton Loop, and as a result of restarting production at the Carlisle mine. We have also increased our prepaid expense
by $5.8 million with one of our vendors. Our capex budget for 2019 is $31 million, of which $22 million is for maintenance capex. We expect cash
from operations for 2019 to fund our maintenance capital expenditures, debt service, and our dividend.
See Note 3 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
$14.6 million, which are presented as asset retirement obligations (ARO) in our accompanying balance sheets. In the event we are not able to
perform reclamation, we have surety bonds totaling $26 million to cover ARO.
Capital Expenditures (capex)
For the year ended December 31, 2018, our capex was $35.1 million allocated as follows (in millions):
Oaktown – investment
Oaktown – maintenance capex
Carlisle - maintenance capex
Princeton Rail Loop
Hourglass - investment
Other
Capex per the Consolidated Statements of Cash Flows
$
$
3.6
19.5
2.3
6.5
2.0
1.2
35.1
35
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, 2018. 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.
Revenue:
Coal sales
Other
Total revenue
Costs and expenses:
Operating costs and expenses
DD&A
ARO accretion
Coal exploration costs
SG&A
Interest
Total cost and expenses
Dec-31
2018
Sep-30
2018
Jun-30
2018
Mar-31
2018
Dec-31
2017
Sep-30
2017
Jun-30
2017
Mar-31
2017
$
89,019 $
709
89,728
79,055 $
667
79,722
56,922 $
321
57,243
66,787 $
77
66,864
68,922 $
378
69,300
73,896 $
572
74,468
62,829 $
1,483
64,312
69,619
11,403
301
374
2,958
6,004
90,659
60,230
10,815
293
279
2,519
3,261
77,397
38,874
11,120
291
315
2,474
4,315
57,389
46,640
10,829
282
217
3,890
2,708
64,566
52,025
9,962
221
288
2,883
2,751
68,130
54,354
9,729
219
152
2,859
3,229
70,542
44,079
9,101
214
275
6,578
3,342
63,589
62,555
998
63,553
39,692
9,703
207
139
2,658
3,091
55,490
Income (loss) before income taxes
(931)
2,325
(146)
2,298
1,170
3,926
723
8,063
Less income taxes:
Current
Deferred
Total income taxes
Net income (loss)
Net income (loss) per share:
Basic and diluted
$
$
Weighted average shares outstanding:
Basic and diluted
(1,362)
(2,167)
(3,529)
(204)
(385)
(589)
(19)
(104)
(123)
(203)
369
166
(1,590)
(18,597)
(20,187)
(2,532)
2,542
10
1,357
(1,023)
334
17
632
649
2,598 $
2,914 $
(23) $
2,132 $
21,357 $
3,916 $
389 $
7,414
0.09 $
0.09 $
(0.00) $
0.07 $
0.69 $
0.13 $
0.01 $
0.25
30,180
30,177
29,980
29,955
29,830
29,774
29,503
29,413
36
Quarterly coal sales and cost data follow (in 000’s, except for per ton data and wash plant recovery percentage):
All Mines
1st 2018
2nd 2018
3rd 2018
4th 2018
T4Qs
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
2018 v. 2017
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,975
1,707
66,787
39.13
$
$
69%
$
$
$
$
$
$
$
46,640
27.32
20,147
11.80
10,428
5,772
3.38
1,983
1,477
56,922
38.54
$
$
73%
$
$
$
$
$
$
$
38,809
26.28
18,113
12.26
7,784
5,058
3.42
1,713
1,962
79,055
40.29
$
$
72%
$
$
$
$
$
$
$
60,132
30.65
18,923
9.64
5,856
4,639
2.36
1,938
2,219
89,019
40.12
$
$
68%
$
$
$
$
$
$
$
69,364
31.26
19,655
8.86
8,996
7,186
3.24
7,609
7,365
291,783
39.62
70%
214,945
29.18
76,838
10.43
33,064
22,655
3.08
1st 2017
2nd 2017
3rd 2017
4th 2017
T4Qs
1,917
1,555
62,555
40.23
$
$
71%
$
$
$
$
$
$
$
39,692
25.53
22,863
14.70
5,144
2,887
1.86
1,647
1,548
62,829
40.59
$
$
69%
$
$
$
$
$
$
$
44,079
28.47
18,750
12.11
6,711
3,032
1.96
1,487
1,786
73,896
41.38
$
$
70%
$
$
$
$
$
$
$
54,354
30.43
19,542
10.94
9,473
2,961
1.66
1,561
1,685
68,922
40.90
$
$
68%
$
$
$
$
$
$
$
52,025
30.88
16,897
10.03
7,294
2,520
1.50
6,612
6,574
268,202
40.80
69%
190,150
28.92
78,052
11.87
28,622
11,400
1.73
For 2018, we sold 7,365,000 tons at an average price of $39.62/ton. For 2017, we sold 6,574,000 tons an average price of $40.80/ton. The
decrease in average price per ton was expected and 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 $29.18/ton and $28.92/ton for the year ended December 31, 2018 and 2017, respectively. With the
restart of production at the Carlisle mine in July 2018, our operating costs have increased, but a second Carlisle unit was fully staffed in late
December 2018 and costs have been dropping. Therefore, we expect operating costs for our coal mines to remain $28-$30/ton in 2019.
