Indicate by check mark whether the registrant
is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of "larger accelerated filer," "accelerated filer" and "smaller reporting company" in
Rule 12b-2 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).
The aggregate market value of the common stock
held by non-affiliates (public float) on June 30, 2017 was $124.5 million based on the closing price reported that date by the
NASDAQ of $7.77 per share.
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, 2018 in New York City, NY.
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 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 reasonable, but 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:
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:
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employee health and safety;
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mine permits and other licensing requirements;
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water quality standards;
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storage of petroleum products and substances
that are regarded as hazardous under applicable laws or that, if spilled, could reach waterways or wetlands;
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plant and wildlife protection;
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reclamation and restoration of mining properties
after mining is completed;
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discharge of materials;
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storage and handling of explosives;
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surface subsidence from underground mining;
and
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the effects, if any, that mining has on groundwater
quality and availability.
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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 the costs of compliance with applicable federal and state laws and
associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws
and regulations has substantially increased the cost of coal mining for domestic coal producers.
Capital expenditures for environmental matters
have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations
and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement
obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations
and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and
other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.
Mining Permits and
Approvals
Numerous governmental permits or approvals
are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation
and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These
matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and impacts
on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting
all requirements imposed by any of these authorities may be costly and time-consuming, 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:
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sealing off abandoned areas of underground
coal mines;
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mine safety equipment, training, and emergency
reporting requirements;
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substantially increased civil penalties for
regulatory violations;
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training and availability of mine rescue teams;
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underground “refuge alternatives”
capable of sustaining trapped miners in the event of an emergency;
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flame-resistant conveyor belts, fire prevention
and detection, and use of air from the belt entry; and
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post-accident two-way communications and electronic
tracking systems.
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MSHA continues to interpret and implement various
provisions of the MINER Act, along with introducing new proposed regulations and standards.
In 2014, MSHA began implementation of a finalized
new regulation titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust
Monitors.” The final rule implements 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.
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 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. It is uncertain whether MSHA will present a proposed rule pertaining to exposure
of underground miners to diesel exhaust, after completing its evaluation of the comments received.
Subsequent to passage of the MINER Act, Illinois,
Kentucky, Pennsylvania and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting,
increased civil and criminal penalties, and increased inspections and oversight. Additionally, state administrative agencies can
promulgate administrative rules and regulations affecting our operations. Other states may pass similar legislation
or administrative regulations in the future.
Some of the costs of complying with existing
regulations and implementing new safety and health regulations may be passed on to our customers. Although we have not quantified
the full impact, implementing and complying with these new 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 levies a tax on production 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. We are also liable
under state statutes for black lung claims. Congress and state legislatures regularly consider various items of black lung
legislation, which, if enacted, could adversely affect our business, results of operations and financial position.
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.
Workers’ Compensation
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. States in which we operate consider changes in workers’
compensation laws from time to time.
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 deep mining. Although we have minimal surface mining activity and no mountaintop
removal mining activity, 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 mined property be restored in accordance with specified standards and approved reclamation plans. SMCRA
requires us to restore the surface to approximate the original contours as contemporaneously as practicable with the completion
of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain
water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface
as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. We believe we are
in compliance in all material respects with applicable regulations relating to reclamation.
In addition, the Abandoned Mine Lands Program,
which is part of SMCRA, imposes a 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 on December 22, 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.
OSM issued its final Stream Protection Rule
("SPR") in December 2016 to replace the vacated SBZ rule. The rule would have generally prohibited the approval
of permits issued pursuant to SMCRA where the proposed operations would result in "material damage to the hydrologic balance
outside the permit area." Pursuant to the rule, permittees would have also been required to restore any perennial or intermittent
streams that a permittee mined through. Finally, the rule would have also imposed additional baseline data collection, surface/groundwater
monitoring, and bonding and financial assurance requirements. However, in February 2017, both the U.S. House of Representatives
and the Senate passed resolutions disapproving the SPR under the Congressional Review Act ("CRA"). President Trump signed
the resolution on February 16, 2017, and, pursuant to the CRA, the SPR "shall have no force or effect" and OSM cannot
promulgate a substantially similar rule absent future legislation. Whether Congress will enact future legislation to
require a new SPR rule remains uncertain.
Following the spill
of coal combustion residues (“CCRs”) in the Tennessee Valley Authority impoundment in Kingston, Tennessee, in December 2009,
the EPA issued proposed rules on CCRs in 2010. This final rule was published on December 19, 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 us and for our competitors to secure new surety bonds
without posting collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally
become less favorable to us. It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral
upon those renewals. Our failure to maintain or inability to acquire, surety bonds that are required by state and federal
laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.
Air Emissions
The CAA and similar state and local laws and
regulations regulate emissions into the air and affect coal mining operations. The CAA directly impacts our coal mining and
processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control
equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants.
The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power
generating plants and other coal-burning 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 costlier 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 formally announced the
retirement or conversion of over 600 coal-fired electric generating units through 2030.
In addition to the greenhouse gas (“GHG”)
issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not
limited to, the following:
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The EPA’s Acid Rain Program, provided
in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product
of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must
be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities
may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions.
In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements
of the EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas
desulfurization systems, or “scrubbers,” or by reducing electricity generating levels. These requirements would not
be supplanted by a replacement rule for the Clean Air Interstate Rule (“CAIR”), discussed below.
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The CAIR calls for power plants in 28 states
and Washington, D.C. to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar
to the system in effect for acid rain. In June 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”),
a replacement rule for CAIR, which would have required 28 states in the Midwest and eastern seaboard to reduce power plant
emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. 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 on December 10,
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. Further litigation is expected 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.
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In February 2012, the EPA adopted the
MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from
coal and oil-fired power plants. In March 2013, the EPA finalized a reconsideration of the MATS rule as it pertains
to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies. Appeals were
filed, and oral arguments were heard by the D.C. Circuit Court of Appeals in December 2013. On April 15, 2014,
the D.C. Circuit Court of Appeals upheld MATS. On June 29, 2015, the 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.
On December 1, 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 EPA's request to cancel oral arguments and ordered the case held in abeyance for an EPA review
of the supplemental finding. 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 will force generators to make
capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating
units. The announced and possible additional retirements are likely to reduce the demand for coal. Apart from MATS, several
states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal
legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA,
states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with
CSAPR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.
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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. On December 1, 2014, the EPA announced a 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. The impact of the regulations
will depend on the EPA's reconsideration and the outcome of subsequent legal challenges. The impact of the regulations will depend
on the EPA’s reconsideration and the outcome of subsequent legal challenges.
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The EPA is required by the CAA to periodically
re-evaluate the available health effects information to determine whether the national ambient air quality standards (“NAAQS”)
should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter (“PM”),
ozone, nitrogen oxide and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and
maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were
previously in “attainment” but do not attain the new standards. In addition, under the revised ozone NAAQS, significant
additional emissions control expenditures may be required at coal-fired power plants. Initial non-attainment determinations related
to the revised sulfur dioxide standard became effective in October 2013. In addition, in January 2013, the EPA
updated the NAAQS for fine particulate matter emitted by a wide variety of sources including power plants, industrial facilities,
and gasoline and diesel engines, tightening the annual PM 2.5 standard to 12 micrograms per cubic meter. The revised standard
became effective in March 2013. In November 2013, the EPA proposed a rule to clarify PM 2.5 implementation
requirements to the states for current 1997 and 2006 non-attainment areas. In July 2016, the EPA issued a final rule for
states to use in creating their plans to address the particulate matter. On October 26, 2015, the EPA published a final rule that
reduced the ozone NAAQS from 75 to 70 ppb. Murray Energy filed a challenge to the final rule in the D.C. Circuit.
Since that time, other industry and state petitioners have filed challenges 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 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. 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.
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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 recent 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.
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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. Depending on the ultimate resolution of these cases,
demand for coal could be affected.
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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. 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.
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 2012, the D.C. Circuit Court of Appeals upheld
these permitting regulations. In June 2014, the U.S. Supreme Court invalidated the EPA’s position that power plants
and other sources can be subject to permitting requirements based on their GHG emissions alone. For CO
2
BACT
to apply, CAA permitting must be triggered by another regulated pollutant (e.g., SO
2
).
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. CO
2
/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. CO
2
/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 CO
2
/MWh (gross) and be constructed with CCS to capture 16% of
CO
2
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. 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 EPA's
regulations for CO
2
emissions from existing power plants and will not affect EPA's standards for new power plants. It
is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP. Additionally, 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. If the
effort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of this appellate process and were implemented
in their current form, or if the ANPRM results in a different proposal to control GHG emissions from electric utility generating
units, demand for coal would likely be further decreased, potentially significantly, and our business would be adversely impacted.
Collectively, 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 for 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.
These standards generally range from 10% to 30%, over time periods that generally extend from the present until between 2020 and
2030. 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 claim 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 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 a more detailed discussion of the direct, indirect,
and cumulative impacts of a proposed action’s reasonably foreseeable emissions and effects. This guidance could create
additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals
for our future operations, including due to the increased risk of legal challenges from environmental groups seeking additional
analysis of climate impacts. In April 2017, CEQ withdrew its final 2016 guidance on how federal agencies should incorporate climate
change and GHG considerations into NEPA reviews of federal actions.
Many states and regions have adopted GHG initiatives,
and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain
facilities, including coal-fired electric generating facilities. For example, in 2005, ten Northeastern states entered into
the Regional Greenhouse Gas Initiative agreement (“RGGI”), calling for the implementation of a cap and trade program
aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established
in statutes and/or regulations a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program
began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional northeastern
states and Canadian provinces have joined as participants or observers. New Jersey has announced its intention to rejoin RGGI following
the change in state government administrations.
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.
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 uncertainly with regard to our continued use of current permits, as well as impose additional time and cost
burdens on future operations, potentially adversely affecting our coal revenue. 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.
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 Clean Water
Act. A 2015 rulemaking by 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, EPA has promulgated a final rule that extends the applicability date of
the 2015 rule for another two years in order to allow EPA to undertake a rulemaking on the question of what constitutes a water
of the United States. In the meantime, judicial challenges to the 2015 rulemaking are likely to continue to work their way through
the courts along with challenges to the recent rulemaking that extends the applicability date of the 2015 rule. For now, 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 EPA and the Corps of Engineers'
rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible
challenges to permitting decisions.
Hazardous Substances
and Wastes
The Federal Comprehensive Environmental Response,
Compensation and Liability Act (“CERCLA”), otherwise known as the “Superfund” law, and analogous state
laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are
considered to have contributed to the release of a “hazardous substance” into the environment. These persons
include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of
the hazardous substances found at the site. Persons who are or were responsible for the release of hazardous substances may
be subject to joint and several liabilities 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.
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 (“Subtitle D”) of RCRA and not the hazardous waste provisions (“Subtitle
C”) which became effective on October 19, 2015. EPA affirms in the preamble to the final rule that “this
rule does not apply to CCR placed in active or abandoned underground or surface mines.” Instead, “the U.S.
Department of Interior (“DOI”) and EPA will address the management of CCR in mine fills in a separate regulatory action(s).”
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, 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, EPA granted petitions for reconsideration and an administrative
stay of all future compliance deadlines for the ELG rule. In August 2017, EPA granted petitions for reconsideration
of the CCR rule.
Endangered Species Act
The federal Endangered Species Act (“ESA”)
and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the
“USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected
from 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.
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.
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 use the continuous 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) and Alliance (Nasdaq: ARLP) and small producers.
Employees
We have 742 employees, of which 736 are Sunrise
Coal employees.
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:
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the demand for electricity in the U.S. may
decline if economic conditions deteriorate, which may negatively impact the revenue, margins, and profitability of our business;
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any inability of our customers to raise capital
could adversely affect their ability to honor their obligations to us; and
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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
the development of our coal reserves.
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A substantial or extended decline in
coal prices could negatively impact our results of operations.
Our results of operations are primarily dependent
upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. The prices we
receive for our production depends upon factors beyond our control, including:
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the supply of and demand for domestic and
foreign coal;
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weather conditions and patterns;
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the proximity to and capacity of transportation
facilities;
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competition from other coal suppliers;
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domestic and foreign governmental regulations
and taxes;
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the price and availability of alternative
fuels;
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the effect of worldwide energy consumption,
including the impact of technological advances on energy consumption; and
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prevailing economic conditions.
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Any adverse change in these factors could result
in weaker demand and lower prices for our products. A substantial or extended decline in coal prices could materially and
adversely affect us by decreasing our revenue to the extent we are not protected by the terms of existing coal supply agreements.
Competition within the coal industry
may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal
prices.
We compete with other coal producers for domestic
coal sales. The most important factors on which we compete are delivered price (
i.e.
, the cost of coal delivered to
the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality
characteristics, contract flexibility (
e.g.
, volume optionality and multiple supply sources) and reliability of supply.
Some competitors may have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships
with specific transportation providers. The competition among coal producers may impact our ability to retain or attract
customers and could adversely impact our revenue and cash from operations. In addition, declining prices from an oversupply
of coal in the market could reduce our revenue and cash from operations.
Changes in consumption patterns by utilities
regarding the use of coal have affected our ability to sell the coal we produce. Since 2000, coal’s share of U.S. electricity
production has fallen from 53% to 30%, while natural gas’ share has increased from 16% to 32%.
The domestic electric utility industry accounts
for over 93% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected
primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability
of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled
generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators.
We expect that many of the new power plants needed in the U.S. to meet increasing demand for electricity generation will be fueled
by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain.
Future environmental regulation of GHG emissions
could accelerate the use by utilities of fuels other than coal. In addition, state and federal mandates for increased use
of electricity derived from renewable energy sources could affect demand for coal. For example, the EPA’s CPP will
likely incentivize additional electric generation from natural gas and renewable sources, and Congress has extended tax credits
for renewables. In addition, a number of states have enacted mandates that require electricity suppliers to rely on renewable
energy sources in generating a certain percentage of power. Such mandates, combined with other incentives to use renewable
energy sources, such as tax credits, could make alternative fuel sources more competitive with coal. A decrease in coal consumption
by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of
operations and reduce our cash from operations.
Extensive environmental laws and regulations
affect coal consumers and have corresponding effects on the demand for coal as a fuel source.
Federal, state and local laws and regulations
extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into
the air from coal-fired electric power plants, which are the ultimate consumers of much of our coal. These laws and regulations
can require significant emission control expenditures for many coal-fired power plants, and various new and proposed laws and regulations
may require further emission reductions and associated emission control expenditures. These laws and regulations may affect
demand and prices for coal. There is also continuing pressure on state and federal regulators to impose limits on carbon
dioxide emissions from electric power plants, particularly coal-fired power plants. Further, far-reaching federal regulations
promulgated by the EPA in the last five years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating
units and a significant reduction in the amount of coal-fired generating capacity in the U.S.
