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 of the costs of compliance with applicable federal and state laws
and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws
and regulations has substantially increased the cost of coal mining for domestic coal producers.
Capital expenditures for environmental matters
have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations
and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement
obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations
and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and
other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.
Mining Permits and
Approvals
Numerous governmental permits or approvals
are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation
and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These
matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and impacts
on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting
all requirements imposed by any of these authorities may be costly and 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 will close on April 10, 2017.
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, 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 500 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, EPA finalized the CSAPR Update to respond to the remand by the D.C. Circuit Court of Appeals.
Implementation of Phase 2 will begin 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. 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 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 will 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, EPA issued a final rule for states
to use in creating their plans to address 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 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, 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.
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. Most recently,
the United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an international
climate 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. The U.S. is currently a party to the Paris Agreement; however, President Trump has said that he would "cancel
the Paris Climate Agreement and stop all payments of U.S. tax dollars to U.N. global warming programs." 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 is now requiring 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 June 2014, the EPA proposed CO
2
emission
“guidelines” for modified and existing fossil fuel-fired power plants under Section 111(d) of the CAA.
The EPA finalized the “Clean Power Plan” (“CPP”) in August 2015, which established carbon pollution
standards for power plants, called CO2 emission performance rates. The EPA expects each state to develop implementation plans
for power plants in its state to meet the individual state targets established in the CPP. The EPA has given states the option
to develop compliance plans for annual rate-based reductions (pounds per megawatt hour) or mass-based tonnage limits for CO2.
The state plans were due in September 2016, subject to potential extensions of up to two years for final plan submission.
The compliance period begins in 2022, and emission reductions will be phased in up to 2030. The EPA also proposed a federal
compliance plan to implement the CPP in the event that an approvable state plan is not submitted to the EPA. Although each
state can determine its own method of compliance, the requirements rely on decreased use of coal and increased use of natural gas
and renewables for electricity generation, as well as reductions in the amount of electricity used by consumers. Judicial
challenges have been filed and oral arguments were heard by the D.C. Circuit Court of Appeals in September 2016, but a final decision
has not yet been issued. On February 9, 2016, the U.S. Supreme Court issued a stay, halting implementation of the regulations.
The stay will be in place until the D.C. Circuit Court of Appeals rules on the merits of the legal challenges and, if following
a ruling by the D.C. Circuit Court of Appeals, a writ of certiorari from the Supreme Court is sought and granted, the stay will
remain in place until the Supreme Court issues its decision on the merits. If, despite the legal challenges, the rules were
implemented in their current form, demand for coal will likely be further decreased, potentially significantly, and adversely impact
our business. Future implementation of the CPP remains uncertain.
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. The rule for existing sources proposes to establish different target emission rates (lbs per megawatt hour)
for each state and has an overall goal to achieve a 32% reduction of carbon dioxide emissions from 2005 levels by 2030. The
compliance period begins in 2022 and in 2030 CO
2
emissions goals must be met. Challenges
to the NSPS have been filed in U.S. Court of Appeal for the D.C. Circuit and oral arguments are set for April 2017.
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 range generally 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 claims to proceed
against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while
a second federal appeals court dismissed a similar case on procedural grounds. The U.S. Supreme Court overturned that decision
in June 2011, holding that federal common law provides no basis for public nuisance claims against utilities due to their
carbon dioxide emissions. The Supreme Court did not, however, decide whether similar claims can be brought under state common
law. As a result, despite this favorable ruling, tort-type liabilities remain a concern.
In addition, environmental advocacy groups
have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting
permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental
Policy Act (“NEPA”). These groups assert that the environmental analyses in question do not adequately consider
the climate change impacts of these particular projects. In December 2014, the Council on Environmental Quality (“CEQ”)
released updated draft guidance discussing how federal agencies should consider the effects of GHG emissions and climate change
in their NEPA evaluations. The guidance encourages agencies to provide more detailed discussion of the direct, indirect,
and cumulative impacts of a proposed action’s reasonably foreseeable emissions and effects. This guidance could create
additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals
for our future operations, including due to the increased risk of legal challenges from environmental groups seeking additional
analysis of climate impacts.
Many states and regions have adopted GHG initiatives
and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain
facilities, including coal-fired electric generating facilities. For example, in 2005, ten Northeastern states entered into
the Regional Greenhouse Gas Initiative agreement (“RGGI”), calling for implementation of a cap and trade program aimed
at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established
in statutes and/or regulations a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program
began in September 2008. Though New Jersey withdrew from RGGI in 2011, since its inception, several additional northeastern
states and Canadian provinces have joined as participants or observers.
Following the RGGI model, five Western states
launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods
of reducing GHG in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four
Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, 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.
For instance, even though the State of West
Virginia has been delegated the authority to issue permits for coal mines in that state, the EPA is taking a more active role in
its review of National Pollutant Discharge Elimination System (“NPDES”) permit applications for coal mining operations
in Appalachia. The EPA has stated that it plans to review all applications for NPDES permits. Indeed, final guidance
issued by the EPA in July 2011, encouraged the EPA Regions 3, 4 and 5 to object to the issuance of state program NPDES permits
where the Region does not believe that the proposed permit satisfies the requirements of the CWA, and with regard to state issued
general Section 404 permits, support the previously drafted Enhanced Coordination Procedures (“ECP”). In
October 2011, the U.S. District Court for the District of Columbia rejected the ECP on several different legal grounds and
later, this same court enjoined the EPA from any further usage of its final guidance. The U.S. Supreme Court denied a request
to review this decision. Any future application of procedures similar to ECP, such as may be enacted following notice and
comment rulemaking, would have the potential to delay issuance of permits for surface coal mines, or to change the conditions or
restrictions imposed in those 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.