Operating costs associated for the idled Prosperity mine were $1.3 million and $1.1 million for the years ending December 31, 2018 and 2017,
respectively. We expect operating costs to be $1.3 million in 2019.
DD&A increased approximately $5.7 million during 2018. A portion of our assets are depreciated based on raw production which has increased in
2018, thus as production increases so do our DD&A. Additionally, we began depreciating a new elevator at Oaktown 1 and assets relating to the
Carlisle mine that had been idled since 2015.
SG&A expenses decreased approximately $3.1 million in 2018. In May 2017, a stock bonus totaling $3.8 million was awarded to company
executives. No such award occurred in 2018. In March 2018, accelerated vesting of restricted stock units totaling $1.5 million occurred due to the
passing of our former Chairman, Victor Stabio. We expect SG&A to be $10 million in 2019.
37
Interest expense increased approximately $3.9 million in 2018. The change in estimated fair value of our interest rate swap agreement during 2018
resulted in additional expense of $2.2 million. The remaining increase in interest expense is a result of amending our credit agreement in May 2018,
which increased our effective fixed rate from 5% to 6%.
Our full-time Sunrise Coal employees and temporary miners totaled 842 at December 31, 2018, compared to 736 at December 31, 2017.
Current Projects
Hourglass Sands
In February 2018, we invested $4 million in Hourglass Sands, LLC, a frac sand mining company in the State of Colorado. In April 2018, we closed
on the purchase of a commercial sand dryer and contracted with a third party to process our sand in Colorado Springs, Colorado.
We began producing raw sand in Colorado in June 2018. We shipped test shipments of sand in September 2018. We are excited about its growth
potential in future years. Currently, we believe we control the only permitted frac sand mine in the State of Colorado.
Princeton Rail Loop
The Princeton loop, which provides access to new markets and customers, was completed and our first coal shipments were delivered to customers
in May 2018. The facility is a truck to rail transload facility located six miles east of Princeton, Indiana and is capable of loading 135 car unit trains in
less than four hours. The facility serves utility coal plants served by Norfolk Southern Railway Company. In 2018, we shipped 828,000 tons of coal
from this facility.
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, 2018, 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
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (Tax Act).
The Tax Act reduced the corporate tax rate to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 requires the effect of a change in
tax laws or rates to be recognized as of the date of enactment, we were required to adjust deferred tax assets and liabilities as of December 22,
2017. Accordingly, we recorded a deferred income tax benefit of $16.4 million for the year ended December 31, 2017.
Our effective tax rate (ETR) for 2018 was (116)% compared to (138)% for 2017. The negative ETR in 2018 is due mostly to the statutory depletion
deduction which is in excess of our book income. The negative ETR in 2017 is due primarily to the effects of the Tax Act adjustment to our deferred
taxes and prior year tax return reconciliation which were all recorded discretely for the year ended December 31, 2017. The tax rate for the years
ended December 31, 2018 and 2017 are not predictive of future tax rates due to the deferred income tax benefit of the Tax Act. The tax rate for
2017 would have been 9% without the effects of the deferred income tax benefit of the Tax Act and the prior year tax return reconciliation.
Historically, our actual effective tax rates have been lower than the statutory effective rate primarily due to the benefit received from statutory
depletion allowances. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income taxes.
38
Critical Accounting Estimates
We believe that the estimates of our coal reserves, our business acquisitions, 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.
We account for business combinations using the purchase method of accounting. The purchase method requires us to determine the fair value of all
acquired assets, including identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying
identifiable net assets, based on their respective estimated fair values. Determining whether an acquisition is considered to be a business or an
asset acquisition, and if deemed to meet the definition of a business, the fair value of assets acquired and liabilities assumed requires
management's judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions,
including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.
The fair value of our interest rate swaps is determined using a discounted future cash flow model based on the key assumption of anticipated future
interest rates.
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.
39
ITEM 8. FINANCIAL STATEMENTS.
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Comprehensive Income
Consolidated Statements of Cash Flows
Consolidated Statement of Stockholders' Equity
Notes to Consolidated Financial Statements
41
44
45
46
47
48
40
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of
Hallador Energy Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheet as of December 31, 2018 and the related consolidated statement of comprehensive
income, stockholders’ equity, and cash flows for the year ended December 31, 2018 and the related notes (collectively referred to as the “financial
statements”) of Hallador Energy Company (the “Company”). We also have audited the Company's internal control over financial reporting as of
December 31, 2018, 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, 2018, and the results of its operations, and its cash flows of the Company for the year ended December 31, 2018, 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, 2018, 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.
41
To the Shareholders and Board of Directors of
Hallador Energy Company
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.
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.
/s/Plante & Moran, PLLC
We have served as the Company’s auditor since 2003.
