HALLADOR ENERGY CO - Annual Report: 2018 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

Commission file number: 001-3473

“COAL KEEPS YOUR LIGHTS ON”

“COAL KEEPS YOUR LIGHTS ON”

HALLADOR ENERGY COMPANY

(www.halladorenergy.com)

Issuer's telephone number: 303.839.5504

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨  No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ¨ Noþ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ  No ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company.  See the definitions of "larger accelerated filer," "accelerated filer", "smaller reporting company," and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No þ

The aggregate market value of the common stock held by non-affiliates (public float) on June 29, 2018 was $125,602,524 based on the closing price reported that date by the NASDAQ of $7.14 per share.

As of March 8, 2019, we had 30,244,599 shares outstanding.

Portions of our Proxy Statement to be filed with the SEC in connection with our annual stockholders’ meeting are incorporated by reference into Part III of this Form 10-K. Our Annual Meeting of Shareholders will be held on May 23, 2019 in Terre Haute, IN.

FORWARD-LOOKING STATEMENTS

Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.”  These statements are based on our beliefs as well as assumptions made by, and information currently available to us.  When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements.  Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements.  Among the factors that could cause actual results to differ from those in the forward-looking statements are:

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement.  When considering forward-looking statements, you should also keep in mind the risk factors described in “Item 1A. Risk Factors” below.  The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement.  We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

You should consider the information above when reading any forward-looking statements contained in this Annual Report on Form 10-K; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website http://www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

ITEM 1.      BUSINESS.

See Item 7- MDA for a discussion of our business.

Regulation and Laws

The coal mining industry is subject to extensive regulation by federal, state and local authorities on matters such as:

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 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:

MSHA continues to interpret and implement various provisions of the MINER Act, along with introducing new proposed regulations and standards.

In 2014, MSHA began implementation of a finalized new regulation titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.”  The final rule implemented a reduction in the allowable respirable coal mine dust exposure limits, requires the use of sampling data taken from a single sample rather than an average of samples, and increases oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine, all of which increase mining costs. The second phase of the rule began in February 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor technology, which provides real-time dust exposure information to the miner.  Phase three of the rule began in August 2016 and resulted in lowering the current respirable dust level of 2.0 milligrams per cubic meter to 1.5 milligrams per cubic meter of air.  Compliance with these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations. On July 9, 2018, MSHA published a request for information to solicit stakeholder comments, data, and information for the development of a framework to conduct a retrospective study on the impact of the final rule, as well as a request for information and data on engineering controls and best practices used by mine operators to lower miners' exposure to respirable coal dust. The comment period for this request for information will close on July 9, 2019. It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period for the current request for information.

Additionally, in July 2014, MSHA proposed a rule addressing the “criteria and procedures for assessment of civil penalties.”  Public commenters have expressed concern that the proposed rule exceeds MSHA’s rulemaking authority and would result in substantially increased civil penalties for regulatory violations cited by MSHA.  MSHA last revised the process for proposing civil penalties in 2006 and, as discussed above, civil penalties increased significantly.  The notice-and-comment period for this proposed rule has closed, and it is uncertain when, or if, MSHA will present a final rule addressing these civil penalties.

In January 2015, MSHA published a final rule requiring mine operators to install proximity detection systems on continuous mining machines, over a staggered time frame ranging from November 2015 through March 2018.  The proximity detection systems initiate a warning or shutdown the continuous mining machine depending on the proximity of the machine to a miner. MSHA subsequently proposed a rule requiring mine operators to also install proximity detection systems on other types of underground mobile mining equipment.  The comment period for this proposed rule closed on April 10, 2017, and it is uncertain when MSHA will promulgate a final rule addressing the issue of proximity detection systems on underground mobile mining equipment, other than continuous mining machines.

In June 2016, MSHA published a request for information on Exposure of Underground Miners to Diesel Exhaust.  Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA's request for information.  The comment period for the request for information was reopened and closed in January 2018.  The comment period was reopened again in March 2018 and is scheduled to close in March 2019. It is uncertain what MSHA will do with this information.

In June 2018, MSHA published a request for information on Safety Improvement Technologies for Mobile Equipment at Surface Mines and for Belt Conveyors at Surface and Underground Mines. The comment period for the request for information closed on December 24, 2018. It is uncertain whether MSHA will present a proposed rule pertaining to safety improvement technologies for mobile equipment at surface mines or for belt conveyors at surface and underground mines.

Subsequent to passage of the MINER Act, Illinois, Kentucky, Pennsylvania, and West Virginia have enacted legislation addressing issues such as mine safety and accident reporting, increased civil and criminal penalties, and increased inspections and oversight. Additionally, state administrative agencies can promulgate administrative rules and regulations affecting our operations.  Other states may pass similar legislation or administrative regulations in the future.

Some of the costs of complying with existing regulations and implementing new safety and health regulations may be passed on to our customers.  Although we have not quantified the full impact, implementing and complying with these new state and federal safety laws and regulations have had, and are expected to continue to have, an adverse impact on our results of operations and financial position.

Black Lung Benefits Act

The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 (“BLBA”) requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease and to some survivors of a miner who dies from this disease.  The BLBA levied a tax on coal sales of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims.  In addition, the BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax.  The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent.  The Emergency Economic Stabilization Act of 2008 extended these rates through December 31, 2018. As of January 1, 2019, the excise tax rates have reverted to their original 1977 statutory levels of $0.50 per ton for underground-mined coal and $0.25 per ton for surface mined coal, but not to exceed 2% of the applicable sales price.