Increased regulation of GHG emissions
could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for our products,
decrease our revenue and reduce our profitability.
Combustion of fossil fuels, such as the coal
we produce, results in the emission of carbon dioxide into the atmosphere. On December 15, 2009, the EPA published the
Endangerment Finding asserting that emissions of carbon dioxide and other GHGs present an endangerment to public health and the
environment, and the EPA has begun to regulate GHG emissions pursuant to the CAA. The EPA has finalized an NSPS to regulate
GHG emissions from new power plants. The finalized standard requires CCS, a technology that is not yet commercially feasible
without government subsidies and that has not been demonstrated in the marketplace. This requirement effectively prevents
the construction of new coal-fired power plants. The EPA published notice in the federal register in April 2017 that the agency
has initiated a review of the NSPS for new and modified fossil fuel-fired power plants and that, following the review, the EPA
will initiate reconsideration proceedings to suspend, revise or rescind this NSPS. In August 2015, the EPA issued its
final CPP rules that establish carbon pollution standards for existing power plants, called 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 EPA's regulations for CO
2
emissions from existing power plants and will not affect
EPA's standards for new power plants. It is not yet clear how either the Circuit Court or the Supreme Court will rule
on the legality of the CPP. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action
and the pending litigation regarding the CPP is uncertain at this time. In connection with this proposed repeal,
the EPA issued an ANPRM in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility
generating units. The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source
regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the
effort to repeal the rules is unsuccessful and the rules were upheld at the conclusion of this appellate process and were implemented
in their current form, or if the ANPRM results in a different proposal to control GHG emissions from electric utility generating
units, demand for coal would likely be further decreased, potentially significantly, and our business would be adversely impacted.
Please read “Item 1. Business—Regulation and Laws—
Air Emissions
” and “—
Carbon Dioxide
Emissions
.”
Numerous political and regulatory authorities
and governmental bodies, as well as environmental activist groups, are devoting substantial resources to anti-coal activities to
minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further
reducing the demand and pricing for coal and potentially materially and adversely impacting our future financial results, liquidity
and growth prospects.
Concerns about the environmental impacts of
coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion
in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the investment community,
which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and
scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may
produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and
floods and other climatic events. Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental
Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on
global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs,
including emissions of carbon dioxide from coal combustion by power plants.
Federal, state and local governments may pass
laws mandating the use of alternative energy sources, such as wind power and solar energy, which may decrease demand for our coal
products. The CPP is one of a number of recent developments aimed at limiting GHG emissions which could limit the market
for some of our products by encouraging electric generation from sources that do not generate the same amount of GHG emissions.
Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries,
could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant
closures. For example, the agreement resulting from the 2015 United Nations Framework Convention on Climate Change contains
voluntary commitments by numerous countries to reduce their GHG emissions and could result in additional firm commitments by various
nations with respect to future GHG emissions. These commitments could further disfavor coal-fired generation, particularly
in the medium to long-term.
There have also been efforts in recent years
affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities and
other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged
in the extraction of fossil fuel reserves. In California, for example, legislation was signed into law in October 2015
that requires California’s state pension funds to divest investments in companies that generate 50% or more of their revenue
from coal mining by July 2017. Other activist campaigns have urged banks to cease financing coal-driven businesses.
As a result, several major banks enacted such policies. The impact of such efforts may adversely affect the demand for and
price of securities issued by us, and impact our access to the capital and financial markets.
In addition, several well-funded non-governmental
organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation.
Collectively, these actions and campaigns could adversely impact our future financial results, liquidity and growth prospects.
Government regulations have resulted
and could continue to result in significant retirements of coal-fired electric generating units. Retirements of coal-fired
electric generating units decrease the overall capacity to burn coal and negatively impact coal demand.
Since 2010, utilities have formally announced
the retirement or conversion of over 600 coal-fired electric generating units through 2030. These retirements and conversions
amount to over 111,000 megawatts (“MW”) or approximately 35% of the 2010 total coal electric generating capacity.
At the end of 2017 retirement and conversions affecting 69,000 MW, or approximately 22% of the 2010 total coal electric generating
capacity, is estimated to have occurred. Most of these announced and completed retirements and conversions have been attributed
to the EPA regulations, although other factors such as an aging coal fleet and low natural gas prices have also played a role.
The reduction in coal electric capacity negatively impacts overall coal demand. Additional regulations and other factors
could lead to additional retirements and conversions and, thereby, additional reductions in the demand for coal.
Plaintiffs in federal court litigation
have attempted to pursue tort claims based on the alleged effects of climate change
.
In 2004, eight states and New York City sued
five electric utility companies 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.
The proliferation of successful climate change litigation could adversely impact demand for coal and ultimately have a material
adverse effect on our business, financial condition and results of operations.
The stability and profitability of our
operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into
new long-term contracts for coal.
In 2017, approximately 50% 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. Any adjustment or renegotiation leading to a
significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term contracts
may provide only limited protection during adverse market conditions. In some circumstances, failure of the parties to agree
on a price under a reopener provision can also lead to early termination of a contract.
Several of our long-term contracts also contain
provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of
certain events that are beyond the customer’s reasonable control. Such events may include labor disputes, mechanical
malfunctions and changes in government regulations, including changes in environmental regulations rendering use of our coal inconsistent
with the customer’s environmental compliance strategies. Additionally, most of our long-term contracts contain provisions
requiring us to deliver coal within stated ranges for specific coal characteristics. Failure to meet these specifications
can result in economic penalties, rejection or suspension of shipments or termination of the contracts. In the event of early
termination of any of our long-term contracts, if we are unable to enter into new contracts on similar terms, our business, financial
condition and results of operations could be adversely affected.
We depend on a few customers for a significant
portion of our revenue, and the loss of one or more significant customers could affect our ability to maintain the sales volume
and price of the coal we produce.
During 2017, we derived 92% of our revenue
from five customers and at least 10% of our revenue from each of them. If we were to lose any of these customers without
finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to
decrease the amounts of coal purchased or the terms, including pricing terms, on which they buy coal from us, it could have a material
adverse effect on our business, financial condition and results of operations.
Litigation resulting from disputes with
our customers may result in substantial costs, liabilities, and loss of revenue.
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 revenue 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:
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mining and processing equipment failures and
unexpected maintenance problems;
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unavailability of required equipment;
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prices for fuel, steel, explosives and other
supplies;
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fines and penalties incurred as a result of
alleged violations of environmental and safety laws and regulations;
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variations in thickness of the layer, or seam,
of coal;
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amounts of overburden, partings, rock and
other natural materials;
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weather conditions, such as heavy rains, flooding,
ice and other natural events affecting operations, transportation or customers;
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accidental mine water discharges and other
geological conditions;
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seismic activities, ground failures, rock
bursts or structural cave-ins or slides;
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employee injuries or fatalities;
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labor-related interruptions;
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increased reclamation costs;
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inability to acquire, maintain or renew mining
rights or permits in a timely manner, if at all;
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fluctuations in transportation costs and the
availability or reliability of transportation; and
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unexpected operational interruptions due to
other factors.
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These conditions have the potential to significantly
impact our operating results. Prolonged disruption of production at any of our mines would result in a decrease in our revenue
and profitability, which could materially adversely impact our quarterly or annual results.
Although none of our employees are members
of unions, our workforce may not remain union-free in the future.
None of our employees are represented under
collective bargaining agreements. However, all of our workforce may not remain union-free in the future, and legislative,
regulatory or other governmental action could make it more difficult to remain union-free. If some or all of our currently
union-free operations were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at
our mining complexes. In addition, even if we remain union-free, our operations 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
.”
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 revenue by causing us to reduce our production or by impairing
our ability to supply coal to our customers.
Transportation costs represent a significant
portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s
purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make
our coal production less competitive than coal produced from other sources. Disruption of transportation services due to
weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events
could temporarily impair our ability to supply coal to our customers. Our transportation providers may face difficulties
in the future that may impair our ability to supply coal to our customers, resulting in decreased revenue. If there are disruptions
of the transportation services provided by our primary rail carriers that transport our coal and we are unable to find alternative
transportation providers to ship our coal, our business could be adversely affected.
Conversely, significant decreases in transportation
costs could result in increased competition from coal producers in other parts of the country. For instance, difficulty in
coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain
and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more
expensive on a per-mile basis than coal shipments originating in the western U.S. Historically, high coal transportation
rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets.
Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive
challenges for eastern coal producers. 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 revenue.
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:
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uncertainties in assessing the value, strengths,
and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including
environmental or mine safety liabilities) of, expansion and acquisition opportunities;
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the ability to achieve identified operating
and financial synergies anticipated to result from an expansion or an acquisition;
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problems that could arise from the integration
of the new operations; and
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unanticipated changes in business, industry
or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.
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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. Weakness in the energy sector in general and coal, in particular, has
significantly impacted access to the debt and equity capital markets. Accordingly, our funding plans may be negatively impacted
by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower
than expected cash flow from operations. In addition, we may be unable to refinance our current credit facilities 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:
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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;
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the percentage of coal in the ground ultimately
recoverable;
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historical production from the area compared
with production from other producing areas;
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the assumed effects of regulation and taxes
by governmental agencies;
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future improvements in mining technology;
and
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assumptions concerning future coal prices,
operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.
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For these reasons, estimates of the recoverable
quantities of coal attributable to any particular group of properties, classifications of reserves based on the risk of recovery
and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers
at different times, may vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely
vary from estimates, and these variations may be material. Any inaccuracy in the estimates of our reserves could result in
higher than expected costs and decreased profitability.
Mining in certain areas in which we operate
is more difficult and involves more regulatory constraints than mining in other areas of the U.S., which could affect the mining
operations and cost structures of these areas.
The geological characteristics of some of our
coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine. As mines become
depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to
those characteristics 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. In March, 2018, President Trump announced
that his administration would be assessing tariffs on steel imports which could increase our costs significantly.
Failure to obtain or renew surety bonds
on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine
or lease coal.
Federal and state laws require us to obtain
surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. We may
have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including
letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to
have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other
guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could
result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party
surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and
future third-party surety bond issuers under the terms of our financing arrangements.
Terrorist attacks or cyber-incidents
could result in information theft, data corruption, operational disruption and/or financial loss.
Like most companies, we have become increasingly
dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate
our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining
information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such
as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate
attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, or cloud-based
applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery,
difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication
interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences.
Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our
business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be
required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate
any vulnerability to cyber incidents.
Certain federal income tax deductions
currently available with respect to coal mining and production may be eliminated as a result of future legislation.
In past years, members of Congress have
indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including
the percentage depletion allowance with respect to coal properties. No legislation with that effect has been proposed,
but the 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 of 1.25 to 1 and (ii) a current maximum leverage ratio (Sunrise funded debt/adjusted EBITDA)
not to exceed 4.25 to 1, which also decreases in future periods further reducing the maximum leverage permitted. On December
31, 2017, our debt service coverage ratio was 1.90, and our leverage ratio was 2.40. Therefore, we were in compliance with
these two ratios.
Our indebtedness may limit our ability
to borrow additional funds or capitalize on business opportunities.
On December 31, 2017, our debt was $202
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
Carlisle Mine
In December 2016, the deterioration of the
North End of the Carlisle Mine, coupled with lower coal prices led us to determine that the northern end of the Carlisle Mine no
longer could be safely and profitably mined. The sealing of the North End was completed in March 2017. In connection therewith,
we identified specific assets totaling $16.6 million ($15.1 million of property and equipment and $1.5 million of advanced royalties)
that were written off in 2016.
The Carlisle Mine assets had an aggregate net
carrying value of $110 million at December 31, 2017. With the Carlisle Mine remaining in hot idle status, we conducted a
review of the Carlisle Mine assets as of December 31, 2017, based on estimated future net cash flows, and determined that no further
impairment was necessary; however, if future expectations and assumptions change we may incur possible impairment in future periods.
Bulldog Reserves
In October 2017, we entered into an agreement
to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase
the property for 8 years. Because of the likelihood of exercising the repurchase option, we are accounting for the sale as a financing
transaction. The Bulldog Mine assets had an aggregate net carrying value of $15 million at December 31, 2017. Also in October 2017,
the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable.
The permit will be issued upon submittal of a fee and bond which are required within 12 months of the notification. We have determined
that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.
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 sixteen years’ experience estimating coal reserves.
Standards set forth by the USGS were used to
place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards, coal within
1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable category. Only tons
greater than 4’ in thickness are included in our underground reserves. All reserves are stated as a final salable product.
Prior to acquiring coal mineral leases, title
abstractors conduct a preliminary title search on the property. This information provides a strong indication of the
coal owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us the rights to explore
and mine the property. Prior to mining, attorneys review the chain of mineral ownership to verify the lessor is
the mineral owner. Prior to purchasing coal properties, we follow a similar process
ITEM 3. LEGAL PROCEEDINGS.
None
ITEM 4. MINE SAFETY
DISCLOSURES:
Safety is
a core value for us. As such we have dedicated a great deal of time, energy, and resources to creating a culture of safety. Thus,
we are very proud of the mine rescue team at Sunrise Coal whose current list of achievements includes reigning National Champions
of the Nationwide Mine Rescue Skills Championship and Governor’s Award recipient (1
st
place) at the 2017 Indiana
Mine Rescue Association Contest.
See Exhibit 95 to this Form 10-K for a listing
of our mine safety violations.
PART II
ITEM 5. MARKET FOR REGISTRANT'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 46% is held by our officers, directors and their affiliates. The following table sets forth
the dividends paid and the high and low closing sales price for the periods indicated:
|
|
Dividends
Paid
|
|
|
High
|
|
|
Low
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
January 1 through March 9
|
|
$
|
0.04
|
|
|
$
|
7.31
|
|
|
$
|
5.96
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth quarter
|
|
|
.04
|
|
|
|
6.56
|
|
|
|
4.87
|
|
Third quarter
|
|
|
.04
|
|
|
|
8.34
|
|
|
|
5.40
|
|
Second quarter
|
|
|
.04
|
|
|
|
8.32
|
|
|
|
6.30
|
|
First quarter
|
|
|
.04
|
|
|
|
9.79
|
|
|
|
7.48
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth quarter
|
|
|
.04
|
|
|
|
10.02
|
|
|
|
7.24
|
|
Third quarter
|
|
|
.04
|
|
|
|
8.26
|
|
|
|
4.50
|
|
Second quarter
|
|
|
.04
|
|
|
|
5.10
|
|
|
|
4.03
|
|
First quarter
|
|
|
.04
|
|
|
|
5.68
|
|
|
|
4.05
|
|
At March 8, 2018, we had 205 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.