Denver, Colorado
March 11, 2019
42
REPORT OF INDEPENDENT PUBLIC ACCOUNTING FIRM
To the Shareholders and Board of Directors of
Hallador Energy Company
1660 Lincoln Street, Suite 2700
Denver, CO 80234
OPINIONS ON THE CONSOLIDATED FINANCIAL STATEMENTS
We have audited the accompanying consolidated balance sheet of Hallador Energy Company (the “Company”) as of December 31, 2017, and the
related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows, for each year in the two year period ended
December 31, 2017, and the related notes and schedules (collectively referred to as the “financial statements”).
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of
December 31, 2017, and the results of its operations and its cash flows for each year in the two year period ended December 31, 2017, in
conformity with accounting principles generally accepted in the United States of America.
BASIS FOR OPINIONS
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.
/s/EKS&H LLLP
March 12, 2018
Denver, Colorado
43
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 10)
Certificates of deposit
Marketable securities
Accounts receivable
Prepaid income taxes
Inventory
Parts and supplies, net of allowance of $1,595 and $795 in 2018 and 2017, 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 Savoy (Note 13)
Investment in Sunrise Energy (Note 13)
Other assets (Note 7)
Total assets
LIABILITIES, REDEEMABLE NONCONTROLLING INTERESTS, AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net (Note 3)
Accounts payable and accrued liabilities (Note 8)
Total current liabilities
Long-term liabilities:
Bank debt, net (Note 3)
Deferred income taxes
Asset retirement obligations (ARO)
Other
Total long-term liabilities
Total liabilities
Redeemable noncontrolling interests (Note 15)
Stockholders' equity:
$
$
$
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
Common stock, $.01 par value, 100,000 shares authorized; 30,245 and 29,955 shares outstanding,
respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive income
Total stockholders’ equity
Total liabilities, redeemable noncontrolling interests, and stockholders’ equity
$
See accompanying notes.
2018
2017
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
12,483
3,811
1,495
1,907
16,762
2,899
12,804
10,043
5,482
67,686
129,724
360,862
136,762
627,348
(203,391)
423,957
8,037
3,853
14,660
518,193
33,171
21,115
54,286
165,773
28,728
13,506
6,577
214,584
268,870
-
-
-
302
100,742
153,830
-
254,874
515,499 $
299
97,873
150,236
915
249,323
518,193
44
Hallador Energy Company
Consolidated Statements of Comprehensive Income
For the years ended December 31,
(in thousands, expect per share data)
Revenue:
Coal sales
Other (Note 9)
Total revenue
Costs and expenses:
Operating costs and expenses
DD&A
ARO accretion
Exploration costs
SG&A
Interest (1)
Total costs and expenses
Income before income taxes
Less income tax benefit
Current
Deferred
Total income tax benefit
Net income *
Net income per share (Note 11):
Basic and diluted
Weighted average shares outstanding:
Basic and diluted
$
$
$
2018
2017
291,783 $
1,774
293,557
215,363
44,167
1,167
1,185
11,841
16,288
290,011
268,202
3,431
271,633
190,150
38,495
861
854
14,978
12,413
257,751
3,546
13,882
(1,788)
(2,287)
(4,075)
(2,748)
(16,446)
(19,194)
7,621 $
33,076
.25 $
1.08
30,074
29,661
*There is no material difference between net income and comprehensive income.
(1)
Included in interest expense is the change in the estimated fair value of our interest rate swaps. Such amounts were $2,182 and $(723) for
2018, and 2017, respectively.
See accompanying notes.
45
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
2018
2017
Operating activities:
Net income
Deferred income taxes
Equity (income) loss – Savoy and Sunrise Energy
Cash distributions - Savoy and Sunrise Energy
DD&A
Loss on sale of assets
Unrealized loss on marketable securities
Change in fair value of interest rate swaps
Amortization and write off of deferred financing costs
Amortization of purchased coal contracts
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
Investing activities:
Capital expenditures
Proceeds from sale of equipment
Proceeds from maturities of certificates of deposit
Proceeds from sale of Savoy
Cash used in investing activities
Financing activities:
Payments of bank debt
Bank borrowings
Deferred financing costs
Proceeds from Bulldog property
Proceeds from noncontrolling interests (Note 15)
Taxes paid on vesting of RSUs
Dividends
Cash used in financing activities
Increase 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 consists of the following:
Cash
Restricted Cash
Supplemental cash flow information:
Cash paid for interest
Cash (received) paid for income taxes, net
Capital expenditures included in accounts payable and prepaid expense
See accompanying notes.
$
$
$
$
$
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
(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)
(4,837)
33,076
(16,446)
(365)
175
38,495
45
-
(723)
1,829
8,922
861
7,266
-
5,533
(2,704)
48
(3,226)
(4,823)
(815)
(1,377)
65,771
(28,622)
506
5,820
-
(22,296)
(36,625)
-
-
4,940
-
(3,209)
(4,892)
(39,786)
3,689
12,605
16,294
12,483
3,811
16,294
11,663
1,562
7,615
46
Hallador Energy Company
Consolidated Statement of Stockholders’ Equity
(in thousands)
Shares
Common
Stock
Additional
Paid-in
Capital
Retained
Earnings
AOCI*
Total
Balance December 31, 2016
Stock-based compensation
Stock issued on vesting of RSUs
Taxes paid on vesting of RSUs
Dividends
Net income
Other
Balance, December 31, 2017
Impact from adoption of ASU 2018-02 and ASU
2016-01 (Note 1)
Stock-based compensation
Stock issued on vesting of RSUs
Taxes paid on vesting of RSUs
Dividends
Net income
29,413 $
-
991
(449)
-
-
-
29,955
345
(55)
294 $
-
5
-
-
-
-
299
3
93,816 $
7,266
-
(3,209)
-
-
-
97,873
3,170
(3)
(298)
Balance, December 31, 2018
30,245 $
302 $
100,742 $
*Accumulated Other Comprehensive Income (loss)
See accompanying notes.