Workers’ Compensation and Black Lung

We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws.  Workers’ compensation laws also compensate survivors of workers who suffer employment-related deaths.  We generally self-insure this potential expense using our actuary estimates of the cost of present and future claims. In addition, coal mining companies are subject to CMHSA, as amended, and various state statutes for the payment of medical and disability benefits to eligible recipients related to coal worker's pneumoconiosis, or black lung. We also provide for these claims through self-insurance programs. Our actuarial calculations are based on numerous assumptions including disability incidence, medical costs, mortality, death benefits, dependents and discount rates.

The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations and thus potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised criteria.  These regulations may also increase black lung related medical costs by broadening the scope of conditions for which medical costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.

The Patient Protection and Affordable Care Act enacted in 2010 includes significant changes to the federal black lung program retroactive to 2005, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment that are totally disabled by a respiratory condition.  These changes could have a material impact on our costs expended in association with the federal black lung program.

Surface Mining Control and Reclamation Act

The Federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes establish operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of underground mining.  Currently, ~96% of our production capacity involves underground room and pillar mining (no surface subsidence), and ~4% involves surface mining. We do not engage in either mountain top removal or long-wall mining. SMCRA nevertheless requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of our mining activities.

SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans.  SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable.  Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.  We believe we are in compliance in all material respects with applicable regulations relating to reclamation.

In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977.  The tax for surface-mined and underground-mined coal is $0.28 per ton and $0.12 per ton, respectively.  We have accrued the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. In addition, states from time to time have increased and may continue to increase their fees and taxes to fund reclamation or orphaned mine sites and acid mine drainage control on a statewide basis. 

Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent contract mine operators and other third parties can be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the third-party violator.  Sanctions against the “owner” or “controller” are quite severe and can include being blocked from receiving new permits and having any permits revoked that were issued after the time of the violations or after the time civil penalties or reclamation fees became due.  We are not aware of any currently pending or asserted claims against us relating to the “ownership” or “control” theories discussed above.  However, we cannot assure you that such claims will not be asserted in the future.

The U.S. Office of Surface Mining Reclamation (“OSM”) published in November 2009 an Advance Notice of Proposed Rulemaking, announcing its intent to revise the Stream Buffer Zone (“SBZ”) rule published in December 2008.  The SBZ rule prohibits mining disturbances within 100 feet of streams if there would be a negative effect on water quality.  Environmental groups brought lawsuits challenging the rule, and in a March 2010 settlement, the OSM agreed to rewrite the SBZ rule.  In January 2013, the environmental groups reopened the litigation against OSM for failure to abide by the terms of the settlement.  Oral arguments were heard on January 31, 2014.  OSM published a notice in December 2014, to vacate the 2008 SBZ rule to comply with an order issued by the U.S. District Court for the District of Columbia.  OSM reimplemented the 1983 SBZ rule. Subsequent attempts by OSM to issue a revised stream protection rule met with Congressional opposition, ultimately resulting in the passage of a resolution under the Congressional Review Act that revoked OSM's stream protection rule and prevents the agency from promulgating a substantially similar rule absent future legislation. Whether Congress will enact future legislation to require a new stream protection rule remains uncertain.

In December 2009, the United States Environmental Protection Agency (“EPA”) issued proposed rules on coal combustion residues (“CCRs”) in 2010.  This final rule was published in December 2014.  The EPA's final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites.  OSM has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but, to date, no further action has been taken.  These actions by OSM potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.

Bonding Requirements

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, and to satisfy other miscellaneous obligations.  These bonds are typically renewable on a yearly basis.  It has become increasingly difficult for our competitors and us to secure new surety bonds without posting collateral.  In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us.  It is possible that surety bond issuers may refuse to renew bonds or may demand additional collateral upon those renewals.  Our failure to maintain or inability to acquire, surety bonds that are required by state and federal laws would have a material adverse effect on our ability to produce coal, which could affect our profitability and cash flow.

Air Emissions

The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining operations.  The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants.  The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning facilities.  There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities.  Installation of additional emissions control technology and any additional measures required under applicable state and federal laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans (“SIPs”), could make coal a less attractive fuel alternative in the planning and building of power plants in the future.  A significant reduction in coal’s share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations.  Since 2010, utilities have completed or formally announced the retirement or conversion of over 600 coal-fired electric generating units through 2030 in the United States, nearly 40% of the U.S. coal fleet.

In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may affect our operations, directly or indirectly, include, but are not limited to, the following:

Carbon Dioxide Emissions

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide, which is considered a GHG.  Combustion of fuel for mining equipment used in coal production also emits GHGs.  Future regulation of GHG emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA.  Congress has considered various proposals to reduce GHG emissions, and it is possible federal legislation could be adopted in the future.  Internationally, the Kyoto Protocol set binding emission targets for developed countries that ratified it (the U.S. did not ratify, and Canada officially withdrew from its Kyoto commitment in 2012) to reduce their global GHG emissions.  The Kyoto Protocol was nominally extended past its expiration date of December 2012, with a requirement for a new legal construct to be put into place by 2015.  The United Nations Framework Convention on Climate Change met in Paris, France in December 2015 and agreed to an international climate agreement (Paris Agreement).  Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions.  These commitments could further reduce demand and prices for our coal. In June of 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement, which has a four-year exit process.   Future participation in the Paris Agreement by the U.S. remains uncertain.  However, many states, regions and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating facilities.  Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted, which would have an adverse effect on our operations.

Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S. Supreme Court’s 2007 decision in Massachusetts v. Environmental Protection Agency that the EPA has authority to regulate GHG emissions.  In 2009, the EPA issued a final rule, known as the “Endangerment Finding,” declaring that GHG emissions, including carbon dioxide and methane, endanger public health and welfare and that six GHGs, including carbon dioxide and methane, emitted by motor vehicles endanger both the public health and welfare.