Stock Performance
The following performance
compares Hallador Energy (Nasdaq: HNRG), the Russell 2000 Index, the SNL Coal Index, Alliance Resource Partners LP (NYSE: ARLP),
Cloud Peak Energy (NYSE: CLD), and Foresight Energy (NYSE: FELP).
The graph assumes that you invested $100 in
our common stock and in each company and index at the closing price on December 31, 2012, that all dividends were reinvested,
and that you continued to hold your investment through December 31, 2017.
|
|
Period Ended
|
|
Company / Index
|
|
12/31/12
|
|
|
12/31/13
|
|
|
12/31/14
|
|
|
12/31/15
|
|
|
12/31/16
|
|
|
12/31/17
|
|
Hallador Energy Company
|
|
|
100.00
|
|
|
|
99.14
|
|
|
|
137.64
|
|
|
|
58.09
|
|
|
|
119.20
|
|
|
|
81.70
|
|
Russell 2000 Index
|
|
|
100.00
|
|
|
|
138.82
|
|
|
|
145.62
|
|
|
|
139.19
|
|
|
|
168.85
|
|
|
|
193.58
|
|
Alliance Resource Partners LP
|
|
|
100.00
|
|
|
|
141.46
|
|
|
|
167.02
|
|
|
|
57.64
|
|
|
|
107.98
|
|
|
|
103.62
|
|
SNL Coal Index
|
|
|
100.00
|
|
|
|
98.12
|
|
|
|
72.68
|
|
|
|
18.19
|
|
|
|
37.61
|
|
|
|
37.92
|
|
Foresight Energy LP
|
|
|
|
|
|
|
100.00
|
|
|
|
90.66
|
|
|
|
21.51
|
|
|
|
39.43
|
|
|
|
27.41
|
|
Cloud Peak Energy Inc.
|
|
|
100.00
|
|
|
|
93.12
|
|
|
|
47.49
|
|
|
|
10.76
|
|
|
|
29.02
|
|
|
|
23.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Source: S&P Global Market Intelligence
|
|
|
|
|
|
|
|
|
|
|
|
ITEM 6. SELECTED FINANCIAL
DATA.
For the years ended December 31,
(in thousands, except per share data)
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
2013
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
268,202
|
|
|
$
|
278,924
|
|
|
$
|
339,490
|
|
|
$
|
233,902
|
|
|
$
|
137,436
|
|
Equity (loss) income – Savoy
|
|
|
460
|
|
|
|
(1,187
|
)
|
|
|
(1,532
|
)
|
|
|
5,272
|
|
|
|
5,827
|
|
Equity (loss) income - Sunrise Energy
|
|
|
(95
|
)
|
|
|
(249
|
)
|
|
|
(74
|
)
|
|
|
248
|
|
|
|
629
|
|
Liability extinguishment
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,300
|
|
Other
|
|
|
3,066
|
|
|
|
3,962
|
|
|
|
2,236
|
|
|
|
1,749
|
|
|
|
5,678
|
|
|
|
|
271,633
|
|
|
|
281,450
|
|
|
|
340,120
|
|
|
|
241,171
|
|
|
|
153,870
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income before impairment and income taxes*
|
|
|
13,882
|
|
|
|
25,044
|
|
|
|
27,570
|
|
|
|
10,701
|
|
|
|
29,598
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset impairment
|
|
|
-
|
|
|
|
16,560
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Income tax expense (benefit)
|
|
|
(19,194
|
)
|
|
|
(4,026
|
)
|
|
|
7,438
|
|
|
|
482
|
|
|
|
7,175
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
33,076
|
|
|
$
|
12,510
|
|
|
$
|
20,132
|
|
|
$
|
10,219
|
|
|
$
|
22,423
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share :
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
1.08
|
|
|
$
|
0.42
|
|
|
$
|
0.68
|
|
|
$
|
0.34
|
|
|
$
|
0.78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends per share
|
|
$
|
0.16
|
|
|
$
|
0.16
|
|
|
$
|
0.16
|
|
|
$
|
0.16
|
|
|
$
|
0.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet Information (end of period):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets
|
|
$
|
518,193
|
|
|
$
|
531,323
|
|
|
$
|
540,378
|
|
|
$
|
579,585
|
|
|
$
|
259,199
|
|
Total bank debt*
|
|
|
201,992
|
|
|
|
238,617
|
|
|
|
249,470
|
|
|
|
306,345
|
|
|
|
16,000
|
|
* Non-GAAP measurement. See Note 2, Note 3,
and Note 4 to the consolidated financial statements.
|
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 own a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana.
We also own a 30.6% equity interest in Savoy Energy, L.P., a private oil and gas exploration company with operations in Michigan.
We account for our interest in Savoy and Sunrise Energy using the equity method. We have reached an agreement for Savoy to redeem
our entire partnership interest for $8 million, which we expect to finalize in mid-March 2018. Our net after commissions paid will be $7.5 million.
We operate two underground mines and one surface
mine in southwestern Indiana. The underground mines, Oaktown 1 and Oaktown 2 are in Oaktown, Indiana, 43 miles south of Terre Haute,
Indiana. The Ace in the Hole surface mine is in Clay City, Indiana, 30 miles southeast of Terre Haute, Indiana. We also own the
Carlisle Mine located near Carlisle, Indiana, 36 miles south of Terre Haute. The Carlisle reserve is contiguous to Oaktown 2. The
Carlisle Mine is developed, but currently idle.
Oaktown 1, Oaktown 2 and Carlisle are one large
underground mining complex representing 121 million tons of controlled reserves, with three slopes, one elevator, two wash plants,
and two rail facilities, located on the CSX railroad. We anticipate total capacity for the three mines to be roughly 10.5 million
tons annually. Additionally, the capacity of our Ace in the Hole mine is .4 million tons annually. Thus, our total mining capacity
is 10.9 million tons annually. The addition of our Princeton Rail Loop, expected to come online in the spring of 2018, will also
provide us new access to coal markets served by the Norfolk Southern Railway Company.
For 2017, over 67% of our coal sales were to
customers with large scrubbed coal-fired power plants in the State of Indiana. Our mines and coal reserves are strategically located
in close proximity to our primary customers, which reduces transportation costs and thus provides us with a competitive advantage
with respect to those customers; our closest customer’s plant is 13 miles away, and the farthest Indiana customer is
80 miles away. We have access to our primary customers directly through either the CSX railroad (NYSE: CSX) or the Indiana Rail
Road which is majority owned by the CSX. Beginning in Q2 2018, our new Princeton Loop will be operational and allow us to access
the NS Railroad (NYSE: NS), increasing our coal markets.
The majority of our coal is sold to investment
grade customers who have scrubbed power plants; thus, we expect to be supplying these plants for many years.
President Trump Promotes Coal
Below is a timeline of some of the milestones
accomplished for the coal industry thus far under the Trump administration:
November 8, 2016
Donald Trump was elected President
of the United States of America. His administration has dramatically improved the regulatory environment in which we operate.
January 20, 2017
Donald Trump was inaugurated as the
45
th
President of the United States.
February 15, 2017
Both the U.S. House of Representatives and
the Senate passed resolutions disapproving the Stream Protection Rule (SPR) under the Congressional Review Act (CRA). President
Trump signed the resolution on February 16, 2017, and, pursuant to the CRA, the SPR "shall have no force or effect" and
the Office of Surface Mining (OSM) cannot promulgate a substantially similar rule absent future legislation.
Currently, the Federal Surface Mining Control
and Reclamation Act of 1977 (SMCRA) is implemented by each State’s respective State agency, which is the Department of Reclamation
in Indiana. The SPR would have mandated additional approvals from Federal Agencies, such as U.S. Fish and Wildlife. The rule would
have also imposed additional baseline data collection, surface/groundwater monitoring, financial assurance requirements and numerous
other requirements.
February 17, 2017
Scott Pruitt was confirmed as Administrator
of the Environmental Protection Agency (EPA). As former Attorney General of the state of Oklahoma, he joined a coalition of state
attorney generals in suing the EPA concerning the Clean Power Plan, the principal Obama-era policy aimed at reducing U.S. greenhouse
gas emissions from the electricity sector.
February 28, 2017
President Trump signed an Executive
Order regarding the “waters of the US” (WOTUS) rule. The order requires the EPA and the Army Corps of Engineers
to review the WOTUS rule and publish a proposed rule that rescinds or revises the rule as appropriate and consistent with law,
keeps the Nation’s navigable waters free from pollution, promotes economic growth, minimizes regulatory uncertainty, and
shows due regard for the roles of the Congress and the States under the Constitution.
In President Trump’s first
full official speech to a joint session of Congress, he stated: “
We’re going
to stop the regulations that threaten the future and livelihood of our great coal miners.”
March 28, 2017
President Trump signed an Executive
Order to dismantle many of the climate change policies enacted during the Obama era. The order takes steps to downplay the future
costs of carbon emissions, walks back tracking of the federal government’s carbon emissions, rescinds a 2016 moratorium on
coal leases on federal lands. It also begins the process of rescinding the EPA's Clean Power Plan to reduce carbon dioxide emissions
from new and existing power plants.
April 13, 2017
The
EPA said it would review and reconsider the effluent limitations guidelines (ELG) rule which targets coal combustion generators’
ash transport wastewater, and wastewater discharges from flue-gas desulfurization and mercury control systems and would require
power plants to install new treatment technologies. The rule has been challenged in court by a coalition of utilities. The EPA
has issued an administrative stay to delay the compliance deadlines for the ELG rule as long as litigation is ongoing.
June 1, 2017
President Trump announced that the
U.S. would pull out of the Paris Agreement steering away from a group of 194 other countries that have promised to curb planet-warming
greenhouse gas emissions.
October 10, 2017
EPA Administrator Scott
Pruitt announced that the EPA would seek to repeal the Clean Power Plan in its entirety.
January 25, 2018
The Trump administration eliminated
a policy dictating how certain major sources of hazardous air pollutants are regulated. The repeal of the agency’s “once
in, always in” policy. Under the new interpretation of the policy, “major sources” can be reclassed as “area
sources,” which are subject to different standards when their emissions reach an enforceable limit.
These
actions are encouraging and will be important to us and the U.S. energy sector.
Our Coal Contracts
We sell coal to the following customers: Duke
Energy Corporation (NYSE: DUK), Hoosier Energy, an electric cooperative, Indianapolis Power & Light Company (IPL), a wholly-owned
subsidiary of The AES Corporation (NYSE: AES), Vectren Corporation (NYSE: VVC), and Orlando Utility Commission (OUC). In 2018,
we have signed new sales contracts with two plants we have never shipped to before. One of the new customers is certainly due to
the addition of our Princeton Rail Loop on the Norfolk Southern Railroad. The other is to a plant located in the Carolinas. We
attribute the latter to the trend of ILB coals replacing coals from higher cost eastern basins.
The table below reflects our projected tons.
Some of our contracts contain language that allow our customers to increase or decrease tonnages throughout the year. In some cases,
our customers are required to purchase their additional tonnage needs from us. We have 17.7 million tons committed for the next
5 years (2018 to 2022), which represents 51% of our current projected sales.
|
|
Targeted tons
|
|
|
Committed tons
|
|
|
|
|
|
Estimated price
|
|
Year
|
|
(millions)
|
|
|
(millions)
|
|
|
% Committed
|
|
|
per ton
|
|
2018
|
|
|
6.8
|
|
|
|
6.4
|
|
|
|
94
|
%
|
|
$
|
40.00
|
|
2019
|
|
|
7.0
|
|
|
|
4.5
|
|
|
|
64
|
%
|
|
$
|
41.00
|
|
We expect to continue selling a significant
portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply
agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments
required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal
supply agreements result from competitive bidding and extensive negotiations with customers.
Asset Impairment Review
See Note 2 to our consolidated financial statements.
Reserve Table - Controlled Tons (in millions):
|
|
|
|
|
2017 Year-End Reserves
|
|
|
|
|
|
|
|
|
|
Tons
|
|
|
Annual
|
|
|
|
|
|
|
|
|
|
|
|
|
Sold
|
|
|
Capacity
|
|
|
Proven
|
|
|
Probable
|
|
|
Total
|
|
|
Sulphur #
|
|
|
BTU
|
|
Oaktown 1 (assigned)
|
|
|
3.771
|
|
|
|
4.0
|
|
|
|
41.5
|
|
|
|
9.6
|
|
|
|
51.1
|
|
|
|
5.9
|
|
|
|
11,600
|
|
Oaktown 2 (assigned)
|
|
|
2.552
|
|
|
|
4.0
|
|
|
|
30.7
|
|
|
|
12.2
|
|
|
|
42.9
|
|
|
|
5.7
|
|
|
|
11,600
|
|
Carlisle (assigned)
|
|
|
-
|
|
|
|
2.5
|
|
|
|
21.8
|
|
|
|
5.5
|
|
|
|
27.3
|
|
|
|
4.4
|
|
|
|
11,500
|
|
Ace in the Hole (assigned)
|
|
|
0.240
|
|
|
|
0.4
|
|
|
|
0.9
|
|
|
|
-
|
|
|
|
0.9
|
|
|
|
2.0
|
|
|
|
10,900
|
|
Bulldog (unassigned)
|
|
|
-
|
|
|
|
-
|
|
|
|
19.6
|
|
|
|
16.2
|
|
|
|
35.8
|
|
|
|
4.5
|
|
|
|
11,300
|
|
Total
|
|
|
6.563
|
|
|
|
10.9
|
|
|
|
114.5
|
|
|
|
43.5
|
|
|
|
158.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assigned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
122.2
|
|
|
|
|
|
|
|
|
|
Unassigned
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35.8
|
|
|
|
|
|
|
|
|
|
Total
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
158.0
|
|
|
|
|
|
|
|
|
|
Our assigned
underground coal reserves are high sulfur (4.0# – 6.5#) with an average BTU content in the 11,500 -11,600 range. Our reserves
have lower chlorine (<0.12%) than average ILB reserves of 0.22%. Much of the ILB’s new production is located
in Illinois and possesses chlorine content in excess of .30%. The relatively low chlorine content of our reserves is
attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants. As discussed below,
the Ace surface mine is low sulfur (2.0#) with an average BTU content of 10,900. We have no metallurgical coal reserves, only steam
(thermal) coal reserves. Below is a discussion of our current projects. Only tons greater than 4 feet in thickness are included
in our underground reserves.
Oaktown 1 Mine (underground) –
Assigned
We
have 51.1 million controlled, salable tons of the Indiana #V coal seam. We began 2017 with 56.9 million tons controlled. Besides
production, the remainder of the decrease relates to tons that were deemed unrecoverable due to geologic conditions combined with
increases for new drilling and new leases. Oaktown 1 reserves are located in Knox County, IN.