122,052 $
-
-
-
(4,892)
33,076
-
150 236
728 $
-
-
-
-
-
187
915
915
(915)
(4,942)
7,621
153,830 $
- $
216,890
7,266
5
(3,209)
(4,892)
33,076
187
249,323
-
3,170
-
(298)
(4,942)
7,621
254,874
47
HALLADOR ENERGY COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Summary of Significant Accounting Policies
Basis of Presentation and Consolidation
The condensed 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. Hourglass is in the development stage and is engaged in the production of frac sand in the State of Colorado (see Note 15).
Segment Information
The Company’s significant operating segments include the Oaktown and Carlisle 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, 2018 and 2017, 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.
Advance 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.
48
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 $26 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
$
$
2018
2017
13,806 $
1,167
-
(327)
14,646
(60)
14,586 $
13,260
861
(112)
(203)
13,806
(300)
13,506
Cash equivalents include investments with maturities, when purchased, of three months or less.
Income Taxes
Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on pretax financial income.
Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and
financial reporting and principally relate to differences in the tax basis of assets and liabilities and their reported amounts, using enacted tax rates in
effect for the year in which differences are expected to reverse.
49
Net Income per Share
Basic net income 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 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 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.
Long-term Contracts
As of December 31, 2018, we are committed to supplying our customers up to a maximum of 30.5 million tons of coal through 2024 of which 20.7
million tons are priced.
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
were from five customers, each representing more than 10% of the December 31, 2018 balance.
For 2017, we derived 92% of our coal sales from five customers, each representing at least 10% of our coal sales. 83% of our accounts receivable
were from four of these customers, each representing more than 10% of the December 31, 2017 balance.
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 May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 is a comprehensive revenue recognition
standard that supersedes nearly all existing revenue recognition guidance under current U.S. GAAP and replaces it with a principle-based approach
for determining revenue recognition. On January 1, 2018, we adopted the new accounting standard and all of the related amendments to all
contracts using the modified retrospective method. Adoption of the new revenue standard did not result in a material cumulative effect adjustment to
the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting
standards in effect for those periods. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an
ongoing basis, however we recognized revenue of $0.5 million over the course of the year related to MSHA costs that would have been recognized
in a future period under the old standard. See “Note 14 - Revenue” to these consolidated financial statements for additional disclosures.
In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments (Topic 825): Recognition and Measurement of Financial Assets and
Financial Liabilities. ASU 2016-01 requires equity investments that are not accounted for under the equity method of accounting or that do not result
in consolidation of the investee to be measured at fair value with changes recognized in net earnings. ASU 2016-01 also eliminates the available-for-
sale classification for equity investments that recognized changes in fair value as a component of other comprehensive income. We adopted ASU
2016-01 on January 1, 2018, using the modified retrospective method, which resulted in a $1.1 million (net of tax) cumulative-effect adjustment from
accumulated other comprehensive income to retained earnings. Adoption of ASU 2016-01 did not have a material impact on our results of
operations and/or cash flows.
50
In November 2016, the FASB issued guidance regarding the presentation of restricted cash in the statement of cash flows (ASU 2016-18). This
update is effective for annual reporting periods beginning after December 15, 2017, and early adoption is permitted. We have adopted the new
standard as of January 1, 2018. Adoption of ASU 2016-18 did not have a material impact on the company’s results of operations and/or cash flows.
In January 2017, the FASB issued new guidance to assist in determining if a set of assets and activities being acquired or sold is a business (ASU
2017-01). It also provided a framework to assist entities in evaluating whether both an input and a substantive process are present, which at a
minimum, must be present to be considered a business. We have adopted the new standard as of January 1, 2018. The standard does not have an
impact on our historical recognition of asset acquisitions and business combinations. However, we expect there may be an impact on how we
account for such acquisitions in the future.
In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain
Tax Effects from Accumulated Other Comprehensive Income. ASU 2018-02 allows companies to reclassify stranded tax effects resulting from the
2017 Tax Act from accumulated other comprehensive income to retained earnings. The company elected to early adopt ASU 2018-02 on January 1,
2018, which resulted in a reclassification of $192,000 of stranded tax effects, related to our unrealized gain on marketable securities, from
accumulated other comprehensive income to retained earnings. Adoption of ASU 2018-02 did not have a material impact on our results of
operations and/or cash flows.