In May 2010, the EPA issued its final “tailoring rule” for GHG emissions, a policy aimed at shielding small emission sources from CAA permitting requirements.  The EPA’s rule phases in various GHG-related permitting requirements beginning in January 2011.  Beginning July 1, 2011, the EPA requires facilities that must already obtain NSR permits (new or modified stationary sources) for other pollutants to include GHGs in their permits for new construction projects that emit at least 100,000 tons per year of GHGs and existing facilities that increase their emissions by at least 75,000 tons per year.  These permits require that the permittee adopt the Best Available Control Technology (“BACT”).  In June 2014, the U.S. Supreme Court invalidated the EPA’s position that power plants and other sources can be subject to permitting requirements based on their GHG emissions alone.  For CO2 BACT to apply, CAA permitting must be triggered by another regulated pollutant (e.g., SO2). 

As a result of revisions to its preconstruction permitting rules that became fully effective in 2011, the EPA now requires new sources, including coal-fired power plants, to undergo control technology reviews for GHGs (predominantly carbon dioxide) as a condition of permit issuance.  These reviews may impose limits on GHG emissions, or otherwise be used to compel consideration of alternative fuels and generation systems, as well as increase litigation risk for and so discourage development of coal-fired power plants. The EPA has also issued final rules requiring the monitoring and reporting of greenhouse gas emissions from certain sources.

In March 2012, the EPA proposed New Source Performance Standards (“NSPS”) for carbon dioxide emissions from new fossil fuel-fired power plants.  The proposal requires new coal units to meet a carbon dioxide emissions standard of 1,000 lbs. CO2/MWh, which is equivalent to the carbon dioxide emitted by a natural gas combined cycle unit.  In January 2014, the EPA formally published its re-proposed NSPS for carbon dioxide emissions from new power plants.  The re-proposed rule requires an emissions standard of 1,100 lbs. CO2/MWh for new coal-fired power plants.  To meet such a standard, new coal plants would be required to install carbon capture and storage (“CCS”) technology. In August 2015, the EPA released final rules requiring newly constructed coal-fired steam electric generating units (“EGUs”) to emit no more than 1,400 lbs CO2/MWh (gross) and be constructed with CCS to capture 16% of CO2 produced by an electric generating unit burning bituminous coal.  At the same time, the EPA finalized GHG emissions regulations for modified and existing power plants.  The rule for modified sources required reducing GHG emissions from any modified or reconstructed source and could limit the ability of generators to upgrade coal-fired power plants thereby reducing the demand for coal.  In April 2017, the EPA published notice in the federal register that the agency has initiated a review of the NSPS for new and modified fossil fuel-fired power plants and that, following the review, the EPA will initiate reconsideration proceedings to suspend, revise or rescind this NSPS.  Challenges to the NSPS have been filed in U.S. Court of Appeal for the D.C. Circuit and oral arguments were set for April 2017; however, in April 2017, the U.S Court of Appeal for the D.C. Circuit ordered the NSPS case held in abeyance for an EPA review of the rule.  In December 2018, the EPA re-proposed the NSPS with a standard reflecting the performance of currently demonstrated supercritical technologies with an emission limit of 1,900 lbs. CO2/MWh for large units (heat input greater than 2,000 MMBtu/hour) and subcritical technologies with an emission limit of 2,000 lbs. CO2/MWh for small units. It is likely than any repeal or revisions to the NSPS will be subject to legal challenges as well.  Future implementation of the NSPS is uncertain at this time.

In August 2015, the EPA issued its final Clean Power Plan ("CPP") rules that establish carbon pollution standards for power plants, called CO₂ emission performance rates.  Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision.  By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted.   The Supreme Court's stay applies only to the EPA's regulations for CO₂ emissions from existing power plants and will not affect the EPA's standards for new power plants.  It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP. Additionally, in October 2017 the EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time.   In connection with this proposed repeal, the EPA issued an Advance Notice of Proposed Rulemaking ("ANPRM") in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units.  The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose.  In August 2018, the EPA proposed the ACE rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction." The ACE rule adopts new implementing regulations under the CAA to clarify the roles of the EPA and the states, including an extension of the deadline for state plans and EPA approvals; and, the rule revises the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements. The EPA's attempts to replace the CPP with the ACE rule are currently subject to litigation, and we cannot predict the final outcome.

Notwithstanding the ACE rule, these requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal.  Congress has rejected legislation to restrict carbon dioxide emissions from existing power plants, and it is unclear whether the EPA has the legal authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP. Substantial limitations on GHG emissions could adversely affect demand for the coal we produce. 

There have been numerous protests of and challenges to the permitting of new coal-fired power plants by environmental organizations and state regulators for concerns related to GHG emissions.  For instance, various state regulatory authorities have rejected the construction of new coal-fueled power plants based on the uncertainty surrounding the potential costs associated with GHG emissions from these plants under future laws limiting the emissions of carbon dioxide.  In addition, several permits issued to new coal-fueled power plants without limits on GHG emissions have been appealed to the EPA’s Environmental Appeals Board.  In addition, over thirty states have currently adopted “renewable energy standards” or “renewable portfolio standards,” which encourage or require electric utilities to obtain a certain percentage of their electric generation portfolio from renewable resources by a certain date.  Several states have announced their intent to have renewable energy comprise 100% of their electric generation portfolio.  Other states may adopt similar requirements, and federal legislation is a possibility in this area.  To the extent these requirements affect our current and prospective customers, they may reduce the demand for coal-fired power and may affect long-term demand for our coal.  Finally, a federal appeals court allowed a lawsuit pursuing federal common law claims to proceed against certain utilities on the basis that they may have created a public nuisance due to their emissions of carbon dioxide, while a second federal appeals court dismissed a similar case on procedural grounds.  The U.S. Supreme Court overturned that decision in June 2011, holding that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions.  The U.S. Supreme Court did not, however, decide whether similar claims can be brought under state common law.  As a result, despite this favorable ruling, tort-type liabilities remain a concern.