Access to the Oaktown 1 Mine is via a 90-foot-deep
box cut and a 2,200-foot slope, reaching coal in excess of 375 feet below the surface. In 2017, we added an elevator 7 miles from
the slope allowing miners to enter closer to the active face, thereby reducing unproductive daily travel time.
Oaktown 2 Mine (underground) –
Assigned
We have 42.9 million controlled, saleable tons
of the Indiana #V coal seam. We began 2017 with 53.5 million controlled tons. Besides production, the remainder of the decrease
relates to tons that were deemed unrecoverable due to geologic and economic conditions based on new drilling. Oaktown 2 reserves
are located in both Knox County, Indiana and Lawrence County, Illinois.
Access to the Oaktown 2 Mine is via an 80-foot-deep
box cut and a 2,600-foot slope, reaching coal in excess of 400 feet below the surface.
Our underground mines are room and pillar mines
that utilize developed entries for ventilation and transportation. Continuous miners extract coal from rooms by removing coal from
the seam, leaving pillars to support the roof. Coal haulers are used to transport coal to a conveyor belt for transport
to the surface. The two Oaktown mines are separated by a sandstone channel. The coal seam thickness ranges
from 4 feet to over 9 feet. The Oaktown mines share the same wash plant which is rated at 1,800 tons per hour. The
two mines are connected to a rail loadout that can store two 120 car trains at once and is serviced by the CSX Railroad and Indiana
Railroad. Coal is also transported via truck to customers.
Carlisle Mine (underground) – Assigned
We have 27.3 million controlled, saleable tons
at our Carlisle Mine. The mine is located near the town of Carlisle, Indiana in Sullivan County and became operational in January
2007. The coal is accessed with a slope to a depth of 340'. The coal is mined in the Indiana #V coal seam which is highly volatile
bituminous coal and has been extensively mined by underground and surface methods in the general area. The coal thickness in the
project area is 4' to 7'. The Carlisle Mine is completely developed but was idle for the entirety of 2017.
Ace in the Hole Mine (Ace) (surface)
– Assigned
The Ace mine is near Clay City, Indiana in
Clay County and 42 road miles northeast of the Carlisle Mine. We control .9 million tons of proven coal reserves of which we own
.5 million tons in fee. The two primary seams are low sulfur coal (~2# SO
2
), which make up .8 million of the .9
million tons controlled. Mine development began in late December 2012, and we began shipping coal in late August 2013.
We truck low sulfur coal from Ace to Oaktown to blend with high sulfur coal. Many utilities in the southeastern U.S. have scrubbers
with lower sulfur limits (4.5# 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. We expect
the maximum capacity of Ace to be 0.4 tons annually.
The Ace mine is a multi-seam open pit strip
mine. The majority of the seams are sold raw, but some of the seams will be washed prior to sales depending on quality. To convert
the tons sold raw, the in-place tonnage is multiplied by a pit recovery of 94% based on seam thickness. To convert the tons sold
washed, the in-place tonnage is multiplied by a pit recovery based on seam thickness then reduced by the projected wash plant recovery
of 72%.
Bulldog Reserves (underground) –
Unassigned
We have leased roughly 19,300 acres in Vermilion
County, Illinois near the village of Allerton. Based on our reserve estimates we currently control 35.8 million tons
of coal. A considerable amount of our leased acres has yet to receive any exploratory drilling.
In October 2017, we entered into an agreement
to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase
the property for eight years. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine
application, along with modifications, was acceptable. The permit will be issued upon submittal of a fee and bond which is required
to be submitted within 12 months of the notification.
Full-scale mine development will not commence
until we have a sales commitment. We estimate the costs to develop this mine to be $150 million at full capacity of 3.0 million
tons annually.
Unassigned reserves represent coal reserves
that would require new mineshafts, mining equipment, and plant facilities before operations could begin on the property. The primary
reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production
can begin.
Below is a map that shows the locations
of our mines.
Railroad Legend:
CSX
– CSX Railroad
INRD
– Indiana Rail Road
ISRR
– Indiana Southern Railroad
NS
– Norfolk Southern Railway
Mine and Wash Plant Recovery and Capacity
|
|
Mine recovery
|
|
|
Wash plant recovery*
|
|
|
Wash Plant Capacity
(Clean Tons)
|
Oaktown 1
|
|
|
49
|
%
|
|
|
81
|
%
|
|
8.0 million**
|
Oaktown 2
|
|
|
49
|
%
|
|
|
81
|
%
|
|
|
Carlisle
|
|
|
53
|
%
|
|
|
81
|
%
|
|
2.5 million
|
Bulldog
|
|
|
45
|
%
|
|
|
77
|
%
|
|
|
* Does not include out-of-seam material extracted
during the mining process.
** Oaktown 1 and Oaktown 2 share the wash plant.
Liquidity and Capital Resources
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2025 and
|
|
Contractual Obligations (in thousands)
|
|
Total
|
|
|
2018
|
|
|
2019-2021
|
|
|
2022-2024
|
|
|
thereafter
|
|
Long-term debt (matures August, 2019)
|
|
$
|
201,992
|
|
|
$
|
35,000
|
|
|
$
|
166,992
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Future interest obligations
|
|
|
15,700
|
|
|
|
10,100
|
|
|
|
5,600
|
|
|
|
-
|
|
|
|
-
|
|
Reclamation obligations
|
|
|
13,806
|
|
|
|
300
|
|
|
|
5,315
|
|
|
|
3,011
|
|
|
$
|
5,180
|
|
|
|
$
|
231,498
|
|
|
$
|
45,400
|
|
|
$
|
177,907
|
|
|
$
|
3,011
|
|
|
$
|
5,180
|
|
As set forth in our Statement of Cash Flows,
cash provided by operations was $62 million for 2017. This amount was adequate to fund our maintenance capital expenditures
for coal properties of $11.1 million, our debt service requirements of $36.6 million, and our dividend of $4.9 million. Our capex
budget for 2018 is $31 million, of which $16 million is for maintenance capex. Cash from operations for 2018 should again 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. Included in the contractual obligations table are reclamation obligations of
$13.8 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 $25 million to cover ARO.
Capital Expenditures (capex)
For 2017, our capex was $28.6 million allocated
as follows (in millions):
Oaktown – investment
|
|
$
|
10.1
|
|
Oaktown – maintenance capex
|
|
|
11.1
|
|
Princeton Rail Loop
|
|
|
6.3
|
|
Other projects
|
|
|
1.1
|
|
Capex per the Consolidated Statement of Cash Flows
|
|
$
|
28.6
|
|
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 their Annual Report on 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, 2017. This table includes all adjustments, consisting
only of normal recurring adjustments, that we consider necessary for fair presentation of our consolidated operating results for
the quarters presented.
|
|
Dec-31
|
|
|
Sep-30
|
|
|
Jun-30
|
|
|
Mar-31
|
|
|
Dec-31
|
|
|
Sep-30
|
|
|
Jun-30
|
|
|
Mar-31
|
|
|
|
2017
|
|
|
2017
|
|
|
2017
|
|
|
2017
|
|
|
2016
|
|
|
2016
|
|
|
2016
|
|
|
2016
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
68,922
|
|
|
$
|
73,896
|
|
|
$
|
62,829
|
|
|
$
|
62,555
|
|
|
$
|
71,495
|
|
|
$
|
65,360
|
|
|
$
|
66,274
|
|
|
$
|
75,795
|
|
Equity income (loss) in equity method investments
|
|
|
(62
|
)
|
|
|
169
|
|
|
|
27
|
|
|
|
231
|
|
|
|
(1,130
|
)
|
|
|
(80
|
)
|
|
|
174
|
|
|
|
(400
|
)
|
Other
|
|
|
440
|
|
|
|
403
|
|
|
|
1,456
|
|
|
|
767
|
|
|
|
869
|
|
|
|
487
|
|
|
|
2,116
|
|
|
|
490
|
|
Total revenue
|
|
$
|
69,300
|
|
|
$
|
74,468
|
|
|
$
|
64,312
|
|
|
$
|
63,553
|
|
|
$
|
71,234
|
|
|
$
|
65,767
|
|
|
$
|
68,564
|
|
|
$
|
75,885
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
52,025
|
|
|
|
54,354
|
|
|
|
44,079
|
|
|
|
39,692
|
|
|
|
50,663
|
|
|
|
46,940
|
|
|
|
45,397
|
|
|
|
49,777
|
|
DD&A
|
|
|
9,962
|
|
|
|
9,729
|
|
|
|
9,101
|
|
|
|
9,703
|
|
|
|
9,385
|
|
|
|
7,942
|
|
|
|
9,056
|
|
|
|
9,182
|
|
ARO accretion
|
|
|
221
|
|
|
|
219
|
|
|
|
214
|
|
|
|
207
|
|
|
|
265
|
|
|
|
260
|
|
|
|
255
|
|
|
|
249
|
|
Coal exploration costs
|
|
|
288
|
|
|
|
152
|
|
|
|
275
|
|
|
|
139
|
|
|
|
505
|
|
|
|
354
|
|
|
|
395
|
|
|
|
419
|
|
SG&A
|
|
|
2,883
|
|
|
|
2,859
|
|
|
|
6,578
|
|
|
|
2,658
|
|
|
|
2,444
|
|
|
|
2,585
|
|
|
|
2,729
|
|
|
|
2,762
|
|
Interest
|
|
|
2,751
|
|
|
|
3,229
|
|
|
|
3,342
|
|
|
|
3,091
|
|
|
|
2,148
|
|
|
|
2,601
|
|
|
|
4,497
|
|
|
|
5,596
|
|
Asset impairment
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
16,560
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total cost and expenses
|
|
|
68,130
|
|
|
|
70,542
|
|
|
|
63,589
|
|
|
|
55,490
|
|
|
|
81,970
|
|
|
|
60,682
|
|
|
|
62,329
|
|
|
|
67,985
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) before income taxes
|
|
|
1,170
|
|
|
|
3,926
|
|
|
|
723
|
|
|
|
8,063
|
|
|
|
(10,736
|
)
|
|
|
5,085
|
|
|
|
6,235
|
|
|
|
7,900
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(1,590
|
)
|
|
|
(2,532
|
)
|
|
|
1,357
|
|
|
|
17
|
|
|
|
103
|
|
|
|
(270
|
)
|
|
|
(768
|
)
|
|
|
768
|
|
Deferred
|
|
|
(18,597
|
)
|
|
|
2,542
|
|
|
|
(1,023
|
)
|
|
|
632
|
|
|
|
(7,012
|
)
|
|
|
1,033
|
|
|
|
1,150
|
|
|
|
970
|
|
Total income taxes
|
|
|
(20,187
|
)
|
|
|
10
|
|
|
|
334
|
|
|
|
649
|
|
|
|
(6,909
|
)
|
|
|
763
|
|
|
|
382
|
|
|
|
1,738
|
|
Net income (loss)
|
|
|
21,357
|
|
|
|
3,916
|
|
|
|
389
|
|
|
|
7,414
|
|
|
|
(3,827
|
)
|
|
|
4,322
|
|
|
|
5,853
|
|
|
|
6,162
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
0.69
|
|
|
$
|
0.13
|
|
|
$
|
0.01
|
|
|
$
|
0.25
|
|
|
$
|
(0.13
|
)
|
|
$
|
0.14
|
|
|
$
|
0.19
|
|
|
$
|
0.21
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
29,830
|
|
|
|
29,774
|
|
|
|
29,503
|
|
|
|
29,413
|
|
|
|
29,287
|
|
|
|
29,252
|
|
|
|
29,251
|
|
|
|
29,251
|
|
Oaktown’s operating costs were $27.59/ton
and $30.44/ton for the year and quarter ended December 31, 2017, respectively. We expect Oaktown’s costs to range from $28
to $30 for 2018. For 2018, we expect our SG&A to be $11 million annually and costs associated with the Prosperity and Carlisle
mines to be $6 million annually (reflected in operating costs and expenses).
Quarterly coal sales and cost data follow (in
000’s, except for per ton data and wash plant recovery percentage):
|
|
1
st
2017
|
|
|
2
nd
2017
|
|
|
3
rd
2017
|
|
|
4
th
2017
|
|
|
T4Qs
|
|
Tons produced
|
|
|
1,917
|
|
|
|
1,647
|
|
|
|
1,487
|
|
|
|
1,561
|
|
|
|
6,612
|
|
Tons sold
|
|
|
1,555
|
|
|
|
1,548
|
|
|
|
1,786
|
|
|
|
1,685
|
|
|
|
6,574
|
|
Coal sales
|
|
$
|
62,555
|
|
|
$
|
62,829
|
|
|
$
|
73,896
|
|
|
$
|
68,922
|
|
|
$
|
268,202
|
|
Average price/ton
|
|
$
|
40.23
|
|
|
$
|
40.59
|
|
|
$
|
41.38
|
|
|
$
|
40.90
|
|
|
$
|
40.80
|
|
Wash plant recovery in %
|
|
|
71
|
%
|
|
|
69
|
%
|
|
|
70
|
%
|
|
|
68
|
%
|
|
|
|
|
Operating costs
|
|
$
|
39,692
|
|
|
$
|
44,079
|
|
|
$
|
54,354
|
|
|
$
|
52,025
|
|
|
$
|
190,150
|
|
Average cost/ton
|
|
$
|
25.53
|
|
|
$
|
28.47
|
|
|
$
|
30.43
|
|
|
$
|
30.88
|
|
|
$
|
28.92
|
|
Margin
|
|
$
|
22,863
|
|
|
$
|
18,750
|
|
|
$
|
19,542
|
|
|
$
|
16,897
|
|
|
$
|
78,052
|
|
Margin/ton
|
|
$
|
14.70
|
|
|
$
|
12.11
|
|
|
$
|
10.94
|
|
|
$
|
10.03
|
|
|
$
|
11.87
|
|
Capex
|
|
$
|
5,144
|
|
|
$
|
6,711
|
|
|
$
|
9,473
|
|
|
$
|
7,294
|
|
|
$
|
28,622
|
|
Maintenance capex
|
|
$
|
2,887
|
|
|
$
|
3,032
|
|
|
$
|
2,961
|
|
|
$
|
2,520
|
|
|
$
|
11,400
|
|
Maintenance capex/ton
|
|
$
|
0.54
|
|
|
$
|
4.25
|
|
|
$
|
2.52
|
|
|
$
|
1.50
|
|
|
$
|
1.73
|
|
|
|
1
st
2016
|
|
|
2
nd
2016
|
|
|
3
rd
2016
|
|
|
4
th
2016
|
|
|
T4Qs
|
|
Tons produced
|
|
|
1,524
|
|
|
|
1,448
|
|
|
|
1,501
|
|
|
|
1,640
|
|
|
|
6,113
|
|
Tons sold
|
|
|
1,629
|
|
|
|
1,464
|
|
|
|
1,485
|
|
|
|
1,739
|
|
|
|
6,317
|
|
Coal sales
|
|
$
|
75,795
|
|
|
$
|
66,274
|
|
|
$
|
65,360
|
|
|
$
|
71,495
|
|
|
$
|
278,924
|
|
Average price/ton
|
|
$
|
46.53
|
|
|
$
|
45.27
|
|
|
$
|
44.01
|
|
|
$
|
41.11
|
|
|
$
|
44.15
|
|
Wash plant recovery in %
|
|
|
65
|
%
|
|
|
63
|
%
|
|
|
68
|
%
|
|
|
67
|
%
|
|
|
|
|
Operating costs
|
|
$
|
49,777
|
|
|
$
|
45,397
|
|
|
$
|
46,940
|
|
|
$
|
50,663
|
|
|
$
|
192,777
|
|
Average cost/ton
|
|
$
|
30.56
|
|
|
$
|
31.01
|
|
|
$
|
31.61
|
|
|
$
|
29.13
|
|
|
$
|
30.52
|
|
Margin
|
|
$
|
26,018
|
|
|
$
|
20,877
|
|
|
$
|
18,420
|
|
|
$
|
20,832
|
|
|
$
|
86,147
|
|
Margin/ton
|
|
$
|
15.97
|
|
|
$
|
14.26
|
|
|
$
|
12.40
|
|
|
$
|
11.98
|
|
|
$
|
13.64
|
|
Capex
|
|
$
|
6,053
|
|
|
$
|
1,822
|
|
|
$
|
3,935
|
|
|
$
|
8,022
|
|
|
$
|
19,832
|
|
Maintenance capex
|
|
$
|
2,984
|
|
|
$
|
904
|
|
|
$
|
1,709
|
|
|
$
|
5,301
|
|
|
$
|
10,898
|
|
Maintenance capex/ton
|
|
$
|
1.83
|
|
|
$
|
0.62
|
|
|
$
|
1.15
|
|
|
$
|
3.05
|
|
|
$
|
1.73
|
|
2017 v. 2016
For 2017, we sold 6,574,000 tons at an average
price of $40.80/ton. For 2016, we sold 6,317,000 tons at an average price of $44.15/ton. The decrease in average price per ton
is the result of our contract mix, expiration of contracts, and acquisition of other contracts.