New Accounting Standards Issued and Not Yet 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 disclosing key
information about lease arrangements. The new guidance will classify leases as either finance or operating (similar to current standard’s “capital” or
“operating” classification), with classification affecting the pattern of income recognition in the statement of income. ASU 2016-02 is effective for
fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. The FASB
continues to issue clarifications, updates and implementation guidance to ASU 2016-02 which we continue to monitor, such as ASU 2018-01,
Leases (Topic 842) ("ASU 2018-01") and ASU 2018-11, Leases (Topic 842) ("ASU 2018-11") which provides practical expedients for transition to
Topic 842. ASU 2018-01 allows for companies that did not previously recognize land easements as leases to continue this practice for existing
leases but will still require the evaluation of new lease arrangements, including land easements. 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. We will elect to apply this option at the adoption
date.
We have completed our review of our current population of leases and continue our efforts to update the population for new leases. We have also
developed internal controls and systems for our implementation and ongoing accounting for leases. We will recognize lease liabilities and offsetting
right-of-use assets of approximately $0.5 million in our consolidated balance sheets for operating leases upon adoption on January 1, 2019.
51
Subsequent Events
In January 2019, we declared a dividend of $.04 per share to shareholders of record as of January 31, 2019. The dividend was paid on February 15,
2019.
In January 2019, we sold our overriding royalty interests in certain producing oil properties in Southern Wyoming for $2.5 million and recognized a
gain for the same amount.
(2) Asset Impairment Review
Carlisle Mine
In July 2018, we restarted production at the Carlisle Mine and began shipping coal to customers. We conducted a review of the Carlisle Mine assets
as of December 31, 2018, based on estimated future net cash flows, and determined that no impairment to the aggregate net carrying value of $107
million was necessary. If in future periods we reduce our estimate of the future net cash flows attributable to the Carlisle Mine, it may result in future
impairment of such assets and such charges could be significant.
Bulldog Reserves
In October 2017, we entered into an agreement to sell land associated with the Bulldog reserves for $4.9 million. As part of the transaction, we hold
the rights to repurchase the property for eight years at the original sale price of $4.9 million plus interest. We accounted for the sale as a financing
transaction with the liability recorded in other long-term liabilities. The Bulldog assets had an aggregate net carrying value of $15 million at
December 31, 2018. Also, in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with
modifications, was acceptable. In October 2018, we paid the required fee and bond and the permit is expected to be issued in the near future. We
have determined that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.
(3) Bank Debt
On May 21, 2018, we executed the Third Amended and Restated Credit Agreement with PNC, as administrative agent for our lenders. The $267
million credit facility is a combination of a $147 million term loan and $120 million revolver. The credit facility extends the term through May 21, 2022,
reduces the debt service requirements, changes the borrower from Sunrise Coal to Hallador, and allows for investments in Hourglass Sands. The
credit facility is collateralized primarily by Hallador’s assets. Our borrowing capacity increased by $6 million as of the effective date of the amended
agreement.
Liquidity
Our bank debt at December 31, 2018, was $188 million (term - $130 million, revolver - $58 million). Our debt is recorded at cost which approximates
fair value due to the variable interest rates in the agreement. As of December 31, 2018, we had additional borrowing capacity of $62 million and total
liquidity of $80 million.
Fees
We incurred $5.7 million in debt issuance costs at the closing of the new credit facility that were added to our bank debt. Bank fees and other costs
incurred in connection with the amended credit agreement and unamortized costs incurred in connection with the initial facility and a subsequent
amendment totaled $8.8 million. These costs were deferred and are being amortized over the term of the loan. Unamortized costs as of December
31, 2018 and 2017, were $7.4 million and $3.0 million, respectively.
52
Covenants
The credit facility includes a Maximum Leverage Ratio (consolidated funded debt / trailing twelve months adjusted EBITDA), calculated as of the end
of each fiscal quarter for the trailing twelve months, not to exceed the amounts below:
Fiscal Periods Ending
September 30, 2018 through March 31, 2019
June 30, 2019 and September 30, 2019
December 31, 2019 through September 30, 2020
December 31, 2020 through September 30, 2021
December 31, 2021 and each fiscal quarter thereafter
Ratio
3.75 to 1.00
3.50 to 1.00
3.25 to 1.00
3.00 to 1.00
2.75 to 1.00
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.
At December 31, 2018, our Leverage Ratio was 2.55, and our Debt Service Coverage Ratio was 2.12. Therefore, we were in compliance with those
two ratios.
Rate
The interest rate on the facility ranges from LIBOR plus 3.00% to LIBOR plus 4.50%, depending on our Leverage Ratio. We entered into swap
agreements to fix the LIBOR component of the interest rate to achieve an effective fixed rate of ~6% on the original term loan balance and on $53
million of the revolver. At December 31, 2018, we are paying LIBOR of 2.52% plus 4.00% for a total interest rate of 6.52%.
Bank debt, less debt issuance costs, is presented below (in thousands):
Current debt
Less debt issuance cost
Net current portion
Long-term debt
Less debt issuance cost
Net long-term portion
Future Maturities (in thousands):
2019
2020
2021
2022
Total
2018
2017
$
$
$
$
$
$
27,563 $
(2,171)
25,392 $
160,900 $
(5,245)
155,655 $
27,563
34,913
36,750
89,237
188,463
35,000
(1,829)
33,171
166,992
(1,219)
165,773
53
( 4) Income Taxes (in thousands)
On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (Tax Act).