In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act (“NEPA”).  These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects.  In December 2014, the Council on Environmental Quality (“CEQ”) released updated draft guidance discussing how federal agencies should consider the effects of GHG emissions and climate change in their NEPA evaluations.  The guidance encourages agencies to provide more detailed discussion of the direct, indirect, and cumulative impacts of a proposed action’s reasonably foreseeable emissions and effects.  This guidance could create additional delays and costs in the NEPA review process or in our operations, or even an inability to obtain necessary federal approvals for our future operations, including due to the increased risk of legal challenges from environmental groups seeking additional analysis of climate impacts. In April 2017, CEQ withdrew its final 2016 guidance on how federal agencies should incorporate climate change and GHG considerations into NEPA reviews of federal actions; however, the potential remains for CEQ to issue similar guidance in the future.

Many states and regions have adopted GHG initiatives, and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities.  For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement (“RGGI”), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states.  The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program.  Auctions for carbon dioxide allowances under the program began in September 2008.  Since its inception, several additional northeastern states and Canadian provinces have joined RGGI as participants or observers. New Jersey is expected to rejoin RGGI, and the recently elected governors of Pennsylvania and Virginia have expressed interest in joining RGGI.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG in the region to 15% below 2005 levels by 2020.  These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, in November 2011, six states withdrew, leaving California and the four Canadian provinces as members. At a January 2012 stakeholder meeting, this group confirmed a commitment and timetable to create the largest carbon market in North America and provide a model to guide future efforts to establish national approaches in both Canada and the U.S. to reduce GHG emissions.  It is likely that these regional efforts will continue.

It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with coal production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs.  Such increased costs for coal consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, which could have a material adverse effect on our business, financial condition, and results of operations.

Water Discharge

The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations affect coal mining operations by imposing restrictions on effluent discharge into waters and the discharge of dredged or fill material into the waters of the U.S.  Regular monitoring, as well as compliance with reporting requirements and performance standards, is a precondition for the issuance and renewal of permits governing the discharge of pollutants into water.  Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of wetlands and streams.  The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact wetlands and streams.  Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies.  However, mitigation requirements under existing and possible future “fill” permits may vary considerably.  For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future. Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

The U.S. Army Corps of Engineers (“Corps of Engineers”) maintains two permitting programs under CWA Section 404 for the discharge of dredged or fill material: one for “individual” permits and a more streamlined program for “general” permits.  In June 2010, the Corps of Engineers suspended the use of “general” permits under Nationwide Permit 21 (“NWP 21”) in the Appalachian states.  In February 2012, the Corps of Engineers reissued the final 2012 NWP 21.  The Center for Biological Diversity later filed a notice of intent to sue the Corps of Engineers based on allegations the 2012 NWP 21 program violated the Endangered Species Act (“ESA”).  The Corps of Engineers and National Marine Fisheries Service (“NMFS”) have completed their programmatic ESA Section 7 consultation process on the Corps of Engineers’ 2012 NWP 21 package, and NMFS has issued a revised biological opinion finding that the NWP 21 program does not jeopardize the continued existence of threatened and endangered species and will not result in the destruction or adverse modification of designated critical habitat. However, the opinion contains 12 additional protective measures the Corps of Engineers will implement in certain districts to “enhance the protection of listed species and critical habitat.” While these measures will not affect previously verified permit activities where construction has not yet been completed, several Corps of Engineers districts with mining operations will be impacted by the additional protective measures going forward. These measures include additional reporting and notification requirements, potential imposition of new regional conditions and additional actions concerning cumulative effects analyses and mitigation.  Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments.  The CWA authorizes the EPA to review Section 404 permits issued by the Corps of Engineers, and in 2009, the EPA began reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia.  Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

The EPA also has statutory “veto” power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.”  In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a previously issued permit for Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia.  This action was the first time that such power was exercised with regard to a previously permitted coal mining project.  A challenge to the EPA’s exercise of this authority was made in the U.S. District Court for the District of Columbia, and in March 2012, that court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively.  In April 2013, the D.C. Circuit Court of Appeals reversed this decision and authorized the EPA to retroactively veto portions of a Section 404 permit.  The U.S. Supreme Court denied a request to review this decision.  Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to our continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal revenues.  In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on fictitious mine scenario. The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning. In June 2018, the EPA Administrator issued a memorandum directing the EPA's Office of Water to promulgate draft regulations eliminating the use of the EPA's Section 404 authority before a Section 404 permit application has been filed, or after a permit has been issued. To date, the EPA has not issued a proposed rule.

Total Maximum Daily Load (“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a pollutant that an impaired water body can receive and still meet state water quality standards and to allocate pollutant loads among the point and non-point pollutant sources discharging into that water body.  Likewise, when water quality in a receiving stream is better than required, states are required to conduct an antidegradation review before approving discharge permits. The adoption of new TMDL-related allocations or any changes to antidegradation policies for streams near our coal mines could require more costly water treatment and could adversely affect our coal production.

Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. A 2015 rulemaking by the EPA to revise the standard was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit and stayed for certain primarily western states by a United States District Court in North Dakota. In January 2018, the Supreme Court determined that the circuit courts do not have jurisdiction to hear challenges to the 2015 rule, removing the basis for the Sixth Circuit to continue its nationwide stay. Additionally, the EPA has promulgated a final rule that extends the applicability date of the 2015 rule for another two years in order to allow the EPA to undertake a rulemaking on the question of what constitutes a water of the United States. In the meantime, judicial challenges to the 2015 rulemaking are likely to continue to work their way through the courts along with challenges to the recent rulemaking that extends the applicability date of the 2015 rule. For now, the EPA and the Corps of Engineers will continue to apply the existing standard for what constitutes a water of the United States as determined by the Supreme Court in the Rapanos case and post-Rapanos guidance. Should the 2015 rule take effect, or should a different rule expanding the definition of what constitutes a water of the United States be promulgated as a result of the EPA and the Corps of Engineers' rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions. In December 2018, the EPA issued a proposed rule to revise the definition "to increase CWA program predictability and consistency by increasing clarity as to the scope of 'waters of the United States' federally regulated under the Act." Litigation surrounding these developments is ongoing and we cannot predict the outcome at this time.

Hazardous Substances and Wastes

The Federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), otherwise known as the “Superfund” law, and analogous state laws, impose liability, without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment.  These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site.  Persons who are or were responsible for the release of hazardous substances may be subject to joint and several liability under CERCLA for the costs of cleaning up releases of hazardous substances and natural resource damages.  Some products used in coal mining operations generate waste containing hazardous substances.  We are currently unaware of any material liability associated with the release or disposal of hazardous substances from our past or present mine sites.

The Federal Resource Conservation and Recovery Act (“RCRA”) and corresponding state laws regulating hazardous waste affect coal mining operations by imposing requirements for the generation, transportation, treatment, storage, disposal, and cleanup of hazardous wastes. Many mining wastes are excluded from the regulatory definition of hazardous wastes, and coal mining operations covered by SMCRA permits are by statute exempted from RCRA permitting. RCRA also allows the EPA to require corrective action at sites where there is a release of hazardous substances.  In addition, each state has its own laws regarding the proper management and disposal of waste material.  While these laws impose ongoing compliance obligations, such costs are not believed to have a material impact on our operations.

In June 2010, the EPA released a proposed rule to regulate the disposal of certain coal combustion by-products (“CCB”).  The proposed rule set forth two very different options for regulating CCB under RCRA.  The first option called for regulation of CCB as a hazardous waste under Subtitle C, which creates a comprehensive program of federally enforceable requirements for waste management and disposal.  The second option utilized Subtitle D, which would give the EPA authority to set performance standards for waste management facilities and would be enforced primarily through citizen suits.  The proposal leaves intact the Bevill exemption for beneficial uses of CCB.  In April 2012, several environmental organizations filed suit against the EPA to compel the EPA to take action on the proposed rule.  Several companies and industry groups intervened.  A consent decree was entered on January 29, 2014.

The EPA finalized the CCB rule on December 19, 2014, setting nationwide solid, nonhazardous waste standards for CCB disposal.  On April 17, 2015, the EPA finalized regulations under the solid waste provisions of Subtitle D of RCRA and not the hazardous waste provisions of Subtitle C which became effective on October 19, 2015.  The EPA affirms in the preamble to the final rule that “this rule does not apply to CCR placed in active or abandoned underground or surface mines.”  Instead, “the U.S. Department of Interior (“DOI”) and EPA will address the management of CCR in mine fills in a separate regulatory action(s).”   While classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers’ operating costs and potentially reduce their ability to purchase coal.

On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards (“ELG”), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. The combined effect of the CCR and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal-burning power plants that cannot comply with the new standards.  These regulations add costs to the operation of coal-burning power plants on top of other regulations like the 2014 regulations issued under Section 316(b) of the CWA that affects the cooling water intake structures at power plants in order to reduce fish impingement and entrainment.  Individually and collectively, these regulations could, in turn, impact the market for our products.  In April 2017, the EPA granted petitions for reconsideration and an administrative stay of all future compliance deadlines for the ELG rule.  In August 2017, the EPA granted petitions for reconsideration of the CCR rule. In July 2018, the EPA published a final rule to revise requirements and extend the deadlines from the 2015 rule. In August 2018, the DC Circuit issued a decision that imposed additional restrictions and addressed all remaining issues in the litigation on the 2015 CCR rule. This court decision could make it more difficult for the EPA to reform the 2015 rule.

 Endangered Species Act

The federal ESA and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from mining-related impacts.  If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered, we could be subject to additional regulatory and permitting requirements.

Other Environmental, Health and Safety Regulations

In addition to the laws and regulations described above, we are subject to regulations regarding underground and above ground storage tanks in which we may store petroleum or other substances.  Some monitoring equipment that we use is subject to licensing under the Federal Atomic Energy Act. Water supply wells located on our properties are subject to federal, state, and local regulation.  In addition, our use of explosives is subject to the Federal Safe Explosives Act.  We are also required to comply with the Federal Safe Drinking Water Act, the Toxic Substance Control Act, and the Emergency Planning and Community Right-to-Know Act.  The costs of compliance with these regulations should not have a material adverse effect on our business, financial condition or results of operations.

Suppliers

The main types of goods we purchase are mining equipment and replacement parts, steel-related (including roof control) products, belting products, lubricants, electricity, fuel, and tires.  Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers other than for purchases of electricity.  The supplier base providing mining materials has been relatively consistent in recent years. Purchases of certain underground mining equipment are concentrated with one principle supplier; however, supplier competition continues to develop.