Operating costs and expenses averaged $28.92/ton
($27.59/ton at our operating Oaktown mines) in 2017 compared to $30.52/ton ($28.02/ton at our operating Oaktown mines) in 2016. The
reduction in cost was due to two primary factors. First, we made a conscious effort to increase production in the first half of
the year in anticipation of stronger market demand. Second, we added new haulage equipment to some of the units at the Oaktown
mines creating production efficiencies of up to 30% to those units. Both of these factors combined led to an 8% increase in production.
In Q4 2017, we also opened a new elevator at Oaktown 1 which reduces miner travel time, and we acquired additional haulage equipment
which will continue to maintain our low-cost structure.
Our Sunrise Coal employees totaled 736 at December
31, 2017 compared to 742 at December 31, 2016.
SG&A costs increased in 2017 by $4.5 million
due primarily to a stock bonus of $3.8 million awarded to executives as reported in our 8-K filed May 17, 2017, increased RSU amortization
and employee pay increases in 2017.
2016 v. 2015
For 2016, we sold 6,317,000 tons at an average
price of $44.15/ton. For 2015, we sold 7,447,000 tons at an average price of $45.59/ton.
Operating costs and expenses averaged $30.52/ton
in 2016 compared to $31.95 in 2015. Our Sunrise Coal employees totaled 742 at December 31, 2016, compared to 740 at
December 31, 2015.
SG&A costs were higher in 2015 due to amortization
of RSUs and accruals of bonuses related to our Vectren Fuels acquisition in 2014. SG&A as a percentage of coal revenue
remained consistent at 3.8% in 2016 and 3.7% in 2015.
We incurred an asset impairment of $16.6 million
due to our decision to seal the north portal of the Carlisle mine. We determined that the North end had deteriorated to the point
that it could no longer be safely and profitably mined.
At the beginning of 2016, we changed from the
straight-line method to the units-of-production method in computing the depreciation for continuous miners. This change in estimate
reduced our DD&A expense for the year ended December 31, 2016, by $2.6 million. This change better reflects the usage of our
continuous miners considering our reduced production in 2016. Due to idle equipment at Carlisle, we stopped depreciating specific
underground equipment resulting in a $4.4 million reduction in depreciation for the year ended December 31, 2016.
Current Projects
Princeton Rail Loop
Construction began in the fourth quarter of
2017 on the Princeton Loop, a truck to rail coal loading facility that will be located 6 miles west of Princeton, IN, on Highway
64 and 37 miles southwest of our Oaktown mining facility. The facility will include the ability to unload trucks, blend coals,
load 135 car unit trains in four hours and store over 4.0 million tons of coal. The new facility will primarily serve utility
coal plants served by the Norfolk Southern Railway Company once the rail facility is completed in the spring of 2018. The
rail loop will provide access to new markets and customers.
Hourglass Sands
In February 2018, we formed and made an initial
investment of $4 million in Hourglass Sands, LLC, a frac sand mining company in the State of Colorado. We own 100% of the Class
A units and will account for Hourglass Sands LLC as a wholly owned subsidiary of Hallador Energy Company. Class A units are entitled
to 100% of profit until our capital investment and interest is returned, then 90% of profits are allocated to Class A Units with
the remainder to Class B units. A Yorktown company associated with one of our directors also invested $4 million for a royalty
interest in the sand project.
We currently control a permitted sand reserve
near Colorado Springs. We are negotiating to have a third party wash our sand and expect to truck test shipments to customers in
the DJ Basin this summer. We believe we control the only permitted frac sand mine in the State of Colorado. We do not anticipate
Hourglass Sands, LLC to be profitable in 2018, but are excited about its growth potential in future years.
MSHA Reimbursements
Some of our legacy coal contracts allow us
to pass on to our customers certain costs incurred resulting from changes in costs to comply with mandates issued by MSHA or other
government agencies. We do not recognize any revenue until our customers have notified us that they accept the charges.
We submitted our incurred costs for 2012 in
June 2015 and received $1.75 million from one of our customers in June 2016. We received an additional payment of $1.25 million
in Q2 2017 for 2012 costs. We also received payments in 2017 from several customers for smaller regulation changes that went into
effect in 2016. As stated above we do not record such reimbursements as revenue until they have been agreed to by our customers.
Incurred costs for 2013 – 2017 will be
submitted in 2018. 2013 costs are expected to be between $2.0 million and $2.7 million. Such reimbursable costs for 2014 through
2017 are not expected to be material.
Income Taxes
On December 22, 2017, the U.S. government
enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (Tax Act). The Tax Act reduces the corporate
tax rate to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 requires the effect of a change in tax laws or rates
to be recognized as of the date of enactment, we are required to adjust deferred tax assets and liabilities as of December 22,
2017. Accordingly, we have recorded a deferred income tax benefit of $16.4 million for the year ended December 31, 2017.
Our effective tax rate (ETR) for 2017 was
(138)% compared to (48)% for 2016 and 27% for 2015. The negative ETR in 2017 is due primarily to the effects of the Tax Act adjustment
to our deferred taxes and prior year tax return reconciliation which were all recorded discretely for the year ended December 31,
2017. The negative ETR in 2016 is due to the combination of the reduction in book income before taxes because of the asset
impairment expense, permanent tax benefits of statutory depletion in excess of tax basis in the mining properties, the captive
insurance company effects, and stock based compensation expense. The tax rate for the years ended December 31, 2017 and 2016 are
not predictive of future tax rates due to the deferred income tax benefit of the Tax Act. The tax rate would have been 9% without
the effects of the deferred income tax benefit of the Tax Act and the prior year tax return reconciliation. Historically, our actual
effective tax rates have been lower than the statutory effective rate primarily due to the benefit received from statutory depletion
allowances. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income
taxes.
Critical Accounting Estimates
We believe that the estimates of our coal reserves,
our business acquisitions, our interest rate swaps, 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 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 will 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 and
Supplementary Data – Note 1. Summary of Significant Accounting Policies” for a discussion of new accounting standards.
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK.
Substantially all our business is conducted
in Indiana, so we have no foreign exchange currency risk.
We have exposure to price risk for supplies
that are used directly or indirectly in the normal course of coal production such as steel, electricity and other supplies. We
manage our risk for these items through strategic sourcing contracts for normal quantities required by our operations. We
do not utilize any commodity price-hedges or other derivatives related to these risks. The Trump administration recently announced
that they would like to assess tariffs on steel imports in the future which would add to this risk.
Borrowings under our credit agreement are at
variable rates and, as a result, we have interest rate exposure. Historically, our earnings have not been materially affected by
changes in interest rates. As disclosed in Note 3 to our consolidated financial statements we entered into swap agreements
to fix the LIBOR component of the interest rate to achieve an effective fixed rate of no greater than 5% on the original term loan
balance and on $100 million of the revolver. Quarterly, we mark-to-market the value of the swaps. For 2017, the change in value
was $723,000 and not considered material. As short-term interest rates rise (especially the two-year U.S. treasury note) the value
of the swap increases and as they fall the value decreases.
We expect to continue selling a significant
portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply
agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments
required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal
supply agreements result from competitive bidding and extensive negotiations with customers.
ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
To the Shareholders and Board of Directors
Hallador Energy Company
Denver, Colorado
OPINIONS ON THE FINANCIAL STATEMENTS
AND INTERNAL CONTROL OVER FINANCIAL REPORTING
We have audited the accompanying consolidated
balance sheets of Hallador Energy Company (the "Company") as of December 31, 2017 and 2016, and the related consolidated
statements of income, comprehensive income, stockholders' equity, and cash flows, for each year in the three-year period ended
December 31, 2017, and the related notes (collectively referred to as the "consolidated financial statements"). We have
also audited the Company's internal control over financial reporting as of December 31, 2017, based on the criteria established
in Internal Control - Integrated Framework: (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
("COSO").
In our opinion, the consolidated financial
statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31,
2017 and 2016, and the results of its operations and its cash flows for each year in the three-year period ended December 31, 2017,
in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria
established in Internal Control - Integrated Framework: (2013) issued by COSO.
BASIS FOR OPINIONS
The Company's management is responsible
for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment
of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal
Control over Financial Reporting. Our responsibility is to express an opinion on the Company's consolidated 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 consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial
statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements,
whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a
test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating
the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of
the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding
of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the
design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits 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 consolidated financial statements for external purposes in accordance with generally accepted accounting principles. A company's
internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records
that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements
in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only
in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material
effect on the consolidated financial statements.
Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness
to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree
of compliance with the policies or procedures may deteriorate.
/s/ EKS&H LLLP
|
|
|
|
March 12, 2018
|
|
Denver, Colorado
|
|
We have served as the Company's auditor
since 2003.
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
Consolidated Balance Sheets
As of December 31,
(in thousands, except per share data)
|
|
2017
|
|
|
2016
|
|
ASSETS
|
|
|
|
|
|
|
|
|
Current assets:
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
12,483
|
|
|
$
|
9,788
|
|
Restricted cash (Note 8)
|
|
|
3,811
|
|
|
|
2,817
|
|
Certificates of deposit
|
|
|
1,495
|
|
|
|
7,315
|
|
Marketable securities
|
|
|
1,907
|
|
|
|
1,763
|
|
Accounts receivable
|
|
|
16,762
|
|
|
|
22,307
|
|
Prepaid income taxes
|
|
|
2,899
|
|
|
|
-
|
|
Coal inventory
|
|
|
12,804
|
|
|
|
10,100
|
|
Parts and supply inventory
|
|
|
10,043
|
|
|
|
10,091
|
|
Purchased coal contracts
|
|
|
-
|
|
|
|
8,922
|
|
Prepaid expenses
|
|
|
9,433
|
|
|
|
9,647
|
|
Total current assets
|
|
|
71,637
|
|
|
|
82,750
|
|
Coal properties, at cost:
|
|
|
|
|
|
|
|
|
Land and mineral rights
|
|
|
129,724
|
|
|
|
126,303
|
|
Buildings and equipment
|
|
|
356,911
|
|
|
|
339,999
|
|
Mine development
|
|
|
136,762
|
|
|
|
126,037
|
|
Total coal properties, at cost
|
|
|
623,397
|
|
|
|
592,339
|
|
Less - accumulated DD&A
|
|
|
(203,391
|
)
|
|
|
(169,579
|
)
|
Total coal properties, net
|
|
|
420,006
|
|
|
|
422,760
|
|
Investment in Savoy (Note 11)
|
|
|
8,037
|
|
|
|
7,577
|
|
Investment in Sunrise Energy (Note 11)
|
|
|
3,853
|
|
|
|
4,122
|
|
Other assets (Note 7)
|
|
|
14,660
|
|
|
|
14,114
|
|
Total assets
|
|
$
|
518,193
|
|
|
$
|
531,323
|
|
LIABILITIES AND STOCKHOLDERS' EQUITY
|
|
|
|
|
|
|
|
|
Current liabilities:
|
|
|
|
|
|
|
|
|
Current portion of bank debt, net (Note 3)
|
|
$
|
33,171
|
|
|
$
|
28,796
|
|
Accounts payable and accrued liabilities (Note 14)
|
|
|
21,115
|
|
|
|
19,918
|
|
Total current liabilities
|
|
|
54,286
|
|
|
|
48,714
|
|
Long-term liabilities:
|
|
|
|
|
|
|
|
|
Bank debt, net (Note 3)
|
|
|
165,773
|
|
|
|
204,944
|
|
Deferred income taxes
|
|
|
28,728
|
|
|
|
45,174
|
|
Asset retirement obligations (ARO)
|
|
|
13,506
|
|
|
|
13,115
|
|
Other
|
|
|
6,577
|
|
|
|
2,486
|
|
Total long-term liabilities
|
|
|
214,584
|
|
|
|
265,719
|
|
Total liabilities
|
|
|
268,870
|
|
|
|
314,433
|
|
Stockholders' equity:
|
|
|
|
|
|
|
|
|
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
|
|
|
-
|
|
|
|
-
|
|
Common stock, $.01 par value, 100,000 shares authorized; 29,955 and 29,413 shares outstanding, respectively
|
|
|
299
|
|
|
|
294
|
|
Additional paid-in capital
|
|
|
97,873
|
|
|
|
93,816
|
|
Retained earnings
|
|
|
150,236
|
|
|
|
122,052
|
|
Accumulated other comprehensive income
|
|
|
915
|
|
|
|
728
|
|
Total stockholders’ equity
|
|
|
249,323
|
|
|
|
216,890
|
|
Total liabilities and stockholders’ equity
|
|
$
|
518,193
|
|
|
$
|
531,323
|
|
See accompanying notes.