The Tax Act made broad and complex changes to the U.S. tax code including, but not limited to, (1) bonus depreciation that will allow for full
expensing of qualified property; (2) reduction of the U.S. federal corporate tax rate; (3) elimination of the corporate alternative minimum tax; (4) a
new limitation on deductible interest expense; (5) the repeal of the domestic production activity deduction; (6) limitations on the deductibility of
certain executive compensation; and (7) limitations on net operating losses generated after December 31, 2017, to 80 percent of taxable income.
The SEC staff issued SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period
that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance
with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. We
completed the accounting for the tax effects of the Tax Act in December 2017.
The Tax Act reduced the corporate tax rate to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 required the effect of a change in
tax laws or rates to be recognized as of the date of enactment, we were required to adjust deferred tax assets and liabilities as of December 22,
2017. Accordingly, we recorded a decrease related to our net deferred tax liability of $16.4 million, with a corresponding net adjustment to deferred
income tax benefit of $16.4 million for the year ended December 31, 2017.
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:
Expected amount
Adjustment to deferred taxes from the Tax Act rate reduction
State income taxes, net of federal benefit
Percentage depletion
Stock-based compensation
Captive insurance
Adjustments to NOL carryforwards
Return to provision adjustments
Other
$
$
2018
2017
737 $
-
(654)
(3,278)
(15)
-
-
(592)
(273)
(4,075) $
4,868
(17,974)
115
(4,128)
(204)
(379)
(1,038)
(205)
(249)
(19,194)
The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following at December
31:
Long-term deferred tax assets:
Stock-based compensation
Investment in Savoy
Net operating loss
Interest limitation carryforward
Alternative minimum tax credit
Other
Total long-term deferred tax assets
Long-term deferred tax liabilities:
Coal properties
Net deferred tax liability
2018
2017
$
$
613 $
-
17,194
441
1,049
995
20,292
(46,733)
(26,441) $
251
781
13,626
-
2,705
943
18,306
(47,034)
(28,728)
54
Our effective tax rate (ETR) for 2018 was (116)% compared to (138)% for 2017. The negative ETR in 2018 is due mostly to the statutory depletion
deduction which is in excess of our book income. The negative ETR in 2017 is due primarily to the effects of the Tax Act adjustment to our deferred
taxes and prior year tax return reconciliation which were all recorded discretely for the year ended December 31, 2017. The tax rate for the years
ended December 31, 2018 and 2017 are not predictive of future tax rates due to the deferred income tax benefit of the Tax Act. The tax rate at
December 31, 2017 would have been 9% without the effects of the deferred income tax benefit of the Tax Act and the prior year tax return
reconciliation. Historically, our actual effective tax rates have been lower than the statutory effective rate primarily due to the benefit received from
statutory depletion allowances. The deduction for statutory depletion does not necessarily change proportionately to changes in income before
income taxes.
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.
(5) Stock Compensation Plans
Restricted Stock Units (RSUs)
On May 16, 2017, our Compensation Committee authorized the issuance and immediate vesting of 495,000 RSUs to our Chairman, President, and
CFO. These shares were valued at $3.8 million, based on the May 16, 2017, closing stock price of $7.74.
By shareholder approval on May 25, 2017, our 2008 Restricted Stock Unit Plan (RSU Plan) was amended and restated to add 1,000,000 shares
and extend its term through May 25, 2027.
On June 6, 2017, our Compensation Committee approved a Four-Year Compensation Plan for our Chairman, President, and CFO that granted them
645,000 RSUs. These shares vest/lapse 25% annually from December 16, 2018 through December 16, 2021, or earlier based on the terms of the
RSU Plan and the applicable award agreements. The closing stock price on the date of grant was $8.23.
55
The table below shows the number of RSUs available for issuance at December 31, 2018:
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, 2016
Granted – weighted average share price on grant date was $7.98
Vested – weighted average share price on vesting date was $7.22
Forfeited
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 (1)
(1) RSU Vesting Schedule
Vesting Year
2019
2020
2021
4,850,000
(2,802,284)
(789,250)
1,258,466
733,000
1,211,500
(990,500)
(9,500)
944,500
202,000
(344,750)
(12,500)
789,250
RSUs Vesting
304,750
176,250
308,250
789,250
Vested shares had a value of $2.1 million for 2018, and $7.1 million for 2017 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 $4.07 million based on the March 8, 2019 closing stock price of $5.16.
For the years ended December 31, 2018 and 2017 stock-based compensation was $3.2 million and $7.3 million, respectively. For 2019, 2020, and
2021, based on existing RSUs outstanding, stock-based compensation expense is estimated to be $1.9 million, $1.2 million, and $1.1 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.
(6) Employee Benefits
We have no defined benefit pension plans or post-retirement benefit plans. We offer our employees a 401(k) Plan, where we match 100% of the first
4% that an employee contributes and a discretionary Deferred Bonus Plan for certain key employees. We also offer health benefits to all employees
and their families. We have 2,481 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.