Illinois Basin (ILB)

The coal industry underwent a significant transformation in the early 1990s, as greater environmental accountability was established in the electric utility industry.  Through the U.S. Clean Air Act, acceptable baseline levels were established for the release of sulfur dioxide in power plant emissions.  In order to comply with the new law, most utilities switched fuel consumption to low-sulfur coal, thereby stripping the ILB of over 50 million tons of annual coal demand.  This strategy continued until mid-2000 when a shortage of low-sulfur coal drove up prices.  This price increase combined with the assurance from the U.S. government that the utility industry would be able to recoup their costs to install scrubbers caused utilities to begin investing in scrubbers on a large scale.  With scrubbers, the ILB has re-opened as a significant fuel source for utilities and has enabled them to burn lower cost high sulfur coal.

The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana and western Kentucky.  The ILB is centrally located between four of the largest regions that consume coal as fuel for electricity generation (East North Central, West South Central, West North Central and East South Central).  The region also has access to sufficient rail and water transportation routes that service coal-fired power plants in these regions as well as other significant coal consuming regions of the South Atlantic and Middle Atlantic.

U. S. Coal Industry

The major coal production basins in the U.S. include Central Appalachia (CAPP), Northern Appalachia (NAPP), Illinois Basin (ILB), Powder River Basin (PRB) and the Western Bituminous region (WB). CAPP includes eastern Kentucky, Tennessee, Virginia and southern West Virginia. NAPP includes Maryland, Ohio, Pennsylvania and northern West Virginia.  The ILB includes Illinois, Indiana and western Kentucky. The PRB is located in northeastern Wyoming and southeastern Montana. The WB includes western Colorado, eastern Utah and southern Wyoming. Hallador, through its wholly-owned subsidiary Sunrise Coal, LLC, mines coal exclusively in the ILB.

Coal type varies by basin. Heat value and sulfur content are important quality characteristics and determine the end use for each coal type.

Coal in the U.S. is mined through surface and underground mining methods. The primary underground mining techniques are longwall mining and continuous (room-and-pillar) mining.  The geological conditions dictate which technique to use. Our mines utilize the continuous mining technique. In continuous mining, rooms are cut into the coal bed leaving a series of pillars, or columns of coal, to help support the mine roof and control the flow of air.  Continuous mining equipment cuts the coal from the mining face.  Generally, openings are driven 20’ wide, and the pillars are rectangular in shape measuring 40’x 40’.  As mining advances, a grid-like pattern of entries and pillars is formed.  Roof bolts are used to secure the roof of the mine.  Battery cars move the coal to the conveyor belt for transport to the surface. The pillars can constitute up to 50% of the total coal in a seam.

The United States coal industry is highly competitive, with numerous producers selling into all markets that use coal. We compete against large producers such as Peabody Energy Corporation (NYSE: BTU), Alliance Resource Partners (Nasdaq: ARLP), and other private producers.

Employees

We have 848 full-time employees and temporary miners, of which 842 are Sunrise Coal employees and temporary miners.  

Other

We have no significant patents, trademarks, licenses, franchises or concessions.

Our Denver office is located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504 and Sunrise Coal's corporate office is located at 1183 East Canvasback Drive, Terre Haute, Indiana 47802, phone 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis. Our website is www.halladorenergy.com.

ITEM 1A.    RISK FACTORS.

Risks Related to our Business

Global economic conditions or economic conditions in any of the industries in which our customers operate as well as sustained uncertainty in financial markets may have material adverse impacts on our business and financial condition that we currently cannot predict.

Weakness in global economic conditions or economic conditions in any of the industries we serve or in the financial markets could materially adversely affect our business and financial condition.  For example:

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:

Any adverse change in these factors could result in weaker demand and lower prices for our products.  A substantial or extended decline in coal prices could materially and adversely affect us by decreasing our revenues to the extent we are not protected by the terms of existing coal supply agreements.

Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

We compete with other coal producers for domestic coal sales in various regions of the U.S.  The most important factors on which we compete are delivered price (i.e., the cost of coal delivered to the customer, including transportation costs, which are generally paid by our customers either directly or indirectly), coal quality characteristics, contract flexibility (e.g., volume optionality and multiple supply sources) and reliability of supply.  Some competitors may have, among other things, larger financial and operating resources, lower per ton cost of production, or relationships with specific transportation providers.  The competition among coal producers may impact our ability to retain or attract customers and could adversely impact our revenues and cash from operations.   In addition, declining prices from an oversupply of coal in the market could reduce our revenues and cash from operations.

New tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.

New tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows. Recently, the Trump Administration imposed tariffs on steel and aluminum and a broad range of other products imported into the United States. In response to the tariffs imposed by the United States, the European Union, Canada, Mexico and China have announced tariffs on United States goods and services. The new tariffs, along with any additional tariffs or trade restrictions that may be implemented by the United States or retaliatory trade measures or tariffs implemented by other countries, could result in reduced economic activity, increased costs in operating our business, reduced demand and changes in purchasing behaviors, limits on trade with the United States or other potentially adverse economic outcomes. While tariffs and other retaliatory trade measures imposed by other countries on United States goods have not yet had a significant impact on our business or results of operations, we cannot predict further developments, and such existing or future tariffs could have a material adverse effect on our results of operations, financial position and cash flows and could reduce our revenues and cash available for distribution.

Changes in consumption patterns by utilities regarding the use of coal have affected our ability to sell the coal we produce.

According to the most recent information from the Energy Information Administration, since 2000, annual production for U.S. coal has fallen from 1.1 billion tons to 691 million tons.

The domestic electric utility industry accounts for ~93% of domestic coal consumption.  The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy.  Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators.