Hallador Energy Company
Consolidated Statements of Comprehensive
Income
For the years ended December 31,
(in thousands, expect per share data)
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
Coal sales
|
|
$
|
268,202
|
|
|
$
|
278,924
|
|
|
$
|
339,490
|
|
Equity income (loss) - Savoy
|
|
|
460
|
|
|
|
(1,187
|
)
|
|
|
(1,532
|
)
|
Equity income (loss) - Sunrise Energy
|
|
|
(95
|
)
|
|
|
(249
|
)
|
|
|
(74
|
)
|
Other (Note 7)
|
|
|
3,066
|
|
|
|
3,962
|
|
|
|
2,236
|
|
Total revenue
|
|
|
271,633
|
|
|
|
281,450
|
|
|
|
340,120
|
|
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs and expenses
|
|
|
190,150
|
|
|
|
192,777
|
|
|
|
237,897
|
|
DD&A
|
|
|
38,495
|
|
|
|
35,565
|
|
|
|
43,942
|
|
ARO accretion
|
|
|
861
|
|
|
|
1,029
|
|
|
|
498
|
|
Coal exploration costs
|
|
|
854
|
|
|
|
1,673
|
|
|
|
2,039
|
|
SG&A
|
|
|
14,978
|
|
|
|
10,520
|
|
|
|
12,617
|
|
Interest
(1)
|
|
|
12,413
|
|
|
|
14,842
|
|
|
|
15,557
|
|
Asset impairment (Note 2)
|
|
|
-
|
|
|
|
16,560
|
|
|
|
-
|
|
Total costs and expenses
|
|
|
257,751
|
|
|
|
272,966
|
|
|
|
312,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
13,882
|
|
|
|
8,484
|
|
|
|
27,570
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less income tax expense (benefit)
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
(2,748
|
)
|
|
|
(167
|
)
|
|
|
(14
|
)
|
Deferred
|
|
|
(16,446
|
)
|
|
|
(3,859
|
)
|
|
|
7,452
|
|
Total income tax expense (benefit)
|
|
|
(19,194
|
)
|
|
|
(4,026
|
)
|
|
|
7,438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income *
|
|
$
|
33,076
|
|
|
$
|
12,510
|
|
|
$
|
20,132
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share (Note 9):
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
1.08
|
|
|
$
|
0.42
|
|
|
$
|
0.68
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
|
29,661
|
|
|
|
29,260
|
|
|
|
29,031
|
|
*There is no material difference between
net income and comprehensive income.
|
(1)
|
Included in interest expense is the change in the estimated fair value
of our interest rate swaps. Such amounts were $(723), $(637) and $159 for 2017, 2016 and 2015, respectively.
|
See accompanying notes.
Hallador Energy Company
Consolidated Statement of Cash Flows
For the years ended December 31,
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
33,076
|
|
|
$
|
12,510
|
|
|
$
|
20,132
|
|
Deferred income taxes
|
|
|
(16,446
|
)
|
|
|
(3,859
|
)
|
|
|
7,452
|
|
Equity (income) loss – Savoy and Sunrise Energy
|
|
|
(365
|
)
|
|
|
1,436
|
|
|
|
1,606
|
|
Cash distributions - Savoy and Sunrise Energy
|
|
|
175
|
|
|
|
3,977
|
|
|
|
-
|
|
DD&A
|
|
|
38,495
|
|
|
|
35,565
|
|
|
|
43,942
|
|
Asset impairment
|
|
|
-
|
|
|
|
16,560
|
|
|
|
-
|
|
Loss on sale of assets
|
|
|
45
|
|
|
|
197
|
|
|
|
-
|
|
Change in fair value of interest rate swaps
|
|
|
(723
|
)
|
|
|
(637
|
)
|
|
|
159
|
|
Amortization and write off of deferred financing costs
|
|
|
1,829
|
|
|
|
2,325
|
|
|
|
1,394
|
|
Amortization of purchased coal contracts
|
|
|
8,922
|
|
|
|
1,593
|
|
|
|
-
|
|
Accretion of ARO
|
|
|
861
|
|
|
|
1,029
|
|
|
|
498
|
|
Stock-based compensation
|
|
|
7,266
|
|
|
|
2,539
|
|
|
|
3,134
|
|
Taxes paid on vesting of RSUs
|
|
|
(3,209
|
)
|
|
|
(1,098
|
)
|
|
|
(1,029
|
)
|
Change in current assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable
|
|
|
5,533
|
|
|
|
(5,632
|
)
|
|
|
10,627
|
|
Coal inventory
|
|
|
(2,704
|
)
|
|
|
4,815
|
|
|
|
4,807
|
|
Parts and supply inventory
|
|
|
48
|
|
|
|
1,164
|
|
|
|
3,664
|
|
Prepaid income taxes
|
|
|
(3,226
|
)
|
|
|
5,312
|
|
|
|
448
|
|
Prepaid expenses
|
|
|
(4,823
|
)
|
|
|
(2,567
|
)
|
|
|
370
|
|
Accounts payable and accrued liabilities
|
|
|
(815
|
)
|
|
|
(11,193
|
)
|
|
|
(1,686
|
)
|
Other
|
|
|
(2,371
|
)
|
|
|
(3,118
|
)
|
|
|
(862
|
)
|
Cash provided by operating activities
|
|
|
61,568
|
|
|
|
60,918
|
|
|
|
94,656
|
|
Investing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures
|
|
|
(28,622
|
)
|
|
|
(19,832
|
)
|
|
|
(31,167
|
)
|
Proceeds from sale of equipment
|
|
|
506
|
|
|
|
-
|
|
|
|
-
|
|
Purchase of Freelandville and Log Creek assets
|
|
|
-
|
|
|
|
(22,358
|
)
|
|
|
-
|
|
Proceeds from maturities of certificates of deposit
|
|
|
5,820
|
|
|
|
-
|
|
|
|
-
|
|
Purchase of certificates of deposit
|
|
|
-
|
|
|
|
(7,315
|
)
|
|
|
-
|
|
Other
|
|
|
-
|
|
|
|
189
|
|
|
|
641
|
|
Cash used in investing activities
|
|
|
(22,296
|
)
|
|
|
(49,316
|
)
|
|
|
(30,526
|
)
|
Financing activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments of bank debt
|
|
|
(36,625
|
)
|
|
|
(34,855
|
)
|
|
|
(56,875
|
)
|
Bank borrowings
|
|
|
-
|
|
|
|
24,000
|
|
|
|
-
|
|
Deferred financing costs
|
|
|
-
|
|
|
|
(2,090
|
)
|
|
|
-
|
|
Proceeds from Bulldog property
|
|
|
4,940
|
|
|
|
-
|
|
|
|
-
|
|
Dividends
|
|
|
(4,892
|
)
|
|
|
(4,799
|
)
|
|
|
(4,794
|
)
|
Cash used in financing activities
|
|
|
(36,577
|
)
|
|
|
(17,744
|
)
|
|
|
(61,669
|
)
|
Increase (decrease) in cash and cash equivalents
|
|
|
2,695
|
|
|
|
(6,142
|
)
|
|
|
2,461
|
|
Cash and cash equivalents, beginning of year
|
|
|
9,788
|
|
|
|
15,930
|
|
|
|
13,469
|
|
Cash and cash equivalents, end of year
|
|
$
|
12,483
|
|
|
$
|
9,788
|
|
|
$
|
15,930
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental cash flow information:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash paid for interest
|
|
$
|
11,663
|
|
|
$
|
12,429
|
|
|
$
|
14,149
|
|
Cash (received) paid for income taxes, net
|
|
|
1,562
|
|
|
|
(5,594
|
)
|
|
|
(956
|
)
|
Capital expenditures included in accounts payable and prepaid expense
|
|
|
7,615
|
|
|
|
(1,616
|
)
|
|
|
804
|
|
See accompanying notes.
Hallador Energy Company
Consolidated Statement of Stockholders’
Equity
(in thousands)
|
|
Shares
|
|
|
Common
Stock
|
|
|
Additional
Paid-in
Capital
|
|
|
Retained
Earnings
|
|
|
AOCI*
|
|
|
Total
|
|
Balance January 1, 2015
|
|
|
28,962
|
|
|
$
|
289
|
|
|
$
|
90,218
|
|
|
$
|
99,003
|
|
|
$
|
365
|
|
|
$
|
189,875
|
|
Stock-based compensation
|
|
|
14
|
|
|
|
-
|
|
|
|
3,134
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3,134
|
|
Stock issued on vesting of RSUs
|
|
|
411
|
|
|
|
3
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
3
|
|
Taxes paid on vesting of RSUs
|
|
|
(136
|
)
|
|
|
-
|
|
|
|
(1,029
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,029
|
)
|
Dividends
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,794
|
)
|
|
|
-
|
|
|
|
(4,794
|
)
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
20,132
|
|
|
|
-
|
|
|
|
20,132
|
|
Other
|
|
|
-
|
|
|
|
-
|
|
|
|
(48
|
)
|
|
|
-
|
|
|
|
(453
|
)
|
|
|
(501
|
)
|
Balance, December 31, 2015
|
|
|
29,251
|
|
|
|
292
|
|
|
|
92,275
|
|
|
|
114,341
|
|
|
|
(88
|
)
|
|
|
206,820
|
|
Stock-based compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
2,539
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,539
|
|
Stock issued on vesting of RSUs
|
|
|
272
|
|
|
|
2
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2
|
|
Taxes paid on vesting of RSUs
|
|
|
(126
|
)
|
|
|
-
|
|
|
|
(1,098
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(1,098
|
)
|
Dividends
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,799
|
)
|
|
|
-
|
|
|
|
(4,799
|
)
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
12,510
|
|
|
|
-
|
|
|
|
12,510
|
|
Other
|
|
|
16
|
|
|
|
-
|
|
|
|
100
|
|
|
|
-
|
|
|
|
816
|
|
|
|
916
|
|
Balance December 31, 2016
|
|
|
29,413
|
|
|
|
294
|
|
|
|
93,816
|
|
|
|
122,052
|
|
|
|
728
|
|
|
|
216,890
|
|
Stock-based compensation
|
|
|
-
|
|
|
|
-
|
|
|
|
7,266
|
|
|
|
-
|
|
|
|
-
|
|
|
|
7,266
|
|
Stock issued on vesting of RSUs
|
|
|
991
|
|
|
|
5
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
5
|
|
Taxes paid on vesting of RSUs
|
|
|
(449
|
)
|
|
|
-
|
|
|
|
(3,209
|
)
|
|
|
-
|
|
|
|
-
|
|
|
|
(3,209
|
)
|
Dividends
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
(4,892
|
)
|
|
|
-
|
|
|
|
(4,892
|
)
|
Net income
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
33,076
|
|
|
|
-
|
|
|
|
33,076
|
|
Other
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
187
|
|
|
|
187
|
|
Balance, December 31, 2017
|
|
|
29,955
|
|
|
$
|
299
|
|
|
$
|
97,873
|
|
|
$
|
150,236
|
|
|
$
|
915
|
|
|
$
|
249,323
|
|
*Accumulated Other Comprehensive Income
(loss)
See accompanying notes.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
|
(1)
|
Summary of Significant Accounting Policies
|
Basis of Presentation
and Consolidation
The consolidated financial statements include
the accounts of Hallador Energy Company (the Company) and its wholly owned subsidiary Sunrise Coal, LLC (Sunrise) and Sunrise’s
wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. We are engaged in the
production of steam coal from mines located in western Indiana. We own a 50% interest in Sunrise Energy, LLC, a private entity
engaged in natural gas operations in the same vicinity as the Carlisle Mine. We also own 30.6% equity interest in Savoy Energy,
L.P., a private oil and gas company that has operations in Michigan. We have reached an agreement for Savoy to redeem our entire
partnership interest for $8 million, which we expect to finalize in mid-March 2018. Our net after commissions paid will be $7.5
million.
Reclassification
To maintain consistency and comparability,
certain amounts in the financial statements have been reclassified to conform to current year presentation.
Inventories
Coal and supplies inventories are valued at
the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs (including depreciation thereto)
and overhead.
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.
Coal Properties
Coal 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, coal
properties are depreciated using the units-of-production method over the estimated recoverable reserves. Most surface and underground
mining equipment is depreciated using estimated useful lives ranging from three to twenty-five years. At the beginning of 2016,
we changed from the straight-line method to the units-of-production method in computing the depreciation for continuous miners.
This change in estimate reduced our DD&A expense for the year ended December 31, 2016, by $2.6 million. Due to idle equipment
at Carlisle, we stopped depreciating specific underground equipment resulting in a $4.4 million reduction in depreciation for the
year ending December 31, 2016.
If facts and circumstances suggest that a long-lived
asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates that the carrying value of the
asset will not be recoverable through estimated undiscounted future net cash flows related to the asset over its remaining life,
then an impairment loss is recognized by reducing the carrying value of the asset to its estimated fair value. See Note 2 for further
discussion of impairments.
Mine Development
Costs of developing new coal mines, including
asset retirement obligation assets, or significantly expanding the capacity of existing mines, are capitalized and amortized using
the units-of-production method over estimated recoverable reserves.
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 $25 million to cover ARO.
The table below (in thousands) reflects the
changes to our ARO:
|
|
2017
|
|
|
2016
|
|
Balance, beginning of year
|
|
$
|
13,260
|
|
|
$
|
12,231
|
|
Accretion
|
|
|
861
|
|
|
|
1,029
|
|
Revisions
|
|
|
(112
|
)
|
|
|
-
|
|
Payments
|
|
|
(203
|
)
|
|
|
-
|
|
Balance, end of year
|
|
|
13,806
|
|
|
|
13,260
|
|
Less current portion
|
|
|
(300
|
)
|
|
|
(145
|
)
|
Long-term balance, end of year
|
|
$
|
13,506
|
|
|
$
|
13,115
|
|
Statement of Cash
Flows
Cash equivalents include investments with maturities,
when purchased, of three months or less.
Income Taxes
Income taxes are provided based on the liability
method of accounting. The provision for income taxes is based on pretax financial income. Deferred tax assets and liabilities
are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting and
principally relate to differences in the tax basis of assets and liabilities and their reported amounts, using enacted tax rates
in effect for the year in which differences are expected to reverse.
Net Income 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) fair value estimates relating
to business combinations, (ii) deferred income tax accounts, (iii) coal reserves, (iv) depreciation, depletion, and amortization,
and (v) estimates used in our impairment analysis.