56
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
$
$
2018
2017
13,070 $
1,811
722
15,603 $
13,603
1,943
677
16,223
Of the amounts in the above table, $15.1 million and $15.8 million are recorded in operating costs and expenses for 2018 and 2017, respectively,
with the remainder in SG&A.
Our mine employees are also covered by workers’ compensation and such costs for 2018 and 2017 were approximately $3.0 million and $2.5
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 23% below that of our peers in underground coal mining in the state of Indiana.
(7) Other Long-Term Assets (in thousands)
Advanced coal royalties
Marketable equity securities available for sale, at fair value (restricted)*
Other
Total other long-term assets
*Held by Sunrise Indemnity, Inc., our wholly owned captive insurance company.
(8) Accounts Payable and Accrued Liabilities (in thousands)
Accounts payable
Goods received not yet invoiced
Accrued property taxes
Accrued payroll
Workers' compensation reserve
Group health insurance
Other
Total accounts payable and accrued liabilities
$
$
$
$
2018
2017
10,186 $
1,909
2,122
14,217 $
9,720
2,148
2,792
14,660
2018
2017
5,844 $
6,095
2,763
1,825
3,670
2,200
4,024
26,421 $
4,008
5,574
2,751
1,403
2,969
1,332
3,078
21,115
57
(9) Other Income (in thousands)
Equity income - Savoy
Equity loss - Sunrise Energy
Loss on disposal of Savoy
MSHA reimbursements
Miscellaneous
(10) Self Insurance
$
$
2018
2017
- $
(187)
(538)
1,013
1,486
1,774 $
460
(95)
-
1,725
1,341
3,431
We self-insure our underground mining equipment. Such equipment is allocated among 10 mining units spread out over 22 miles. The historical cost
of such equipment is about $255 million.
As of December 31, 2018, and 2017, restricted cash of $4.6 million and $3.8 million, respectively, represents cash held and controlled by a third
party and is restricted for future workers’ compensation claim payments.
(11) Net Income per Share
We compute net income per share using the two-class method, which is an allocation formula that determines net income per share for common
stock and participating securities, which for us are our outstanding RSUs.
The following table (in thousands, except per share amounts) sets forth the computation of net income per share:
Numerator:
Net income
Less earnings allocated to RSUs
Net income allocated to common shareholders
Denominator:
2018
2017
$
$
7,621 $
(185)
7,436 $
33,076
(1,028)
32,048
Weighted average number of common shares outstanding
30,074
29,661
Net income per share:
Basic and diluted
(12) Fair Value Measurements
$
0.25 $
1.08
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.
58
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less
observable from objective sources (i.e., supported by little or no market activity). Our Level 3 instruments are comprised of interest rate swaps. The
fair values of our swaps were estimated using discounted cash flow calculations based upon forward interest-rate yield curves. 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 following table summarizes our financial assets and liabilities measured on a recurring basis at fair value at December 31, 2018 and 2017 by
respective level of the fair value hierarchy (in thousands):
Level 1
Level 2
Level 3
Total
December 31, 2018
Assets:
Marketable securities
Marketable securities - restricted
Liabilities:
Interest rate swaps
December 31, 2017
Assets:
Marketable securities
Marketable securities – restricted
Interest rate swaps
$
$
$
$
$
1,842 $
1,909
3,751 $
- $
1,907 $
2,148
-
4,055 $
- $
-
- $
- $
- $
-
-
- $
The table below highlights the change in fair value of the interest rate swaps (in thousands):
Ending balance, December 31, 2016
Change in estimated fair value
Ending balance, December 31, 2017
Change in estimated fair value
Ending balance, December 31, 2018
(13) Equity Method Investments
Savoy Energy, L.P.
- $
-
- $
1,639 $
- $
-
543
543 $
$
$
1,842
1,909
3,751
1,639
1,907
2,148
543
4,598
(180)
723
543
(2,182)
(1,639)
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, 2018, and December 31, 2017, was
$3.7 million and $3.9 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.
59
(14) REVENUE
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 condensed consolidated statements of comprehensive income.
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. 73% and 68% of our coal revenue for the years ended December 31, 2018 and 2017,
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 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 railcar at the
mine. This is also the point at which physical possession of the coal transfers to the customer, as well as the significant risks and rewards in
ownership of the coal.
60
We have remaining performance obligations relating to fixed priced contracts of approximately $840 million, which represent the average fixed
prices on our committed contracts as of December 31, 2018. We expect to recognize approximately 68% of this revenue through 2020, with the
remainder recognized thereafter. We have remaining performance obligations relating to index priced contracts or contracts with price reopeners of
approximately $330 million, which represents our estimate of the expected re-opener/indexed price on committed contracts as of December 31,
2018. We expect to recognize all of this income 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.
61
(15) 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.
Below is a condensed Hourglass balance sheet and a condensed statement of operations as of December 31, 2018 Current assets include cash
totaling $2.9 million and sand inventory totaling $1.3 million. Expenses are included in operating costs and expenses, exploration costs, and SG&A
in our consolidated statements of comprehensive income.