In June 2015, the EPA issued a new rule providing
a definition of the WOTUS. This rule is broadly written and expands the EPA and Corps of Engineers jurisdiction. WOTUS creates
new federal authority over lands, ditches, and potentially on-site mining waters. Of critical concern to our industry is the possibility
that many water features commonly found on mine sites which are currently not considered jurisdictional could nevertheless fall
within the definition of WOTUS under the proposed rule. Ditches, closed loop systems, on-site ponds, impoundments, and other
water management features are integral to mining operations, and are used to manage on-site waters in an environmentally sound
and frequently statutorily mandated manner. The rule could lead to substantially increased permitting requirements with
more costs, delays, and increased risk of litigation. Industry Groups have challenged the final rule. Multiple suits
were filed across the country by states, industry, and outside parties. The Coal Industry is currently active in suits in the Texas
District Court and 6
th
Circuit Court of Appeals, though the coalition has moved to intervene
in several suits (to both defend certain provisions in the rule important to industry and contest overly-broad provisions).
The 6
th
Circuit ordered a nationwide stay of the rule that will remain in effect
at least until it issues its jurisdictional determination (expected in the near future). At present, it is not clear whether
an appellate court or multiple district courts will exercise jurisdiction over the claims. In January 2016, the U.S. Supreme
Court agreed to resolve the jurisdictional questions and decide the proper court or courts to hear the challenges to the WOTUS
rule.
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.
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 reopened 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: BTUUQ) and Alliance (NASDAQ: ARLP) and small producers.
Employees
We have 748 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
and Sunrise Coal’s is
www.sunrisecoal.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
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 34%.
The domestic electric utility industry accounts
for over 92% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected
primarily by the overall demand for electricity, environmental and other 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.
In addition, 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. At former President Obama’s
direction, the EPA proposed CO2 emissions requirements, known as the CPP, for existing and modified power plants and published
such rules on October 23, 2015. As a result of these current and proposed laws, regulations and regulatory initiatives,
electricity generators may elect to switch to other fuels that generate less of these emissions or by-products, further reducing
demand for coal. Please read “Item 1. Business—Regulation and Laws—“
Air Emission,”
“—
Carbon Dioxide Emissions
” and “—
Hazardous Substances and Wastes
.”
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 a rule 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
construction of new coal fired power plants. In August 2015, the EPA finalized GHG emissions regulations for modified
and existing power plants. The rule for modified sources requires 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.
The rule for existing sources proposes to establish different target emission rates (lbs per megawatt hour) for each state
and has an overall goal to achieve a 32% reduction of carbon dioxide emissions from 2005 levels by 2030. If upheld by courts,
the regulation could lead to premature retirements of coal-fired electric generating units and significantly reduce the demand
for coal. In addition, many states and regions have adopted GHG initiatives. Also, there have been numerous protests
of, and challenges to, the permitting of new coal-fired power plants by environmental organizations and state regulators due to
concerns related to GHG emissions. 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.
Congress has extended certain tax credits for
renewable sources of electric generation, which will increase the ability of these sources to compete with our coal products in
the market. In addition, the U.S. Department of Interior recently announced a moratorium on issuing certain new coal leases on
federal land while the Bureau of Land Management undertakes a programmatic review of the federal coal program. While none
of our operations are located on federal lands impacted by this moratorium, it does signal increased attention at the federal level
to coal mining practices and the GHG emissions resulting from coal combustion.
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 558 coal-fired electric generating units through 2030. These retirements and conversions
amount to over 93,000 megawatts (“MW”) or approximately 30% of the 2010 total coal electric generating capacity.
At the end of 2016 retirement and conversions affecting 60,000 MW, or approximately 19% of the 2010 total coal electric generating
capacity, are 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.
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 2016, substantially all 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 2016, we derived 90% 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 work force may not remain union-free in the future.
None of our employees are represented under
collective bargaining agreements. However, all of our work force 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 economically recover. 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; and
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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 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.
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.
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 4 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 maximum leverage ratio (funded debt/EBITDA) not to exceed 4.50 to 1. At December 31, 2016, our debt service
coverage ratio was 2.11
and our leverage ratio was 2.95. Therefore, we were in compliance
with these two ratios.
Our indebtedness may limit our ability
to borrow additional funds or capitalize on business opportunities.
At December 31, 2016, our debt was $239
million. Our leverage may:
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adversely affect our ability to finance future
operations and capital needs;
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limit our ability to pursue acquisitions and
other business opportunities;
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make our results of operations more susceptible
to adverse economic or operating conditions; and
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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
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. Thus, the decision was made to seal off the North end of the mine. Sealing
will be completed in the 1st quarter of 2017. 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. After the impairment, the Carlisle assets
had an aggregate carrying value of $118 million at December 31, 2016. We conducted a review of the Carlisle mine assets and
determined that no further impairment charge was necessary. If, in future periods, we reduce our estimate of the future net
cash flows attributable to the Carlisle Mine, it may result in additional future impairment of such assets and such charges could
be significant. None of our other assets are considered impaired.