Business Combinations
We account for business combinations using
the purchase method of accounting. The purchase method requires us to determine the fair value of all acquired assets, including
identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable
net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed
requires management's judgment and the utilization of independent valuation experts, and often involves the use of significant
estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives,
among other items.
Revenue Recognition
We recognize revenue from coal sales at the
time title and risk of loss passes to the customer at contracted amounts and amounts are deemed collectible. Some coal supply agreements
provide for price adjustments based on variations in quality characteristics of the coal shipped and are recorded in the period
of shipment. As discussed below, we do not expect the new revenue recognition standard introduced by ASU 2014-09, Revenue from
Contracts with Customers (ASU 2014-09) will result in a material change to our pattern of revenue recognition when it becomes effective.
Long-term Contracts
As of December 31, 2017, we are committed to
supplying our customers a maximum of 26.1 million tons of coal through 2024 of which 13.5 million tons are priced.
For 2017, we derived 92% of our coal sales
from five customers, each representing at least 10% of our coal sales. 83% of our accounts receivable were from four of these customers,
each representing more than 10% of the December 31, 2017 balance.
For 2016, we derived 90% of our coal sales
from five customers each representing at least 10% of our coal sales. 78% of our accounts receivable were from four of these customers,
each representing more than 10% of the December 31, 2016 balance.
For 2015, we derived 82% of our coal sales
from four customers, each representing at least 10% of our coal sales.
We are paid every two to four weeks and do
not expect any credit losses.
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 July 2015, the FASB issued ASU 2015-11, Inventory
(Topic 330): Simplifying the Measurement of Inventory (ASU 2015-11). ASU 2015-11 simplifies the subsequent measurement
of inventory. It replaces the current lower of cost or market test with the lower of cost or net realizable value test. Net
realizable value is defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs
of completion, disposal, and transportation. The new standard was applied prospectively and effective for annual reporting
periods beginning after December 15, 2016 and interim periods within those annual periods. The adoption of ASU 2015-11
did not have a material impact on our consolidated financial statements.
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. We are currently in the process of accumulating all
contractual lease arrangements in order to determine the impact on our financial statements and do not believe we have significant
amounts of off- balance sheet leases; accordingly, we do not expect the adoption of ASU 2016-02 to have a material impact on our
consolidated financial statements. We continue to monitor closely the activities of the FASB and various non-authoritative groups
with respect to implementation issues that could affect our evaluation.
In May 2014, the FASB issued ASU No. 2014-09,
“Revenue from Contracts with Customers.” ASU 2014-09 is a comprehensive revenue recognition standard that will supersede
nearly all existing revenue recognition guidance under current U.S. GAAP and replace it with a principle based approach for determining
revenue recognition. ASU 2014-09 will require that companies recognize revenue based on the value of transferred goods or services
as they occur in the contract. The ASU also will require additional disclosure about the nature, amount, timing and uncertainty
of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets
recognized from costs incurred to obtain or fulfill a contract. ASU 2014-09 is effective for interim and annual periods beginning
after December 15, 2017. We have adopted the new standard as of January 1, 2018. Entities will be able to transition to the standard
either retrospectively or as a cumulative-effect adjustment as of the date of adoption.
Our primary source of revenue is from the sale
of coal through both short-term and long-term contracts with utility companies whereby revenue is currently recognized when risk
of loss has passed to the customer. Under the new standard, an entity should recognize revenue to depict the transfer of promised
goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange
for those goods or services. As part of our assessment process, we applied the five-step analysis outlined in the new standard
to certain contracts representative of the majority of our coal sales contracts and determined that our pattern of recognition
is consistent between the new and existing standards. We also reviewed the expanded disclosure requirements under the new standard
and have determined the additional information to be disclosed. In addition, we reviewed our business processes, systems and internal
controls over financial reporting to support the new recognition and disclosure requirements under the new standard. Upon adoption
of this new standard, we believe that the timing of revenue recognition related to our coal sales will remain consistent with our
current practice, but expanded disclosures including presenting revenue for all periods presented and expected revenue by year
for performance obligations that are unsatisfied or partially unsatisfied as of the date of presentation will be required. We have
elected the modified retrospective transition method which allows a cumulative effect adjustment to equity as of the date of adoption.
Because we do not anticipate a change in our pattern of revenue recognition, we anticipate that the transition will not have a
material impact on our consolidated financial statements. Although we don’t consider it material, one source of variable
consideration we receive relates to reimbursement from certain customers for expenses incurred for new government impositions adopted,
which we may recognize sooner than our current recognition practice.
In November 2016, the FASB issued guidance
regarding the presentation of restricted cash in the statement of cash flows (ASU 2016-18). This update is effective for annual
reporting periods beginning after December 15, 2017, and early adoption is permitted. We have adopted the new standard as of January
1, 2018.
In January 2017, the FASB issued new guidance
to assist in determining if a set of assets and activities being acquired or sold is a business (ASU 2017-01). It also provided
a framework to assist entities in evaluating whether both an input and a substantive process are present, which at a minimum, must
be present to be considered a business. This update is effective for annual reporting periods beginning after December 15, 2017,
and early adoption is permitted in most circumstances. The standard does not have an impact to the Company’s historical recognition
of asset acquisitions and business combinations. However, we expect there will be an impact to how the Company accounts for assets
acquired in the future.
Subsequent Events
In January 2018, we declared a dividend of
$.04 per share to shareholders of record as of January 31, 2018. The dividend was paid on February 16, 2018.
In February 2018, we formed and made an
initial investment of $4 million in Hourglass Sands, LLC, a frac sand mining company in the State of Colorado. We own 100%
of the Class A units and will account for Hourglass Sands LLC as a wholly owned subsidiary of Hallador Energy Company. Class
A units are entitled to 100% of profit until our capital investment and interest is returned, then 90% of profits are allocated
to Class A Units with the remainder to Class B units. A Yorktown company associated with one of our directors also invested
$4 million for a royalty interest in the sand project.
We currently control a permitted sand reserve
near Colorado Springs. We are negotiating to have a third party wash our sand and expect to truck test shipments to customers
in the DJ Basin this summer. We believe we control the only permitted frac sand mine in the State of Colorado. We do
not anticipate Hourglass Sands, LLC to be profitable in 2018, but are excited about its growth potential in future years.
We
have reached an agreement for Savoy Energy L.P. to redeem our entire partnership interest for $8 million, which we expect to finalize
in mid-March 2018. Our net after commissions paid will be $7.5 million.
|
(2)
|
Asset Impairment Review
|
Carlisle Mine
In December 2016, the deterioration of the
North End of the Carlisle Mine (the North End), coupled with lower coal prices led us to determine that the North End could no
longer be mined safely and profitably. The sealing of the North End was completed in March 2017. In connection therewith, we identified
specific assets totaling $16.6 million ($15.1 million of property and equipment and $1.5 million of advanced royalties) that were
written off in 2016.
With the Carlisle Mine remaining in hot idle
status, we conducted a review of the Carlisle Mine assets as of December 31, 2017, based on estimated future net cash flows, and
determined that no further impairment was necessary.
The Carlisle Mine assets had an aggregate net
carrying value of $110 million at December 31, 2017. If in future periods we reduce our estimate of the future net cash
flows attributable to the Carlisle Mine, it may result in future impairment of such assets and such charges could be significant.
Bulldog Reserves
In October 2017, we entered into an agreement
to sell land associated with the Bulldog Mine for $4.9 million. As part of the transaction, we will hold the rights to repurchase
the property for 8 years. Because of the likelihood of exercising the repurchase option, we are accounting for the sale as a financing
transaction. The Bulldog Mine assets had an aggregate net carrying value of $15 million at December 31, 2017. Also in October 2017,
the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable.
The permit will be issued upon submittal of a fee and bond which are required within 12 months of the notification. We have determined
that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.
On March 18, 2016, we executed an amendment
to our credit agreement with PNC, as administrative agent for our lenders, for the primary purpose of increasing liquidity and
maintaining compliance through the maturity of the agreement in August 2019. The revolver was reduced from $250 million to
$200 million, and the $175 million term loan remained the same. Our debt at December 31, 2017, was $202 million (term-$71 million,
revolver-$131 million). As of December 31, 2017, we had additional borrowing capacity of $69 million and total liquidity of $85
million.
Bank fees and other costs incurred in connection
with the initial facility and the amendment were $9.1 million, which were deferred and are being amortized over five years. The
credit facility is collateralized by substantially all of Sunrise’s assets, and we are the guarantor.
The amended credit facility increased the Maximum
Leverage Ratio (Sunrise total funded debt/ trailing 12 months adjusted EBITDA) to those listed below:
Fiscal Periods Ending
|
|
Ratio
|
|
December 31, 2017 and March 31, 2018
|
|
|
4.25
|
X
|
June 30, 2018 and September 30, 2018
|
|
|
4.00
|
X
|
December 31, 2018
|
|
|
3.75
|
X
|
March 31, 2019 and June 30, 2019
|
|
|
3.50
|
X
|
The amended credit facility also requires a
Debt Service Coverage Ratio minimum of 1.25X through the maturity of the credit facility. The amendment defines the Debt Service
Coverage Ratio as trailing 12 months adjusted EBITDA/annual debt service.
At December 31, 2017, our Leverage Ratio was
2.40 and our Debt Service Coverage Ratio was 1.90. Therefore, we were in compliance with these two debt covenant ratios.
The interest rate on the facility ranges from
LIBOR plus 2.25% to LIBOR plus 4%, 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 ~5% on the original term loan balance and on $100 million of the revolver.
The revolver swap notional value steps down 10% each quarter which commenced on March 31, 2016. At December 31, 2017, these two
interest rate swaps had an estimated net fair value of $.5 million included in other assets on our consolidated balance sheet.
Notional values of the two interest rate swaps were $96 million and $30 million as of December 31, 2017.
At December 31, 2017, we were paying LIBOR
at 1.57% plus 3% for a total interest rate of 4.57%.
New accounting standards adopted in 2016 required
that our debt issuance costs be presented as a direct reduction from the related debt rather than as an asset.
Our debt at December 31 is presented below (in thousands):
|
|
2017
|
|
|
2016
|
|
Current debt
|
|
$
|
35,000
|
|
|
$
|
30,625
|
|
Less debt issuance cost
|
|
|
(1,829
|
)
|
|
|
(1,829
|
)
|
Net current portion
|
|
$
|
33,171
|
|
|
$
|
28,796
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
166,992
|
|
|
$
|
207,992
|
|
Less debt issuance cost
|
|
|
(1,219
|
)
|
|
|
(3,048
|
)
|
Net long-term portion
|
|
$
|
165,773
|
|
|
$
|
204,944
|
|
Future Maturities (in thousands):
|
|
|
|
2018
|
|
$
|
35,000
|
|
2019
|
|
|
166,992
|
|
Total
|
|
$
|
201,992
|
|
|
(
4)
|
Income Taxes (in thousands)
|
On December 22, 2017, the U.S. government
enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (Tax Act). The Tax Act makes 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. To
the extent that a company’s accounting for certain income tax effects of the Tax Act is incomplete but it is able to determine
a reasonable estimate, it must record a provisional estimate in the financial statements. If a company cannot determine a provisional
estimate to be included in the financial statements, it should continue to apply ASC 740 on the basis of the provisions of the
tax laws that were in effect immediately before the enactment of the Tax Act. As we are not subject to either the international
changes of the Tax Act or other applicable provisions, we believe that the income tax effects of the Tax Act applicable to our
accounting under ASC 740 is substantially complete for the year ended December 31, 2017. Additional information that may affect
the accounting under ASC 740 would include further clarification and guidance on how the Internal Revenue Service and state taxing
authorities will implement the Tax Act. We do not believe potential adjustments in future periods would materially impact the Company’s
financial condition or results of operations.
The Tax Act reduces the corporate tax rate
to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 requires the effect of a change in tax laws or rates to be recognized
as of the date of enactment, we are required to adjust deferred tax assets and liabilities as of December 22, 2017. Accordingly,
we have recorded a 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:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Expected amount
|
|
$
|
4,868
|
|
|
$
|
2,966
|
|
|
$
|
9,653
|
|
Adjustment to deferred taxes from the Tax Act rate reduction
|
|
|
(17,974
|
)
|
|
|
|
|
|
|
|
|
Change in Indiana rate
|
|
|
|
|
|
|
|
|
|
|
(85
|
)
|
State income taxes, net of federal benefit
|
|
|
115
|
|
|
|
(387
|
)
|
|
|
612
|
|
Percentage depletion
|
|
|
(4,128
|
)
|
|
|
(6,021
|
)
|
|
|
(2,606
|
)
|
Stock-based compensation
|
|
|
(204
|
)
|
|
|
(238
|
)
|
|
|
|
|
Captive insurance
|
|
|
(379
|
)
|
|
|
(418
|
)
|
|
|
(419
|
)
|
Adjustments to NOL carryforwards
|
|
|
(1,038
|
)
|
|
|
|
|
|
|
|
|
Return to provision adjustments
|
|
|
(205
|
)
|
|
|
|
|
|
|
|
|
Other
|
|
|
(249
|
)
|
|
|
72
|
|
|
|
283
|
|
|
|
$
|
(19,194
|
)
|
|
$
|
(4,026
|
)
|
|
$
|
7,438
|
|
The deferred tax assets and liabilities resulting
from temporary differences between book and tax basis are comprised of the following at December 31:
|
|
2017
|
|
|
2016
|
|
Long-term deferred tax assets:
|
|
|
|
|
|
|
|
|
Stock-based compensation
|
|
$
|
251
|
|
|
$
|
512
|
|
Investment in Savoy
|
|
|
781
|
|
|
|
1,031
|
|
Net operating loss
|
|
|
13,626
|
|
|
|
14,908
|
|
Alternative minimum tax credit
|
|
|
2,705
|
|
|
|
4,221
|
|
Other
|
|
|
943
|
|
|
|
564
|
|
Total long-term deferred tax assets
|
|
|
18,306
|
|
|
|
21,236
|
|
Long-term deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Coal properties
|
|
|
(47,034
|
)
|
|
|
(50,439
|
)
|
Oil and gas properties
|
|
|
-
|
|
|
|
(15,971
|
)
|
Total long-term deferred tax liabilities
|
|
|
(47,034
|
)
|
|
|
(66,410
|
)
|
Net deferred tax liability
|
|
$
|
(28,728
|
)
|
|
$
|
(45,174
|
)
|
Our effective tax rate (ETR) for 2017 was
(138)% compared to (48)% for 2016 and 27% for 2015. The negative ETR in 2017 is due primarily to the effects of the Tax Act adjustment
to our deferred taxes and prior year tax return reconciliation which were all recorded discretely for the year ended December 31,
2017. The negative ETR in 2016 is due to the combination of the reduction in book income before taxes because of the asset
impairment expense, permanent tax benefits of statutory depletion in excess of tax basis in the mining properties, the captive
insurance company effects, and stock based compensation expense. The tax rate for the years ended December 31, 2017 and 2016 are
not predictive of future tax rates due to the deferred income tax benefit of the Tax Act. The tax rate would have been 9% without
the effects of the deferred income tax benefit of the Tax Act and the prior year tax return reconciliation. Historically, our actual
effective tax rates have been lower than the statutory effective rate primarily due to the benefit received from statutory depletion
allowances. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income
taxes.