Condensed Balance Sheet
Current assets
Property and equipment
Total assets
Total liabilities
Redeemable noncontrolling interests
Members' equity
Total liabilities and equity
Revenue
Expenses
Net loss
Condensed Statement of Operations
$
$
$
$
$
$
4,241
3,092
7,333
502
4,000
2,831
7,333
255
1,424
(1,169)
62
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, 2018. Based on that
evaluation, our management concluded that our ICFR was effective at December 31, 2018. Plante & Moran, PLLC has audited and reported on our
financial statements and our ICFR as of December 31, 2018. 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, 2018 that
have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
63
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 2019.
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.
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
10.2
10.3
10.5
10.6
10.7
14
21.1
23.1
31
32
95
101
(1)
(2)
(3)
(4)
(5)
(6)
(7)
(8)
(9)
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009. (1)
By-laws of Hallador Energy Company, effective December 24, 2009 (1)
2009 Stock Bonus Plan (2)*
Third Amended and Restated Credit Agreement dated May 21, 2018 (3)
Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement* (5)
Amended and Restated Hallador Energy Company 2008 Restricted Stock Unit Plan (6)
Hallador Energy Company Four-Year Plan* (7)
Code of Ethics for Senior Financial Officers. (8)*
List of Subsidiaries (9)
Consent of Plante & Moran, PLLC (9)
SOX 302 Certifications (9)
SOX 906 Certification (9)
Mine Safety Disclosure (9)
Interactive data files. (9)
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 May 6, 2016
IBR to Form 8-K dated May 17, 2017
IBR to Form 10-Q dated August 8, 2017
IBR to Form 10-Q dated May 6, 2016
IBR to the 2005 Form 10-KSB.
Filed herewith.
*Management Agreements
ITEM 16.
Form 10-K Summary.
As this item is optional, no summary is presented.
64
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 11, 2019
HALLADOR ENERGY COMPANY
/s/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO and CAO
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/DAVID HARDIE
David Hardie
/s/BRYAN LAWRENCE
Bryan Lawrence
/s/BRENT BILSLAND
Brent Bilsland
/s/DAVID J. LUBAR
David J. Lubar
Director
Director
March 11, 2019
March 11, 2019
Board Chairman, President and CEO
March 11, 2019
Director
March 11, 2019
65
Exhibit 21.1
List of Subsidiaries
Edwardsport Construction Company, LLC
Gibson County Logistics, LLC
Hourglass Sands, LLC
High Point Land Holdings LLC
Oaktown Fuels Mine No. 1, LLC
Oaktown Fuels Mine No. 2, LLC
Prosperity Mine, 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 11, 2019 relating to the financial statements and the effectiveness of internal control
over financial reporting for the fiscal year ended December 31, 2018, which appears in this Form 10-K.
/s/ Plante & Moran, PLLC
Denver, CO
March 11, 2019
Exhibit 23.2
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 12, 2018 relating to the financial statements and the effectiveness of internal control
over financial reporting for each of the fiscal years ended December 31, 2017, which appears in this Form 10-K.
/s/ EKS&H LLLP
Denver, CO
March 11, 2019
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 officer 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 officer 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 11, 2019
/s/BRENT K. BILSLAND
Brent K. Bilsland, President and CEO
Exhibit 31.2
CERTIFICATION
I, Lawrence D. Martin, certify that:
1. I have reviewed this annual report on Form 10-K of Hallador Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered
by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects
the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer 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 officer 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 11, 2019
/s/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO
Exhibit 32
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, 2018, 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:
(1)
(2)
March 11, 2019
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.
By;
/s/BRENT K. BILSLAND
Brent K. Bilsland, President and CEO
/s/LAWRENCE D. MARTIN
Lawrence D. Martin, CFO
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 outlines required disclosures and citations/orders issued to us by MSHA during 2018. 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 2018
Section
104(a)
Citations
Section
104(b)
Orders
Section
104(d)
Citations/Orders
Section
107(a)
Orders
Section
110(b)(2)
Violations
11
0
1
37
32
1
0
Section
104(e)
Notice
Yes/No
Section
104(e)
POV
Yes/No
No
No
No
No
No
No
No
0
0
0
0
0
0
0
No
No
No
No
No
No
No
0
0
0
1
0
0
0
Mining
Related
Fatalities
Legal
Actions
Pending
0
0
0
1
0
0
0
0
0
0
0
1
0
0
0
0
0
2
2
0
0
Contest of
Citations/
Orders
Contest
of
Penalties
Complaints
of
Complaints
of Discharge/
Compensation Discrimination
Applications
of Temp.
Relief
Appeals of
Decisions/
Orders
0
0
0
5
2
0
0
0
0
0
1
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Proposed
MSHA
Assessments
(In thousands)
3.70
0.00
0.90
107.00
38.50
0.35
0.00
0 $
0 $
0 $
0 $
0 $
0 $
0 $
Legal
Actions
Initiated
Legal
Actions
Resolved
0
0
0
7
2
0
0
0
0
0
6
0
0
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