Future environmental regulation of GHG emissions also could accelerate a decline in coal demand.  In addition, state and federal mandates for increased use of electricity derived from renewable energy sources could affect demand for coal.  For example, to the extent implemented as originally finalized, the EPA’s CPP could likely incentivize additional electric generation from natural gas and renewable sources, and Congress has extended tax credits for renewables.  In addition, a number of states have enacted mandates that require electricity suppliers to rely on renewable energy sources in generating a certain percentage of power.  Such mandates, combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more competitive with coal.  A decrease in coal consumption by the domestic electric utility industry could adversely affect the price of coal, which could negatively impact our results of operations and reduce our cash from operations.

Extensive environmental laws and regulations affect coal consumers and have corresponding effects on the demand for coal as a fuel source.

Federal, state and local laws and regulations extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from coal-fired electric power plants, which are the ultimate consumers of much of our coal.  These laws and regulations can require significant emission control expenditures for many coal-fired plants, and various new and proposed laws and regulations may require further emission reductions and associated emission control expenditures.  These laws and regulations may affect demand and prices for coal.  There is also continuing pressure on state and federal regulators to impose limits on carbon dioxide emissions from electric power plants, particularly coal-fired power plants.  Further, far-reaching federal regulations promulgated by the EPA in the last several years, such as CSAPR and MATS, have led to the premature retirement of coal-fired generating units and a significant reduction in the amount of coal-fired generating capacity in the U.S. 

Increased regulation of GHG emissions could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for our products, decrease our revenues and reduce our profitability.

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere.  On December 15, 2009, the EPA published the Endangerment Finding asserting that emissions of carbon dioxide and other GHGs present an endangerment to public health and the environment, and the EPA has begun to regulate GHG emissions pursuant to the CAA.  The EPA previously finalized an NSPS to regulate GHG emissions from new power plants; however, the EPA published notice in the federal register in April 2017 that the agency has initiated a review of the NSPS for new and modified fossil fuel-fired power plants and that, following the review, the EPA will initiate reconsideration proceedings to suspend, revise or rescind this NSPS.  The finalized standard requires CCS, a technology that is not yet commercially feasible without government subsidies and that has not been demonstrated in the marketplace.  This requirement, to the extent implemented as originally finalized, effectively prevents construction of new coal-fired power plants. In December 2018, the EPA re-proposed the NSPS with a standard reflecting the performance of currently demonstrated supercritical technologies with an emission limit of 1,900 lbs. CO2/MWh for large units (heat input greater than 2,000 MMBtu/hour) and subcritical technologies with an emission limit of 2,000 lbs. CO2/MWh for small units. In August 2015, the EPA issued its final CPP rules that establish carbon pollution standards for existing power plants, called CO₂ emission performance rates.  Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the Circuit Court even issued a decision.  By its terms, this stay will remain in effect throughout the pendency of the appeals process including at the Circuit Court and the Supreme Court through any certiorari petition that may be granted.  The Supreme Court's stay applies only to the EPA's regulations for CO2 emissions from existing power plants and will not affect the EPA's standards for new power plants.  It is not yet clear how either the Circuit Court or the Supreme Court will rule on the legality of the CPP. Additionally, in October 2017 the EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time.   In connection with this proposed repeal, the EPA issued an ANPRM in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. In August 2018, the EPA proposed the ACE rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction." The ACE rule adopts new implementing regulations under the CAA to clarify the roles of the EPA and the states, including an extension of the deadline for state plans and EPA approvals; and, the rule revises the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements. If the effort to replace the NSPS and CPP is unsuccessful and the rules were upheld at the conclusion of this appellate process and were implemented in their current form, demand for coal would likely be further decreased, potentially significantly, and our business would be adversely impacted. Please read “Item 1. Business—Regulation and Laws—Air Emissions” and “—Carbon Dioxide Emissions.”

Numerous political and regulatory authorities and governmental bodies, as well as environmental activist groups, are devoting substantial resources to anti-coal activities to minimize or eliminate the use of coal as a source of electricity generation, domestically and internationally, thereby further reducing the demand and pricing for coal and potentially materially and adversely impacting our future financial results, liquidity and growth prospects.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate issues, are resulting in increased regulation of coal combustion in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events.  Numerous reports, such as the Fourth and Fifth Assessment Report of the Intergovernmental Panel on Climate Change, have also engendered concern about the impacts of human activity, especially fossil fuel combustion, on global climate issues. In turn, increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions of carbon dioxide from coal combustion by power plants.

Federal, state and local governments may pass laws mandating the use of alternative energy sources, such as wind power and solar energy, which may decrease demand for our coal products.  The CPP is one of a number of developments aimed at limiting GHG emissions which could limit the market for some of our products by encouraging electric generation from sources that do not generate the same amount of GHG emissions.  Enactment of laws or passage of regulations regarding emissions from the combustion of coal by the U.S., states, or other countries, could also result in electricity generators further switching from coal to other fuel sources or additional coal-fueled power plant closures.  For example, the agreement resulting from the 2015 United Nations Framework Convention on Climate Change contains voluntary commitments by numerous countries to reduce their GHG emissions and could result in additional firm commitments by various nations with respect to future GHG emissions.  These commitments could further disfavor coal-fired generation, particularly in the medium to long-term.

Internationally, a growing number of countries are passing new laws and regulations that could have an adverse impact on demand for coal. For example, China's latest five-year plan calls for reducing the share of coal in terms of the country's total energy consumption to 58 percent by 2020 from 64 percent in 2015. The plan also calls for China to increase the share of electricity it generates from nuclear and renewable energy sources to 20 percent. Separately, in Europe, multiple countries have announced their intent to phase out existing coal-fired power plants between 2025 and 2030. In addition, in December 2018, the European Union announced that it would be phasing out subsidies for coal plants unless facilities meet a performance standard of 550 grammes of CO2 per kilowatt hour. All of these developments have the potential to adversely impact demand for coal in international markets.