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 for the years 2014 through 2016 along with tax returns filed with numerous state
entities remain subject to examination.
|
(5)
|
Stock Compensation Plans
|
Restricted Stock Units (RSUs)
On May 16, 2017, our Compensation Committee
authorized the issuance and immediate vesting of 495,000 RSUs to our Chairman, President, and CFO. These shares were valued at
$3.8 million, based on the May 16, 2017, closing stock price of $7.74.
By shareholder approval on May 25, 2017, our
2008 Restricted Stock Unit Plan (RSU Plan) was amended and restated to add 1,000,000 shares and extend its term through May 25,
2027.
On June 6, 2017, our Compensation Committee
approved a Four-Year Compensation Plan for our Chairman, President, and CFO that granted them 645,000 RSUs. Beginning December
16, 2018, these RSUs will vest/lapse 25% annually through December 16, 2021, or earlier based on the terms of the RSU Plan and
the applicable award agreements. The closing stock price on the date of grant was $8.23.
The table below shows the number of RSUs
available for issuance at December 31, 2017:
Total authorized RSUs in Plan approved by shareholders
|
|
|
4,850,000
|
|
Stock issued out of the Plan from vested grants
|
|
|
(2,512,432
|
)
|
Non-vested grants
|
|
|
(944,500
|
)
|
RSUs available for future issuance
|
|
|
1,393,068
|
|
|
|
|
|
|
Non-vested grants at January 1, 2015
|
|
|
1,042,000
|
|
Granted – share price on grant date was $11.52
|
|
|
2,000
|
|
Vested – weighted average share price on vesting date was $7.42
|
|
|
(410,500
|
)
|
Forfeited
|
|
|
(27,000
|
)
|
Non-vested grants at December 31, 2015
|
|
|
606,500
|
|
Granted – weighted average share price on grant date was $6.84
|
|
|
414,000
|
|
Vested – weighted average share price on vesting date was $8.72
|
|
|
(271,500
|
)
|
Forfeited
|
|
|
(16,000
|
)
|
Non-vested grants at December 31, 2016
|
|
|
733,000
|
|
Granted – weighted average share price on grant date was $7.98
|
|
|
1,211,500
|
|
Vested – weighted average share price on vesting date was $7.22
|
|
|
(990,500
|
)
|
Forfeited
|
|
|
(9,500
|
)
|
Non-vested grants at December 31, 2017 (1)
|
|
|
944,500
|
|
Vesting
Year
|
|
No. RSUs
Vesting
|
|
2018
|
|
|
178,250
|
|
2019
|
|
|
373,750
|
|
2020
|
|
|
231,250
|
|
2021
|
|
|
161,250
|
|
|
|
|
944,500
|
|
Vested shares had a value of $7.1 million for
2017, $2.4 million for 2016, and $3.0 million for 2015 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 $6.2 million
based on the March 9, 2018, closing stock price of $6.53.
For the years ended December 31, 2017, 2016
and 2015 stock based compensation was $7.3 million, $2.5 million, and $3.1 million, respectively. For 2018, based on existing
RSUs outstanding, stock-based compensation expense is estimated to be $2.0 million.
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.
We have no defined benefit pension plans or
post-retirement benefit plans. We offer our employees a 401(k) Plan, where we match 100% of the first 4% that an employee contributes and
a discretionary Deferred Bonus Plan for certain key employees. We also offer health benefits to all employees and their
families. We have 2,289 participants in our employee health plan. The plan does not cover dental, vision, short-term or long-term
disability. These coverages are available on a voluntary basis. We bear some of the risk of our employee health plans.
Our health claims are capped at $200,000 per person with a maximum annual exposure of $14.4 million, not including premiums.
Our employee benefit expenses for the years
ended December 31 are below (in thousands):
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Health benefits, including premiums
|
|
$
|
13,311
|
|
|
$
|
12,672
|
|
|
$
|
13,400
|
|
401(k) matching
|
|
|
1,892
|
|
|
|
1,458
|
|
|
|
2,267
|
|
Deferred bonus plan
|
|
|
677
|
|
|
|
588
|
|
|
|
445
|
|
Total
|
|
$
|
15,880
|
|
|
$
|
14,718
|
|
|
$
|
16,112
|
|
Of the amounts in the above table, $15.5 million,
$13.8 million, and $15.2 million for 2017, 2016, and 2015, respectively are recorded in operating costs and expenses with the remainder
in SG&A.
Our mine employees are also covered by workers’
compensation and such costs for 2017, 2016 and 2015 were approximately $2.8 million, $2.3 million and $4.6 million, respectively,
of which $2.5 million, $2.3 million, and $4.6 million, respectively are recorded in operating costs and expenses with the remainder
in SG&A. 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. Our operations are protected from these perils through insurance policies.
Our maximum annual exposure is limited to $1 million per occurrence with a $4 million aggregate deductible. Based on discussions
and representations from our insurance carrier, we believe that our reserve for our workers’ compensation benefits is adequate. We
have a safety conscious workforce, and based on our experience modifier, our claims are averaging 27% below that of our peers in
underground coal mining in the state of Indiana.
|
(7)
|
Other Long-Term Assets and Other Income (in thousands)
|
|
|
2017
|
|
|
2016
|
|
Long-term assets
|
|
|
|
|
|
|
|
|
Advanced coal royalties
|
|
$
|
9,720
|
|
|
$
|
9,296
|
|
Marketable equity securities available for sale,
|
|
|
|
|
|
|
|
|
at fair value (restricted)*
|
|
|
2,148
|
|
|
|
2,036
|
|
Other
|
|
|
2,792
|
|
|
|
2,782
|
|
Total other assets
|
|
$
|
14,660
|
|
|
$
|
14,114
|
|
*Held by Sunrise Indemnity, Inc., our wholly
owned captive insurance company.
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Other income:
|
|
|
|
|
|
|
|
|
|
|
|
|
MSHA reimbursements**
|
|
$
|
1,725
|
|
|
$
|
1,753
|
|
|
$
|
|
|
Miscellaneous
|
|
|
1,341
|
|
|
|
2,209
|
|
|
|
2,236
|
|
|
|
$
|
3,066
|
|
|
$
|
3,962
|
|
|
$
|
2,236
|
|
**See “MSHA Reimbursements” in
the MD&A section for a discussion of these amounts.
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 $258
million.
As of December 31, 2017, and 2016, restricted
cash of $3.8 million and $2.8 million, respectively, represents cash held and controlled by a third party and is restricted for
future workers’ compensation claim payments.
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:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
$
|
33,076
|
|
|
$
|
12,510
|
|
|
$
|
20,132
|
|
Less earnings allocated to RSUs
|
|
|
(1,028
|
)
|
|
|
(305
|
)
|
|
|
(450
|
)
|
Net income allocated to common shareholders
|
|
$
|
32,048
|
|
|
$
|
12,205
|
|
|
$
|
19,682
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of common shares outstanding
|
|
|
29,661
|
|
|
|
29,260
|
|
|
|
29,031
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic and diluted
|
|
$
|
1.08
|
|
|
$
|
0.42
|
|
|
$
|
0.68
|
|
|
(10)
|
Fair Value Measurements
|
We account for certain assets and liabilities
at fair value. The hierarchy below lists three levels of fair value based on the extent to which inputs used in measuring fair
value are observable in the market. We categorize each of our fair value measurements in one of these three levels based on the
lowest level input that is significant to the fair value measurement in its entirety. These levels are:
Level 1: Unadjusted quoted prices in active
markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets
as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information
on an ongoing basis. Our marketable securities are Level 1 instruments.
Level 2: Quoted prices in markets that are
not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. We
have no Level 2 instruments.
Level 3: Measured based on prices or valuation
models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e.,
supported by little or no market activity). Our Level 3 instruments are comprised of interest rate swaps. 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, 2017 and 2016 by respective level of the fair
value hierarchy:
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Total
|
|
|
|
(in thousands)
|
|
December 31, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities
|
|
$
|
1,907
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1,907
|
|
Marketable securities - restricted
|
|
|
2,148
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,148
|
|
Interest rate swaps
|
|
|
-
|
|
|
|
-
|
|
|
|
543
|
|
|
|
543
|
|
|
|
$
|
4,055
|
|
|
$
|
-
|
|
|
$
|
543
|
|
|
$
|
4,598
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities
|
|
$
|
1,763
|
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
1,763
|
|
Marketable securities - restricted
|
|
|
2,036
|
|
|
|
-
|
|
|
|
-
|
|
|
|
2,036
|
|
Interest rate swaps
|
|
|
-
|
|
|
|
-
|
|
|
|
296
|
|
|
|
296
|
|
|
|
$
|
3,799
|
|
|
$
|
-
|
|
|
$
|
296
|
|
|
$
|
4,095
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate swaps
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
476
|
|
|
$
|
476
|
|
The table below highlights the change in fair
value of the interest rate swaps:
|
|
Fair Value Measurements
Using
Significant
Unobservable Inputs
(Level 3)
|
|
|
|
Interest Rate Swaps
|
|
|
|
(in thousands)
|
|
Ending balance, December 31, 2015
|
|
$
|
(817
|
)
|
Change in estimated fair value
|
|
|
637
|
|
Ending balance, December 31, 2016
|
|
|
(180
|
)
|
Change in estimated fair value
|
|
|
723
|
|
Ending balance, December 31, 2017
|
|
$
|
543
|
|
|
(11)
|
Equity Method Investments
|
We own a 50% interest in Sunrise Energy, LLC,
which owns gas reserves and gathering equipment with plans to develop and operate such reserves. Sunrise Energy also plans to develop
and explore for oil, gas and coal-bed methane gas reserves on or near our underground coal reserves. We received distributions
totaling $175,000 and $375,000 for the years ended December 31, 2017 and 2016, respectively.
We own a 30.6% interest in Savoy Energy, L.P.,
a private company engaged in the oil and gas business primarily in the state of Michigan.
On November 3, 2016, Lubar Equity Fund,
LLC acquired a 25% interest in Savoy for $9.5 million in cash. Accordingly, our ownership interest was reduced from 40.8% to 30.6%.
At closing, Savoy made a cash distribution of $4.4 million of which our share was $1.8 million and per our credit agreement was
applied to our bank debt. Mr. Lubar, one of our directors, is affiliated with Lubar Equity Fund, LLC.
We did not receive any distributions in 2017
and received two distributions in 2016 totaling $3.6 million from Savoy. Both distributions were applied to our bank debt as required
under our agreement.
Savoy also recorded impairments of $1.0 million,
$2.0 million, and $2.6 million for the years ended December 31, 2017, 2016, and 2015, respectively.
We have reached an agreement for Savoy to redeem
our entire partnership interest for $8 million, which we expect to finalize in mid-March 2018. Our net after commissions paid will
be $7.5 million.
|
(12)
|
Freelandville and Log Creek Purchases
|
On March 22, 2016, we completed the purchase
of the Freelandville coal reserves, advanced royalties, and coal sales agreement for $18.25 million from Triad Mining LLC. These
reserves totaled 14.2 million tons of fee and leased coal and will be mined from our Oaktown 1 portal. This purchase allowed us
access to another 1.6 million tons of our own leased reserves that were previously inaccessible. The purchased coal sales agreement
totaled 1,435,000 tons and was fulfilled in 2017. The purchase price allocation for the acquisition was as follows (in thousands):
Purchased coal contract
|
|
$
|
6,407
|
|
Advanced coal royalties
|
|
|
1,690
|
|
Mineral rights and leases
|
|
|
10,153
|
|
Total
|
|
$
|
18,250
|
|
On December 12, 2016, we completed a second
transaction with Triad, the purchase of their Log Creek coal sales agreement for $4.1 million. The purchased coal sales agreement
included 557,000 tons that were delivered in 2016 and 2017.
|
(13)
|
Quarterly Financial Data (Unaudited)
|
Summarized quarterly financial data is as follows:
|
|
Three Months Ended
|
|
|
|
Dec-31
|
|
|
Sep-30
|
|
|
Jun-30
|
|
|
Mar-31
|
|
|
|
(In thousands, except per share data)
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
69,300
|
|
|
$
|
74,468
|
|
|
$
|
64,312
|
|
|
$
|
63,553
|
|
Operating income
|
|
|
3,921
|
|
|
|
7,155
|
|
|
|
4,065
|
|
|
|
11,154
|
|
Net income (loss) *
|
|
|
21,357
|
|
|
|
3,916
|
|
|
|
389
|
|
|
|
7,414
|
|
Basic income per common share
|
|
$
|
0.69
|
|
|
$
|
0.13
|
|
|
$
|
0.01
|
|
|
$
|
0.25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
$
|
71,234
|
|
|
$
|
65,767
|
|
|
$
|
68,564
|
|
|
$
|
75,885
|
|
Operating income
|
|
|
7,972
|
|
|
|
7,686
|
|
|
|
10,732
|
|
|
|
13,496
|
|
Net income (loss) *
|
|
|
(3,827
|
)
|
|
|
4,322
|
|
|
|
5,853
|
|
|
|
6,162
|
|
Basic income per common share
|
|
$
|
(0.13
|
)
|
|
$
|
0.14
|
|
|
$
|
0.19
|
|
|
$
|
0.21
|
|
*
See
Note 2 related to asset impairment taken in December 2016 and Note 4 related to the effects of the Tax Act in December 2017.
|
(14)
|
Accounts Payable and Accrued Liabilities
|
|
|
2017
|
|
|
2016
|
Accounts payable
|
$
|
4,008
|
|
$
|
4,829
|
Goods received not
yet invoiced
|
|
5,574
|
|
|
3,072
|
Accrued property taxes
|
|
2,751
|
|
|
2,992
|
Workers' compensation reserve and IBNR
|
|
2,969
|
|
|
2,658
|
Other
|
|
5,813
|
|
|
6,367
|
Total accounts payable and accrued liabilities
|
$
|
21,115
|
|
$
|
19,918
|
|
ITEM 9:
|
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
|
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, 2017. Based on that evaluation, our management concluded that
our ICFR was effective at December 31, 2017. EKS&H LLLP has audited and reported on our financial statements and our ICFR as
of December 31, 2017. 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, 2017, that have materially affected or
are reasonably likely to materially affect our internal control over financial reporting.
|
ITEM 9B.
|
OTHER INFORMATION
None.
|