There have also been efforts in recent years affecting the investment community, including investment advisors, sovereign wealth funds, public pension funds, universities, and other groups, promoting the divestment of fossil fuel equities and also pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves.  In California, for example, legislation requires California’s state pension funds to divest investments in companies that generate 50% or more of their revenue from coal mining.  Other activist campaigns have urged banks to cease financing coal-driven businesses.  As a result, several major banks have enacted such policies.  The impact of such efforts may adversely affect the demand for and price of securities issued by us, and impact our access to the capital and financial markets.

In addition, several well-funded non-governmental organizations have explicitly undertaken campaigns to minimize or eliminate the use of coal as a source of electricity generation.  Collectively, these actions and campaigns could adversely impact our future financial results, liquidity and growth prospects.

Government regulations have resulted and could continue to result in significant retirements of coal-fired electric generating units.  Retirements of coal-fired electric generating units decrease the overall capacity to burn coal and negatively impact coal demand.

Since 2010, utilities have formally announced the retirement or conversion of over 600 coal-fired electric generating units through 2030.  These announced retirements and conversions amount to nearly 120,000 megawatts (“MW”) or approximately 40% of the 2010 total coal electric generating capacity.  As of 2018, it is estimated that a little over half of these announced retirements have been completed. Most of these retirements and conversions have been attributed to EPA regulations, although other factors such as an aging coal fleet and low natural gas prices have also played a role.  The reduction in coal electric capacity negatively impacts overall coal demand.  Additional regulations and other factors could lead to additional retirements and conversions and, thereby, additional reductions in the demand for coal.

We or our customers could be subject to tort claims based on the alleged effects of climate change.

In 2004, eight states and New York City sued five electric utility companies in Connecticut v. American Electric Power Co.  Invoking the federal and state common law of public nuisance; plaintiffs sought an injunction requiring defendants to abate their contribution to the nuisance of climate change by capping carbon dioxide emissions and then reducing them.  In June 2011, the U.S. Supreme Court issued a unanimous decision holding that the plaintiffs’ federal common law claims were displaced by federal legislation and regulations.  The U.S. Supreme Court did not address the plaintiffs’ state law tort claims and remanded the issue of preemption for the district court to consider.  While the U.S. Supreme Court held that federal common law provides no basis for public nuisance claims against utilities due to their carbon dioxide emissions, tort-type liabilities remain a possibility and a source of concern.  Proliferation of successful climate change litigation could adversely impact demand for coal and ultimately have a material adverse effect on our business, financial condition and results of operations.

The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do not extend existing or enter into new long-term contracts for coal.

In 2018, approximately 84% of our sales were under contracts having a term greater than one year, which we refer to as long-term contracts.  Long-term sales contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts.  From time to time industry conditions may make it more difficult for us to enter into long-term contracts with our electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time.  Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject a portion of our revenue stream to the increased volatility of the spot market.

Some of our long-term coal sales contracts contain provisions allowing for the renegotiation of prices and, in some instances, the termination of the contract or the suspension of purchases by customers.

Some of our long-term contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals.  These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins.  Accordingly, long-term contracts may provide only limited protection during adverse market conditions.  In some circumstances, failure of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.

Several of our long-term contracts also contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of certain events that are beyond the customer’s reasonable control.  Such events may include labor disputes, mechanical malfunctions and changes in government regulations, including changes in environmental regulations rendering use of our coal inconsistent with the customer’s environmental compliance strategies.  Additionally, most of our long-term contracts contain provisions requiring us to deliver coal within stated ranges for specific coal characteristics.  Failure to meet these specifications can result in economic penalties, rejection or suspension of shipments or termination of the contracts.  In the event of early termination of any of our long-term contracts, if we are unable to enter into new contracts on similar terms, our business, financial condition and results of operations could be adversely affected.

We depend on a few customers for a significant portion of our revenue, and the loss of one or more significant customers could affect our ability to maintain the sales volume and price of the coal we produce.

During 2018, we derived 82% of our revenue from four customers (10 power plants), with each of the four customers representing at least 10% of our coal sales.  With the addition of 8 new power plants that we began shipping to in 2018, we expect to reduce the concentration from customers representing at least 10% of our coal sales to 70% in 2019. If in the future we lose any of these customers without finding replacement customers willing to purchase an equivalent amount of coal on similar terms, or if these customers were to decrease the amounts of coal purchased or the terms, including pricing terms, on which they buy coal from us, it could have a material adverse effect on our business, financial condition and results of operations.

Litigation resulting from disputes with our customers may result in substantial costs, liabilities, and loss of revenues.

From time to time we have disputes with our customers over the provisions of long-term coal supply contracts relating to, among other things, coal pricing, quality, quantity and the existence of specified conditions beyond our or our customers’ control that suspend performance obligations under the particular contract.  Disputes may occur in the future, and we may not be able to resolve those disputes in a satisfactory manner, which could have a material adverse effect on our business, financial condition and results of operations. 

Our ability to collect payments from our customers could be impaired if their creditworthiness declines or if they fail to honor their contracts with us.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers.  If the creditworthiness of our customers declines significantly, our business could be adversely affected.  In addition, if a customer refuses to accept shipments of our coal for which they have an existing contractual obligation, our revenues will decrease, and we may have to reduce production at our mines until our customer’s contractual obligations are honored.

Our profitability may decline due to unanticipated mine operating conditions and other events that are not within our control and that may not be fully covered under our insurance policies.

Our mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines for varying lengths of time and, as a result, can diminish our profitability.  These conditions and events include, among others:

These conditions have the potential to significantly impact our operating results.  Prolonged disruption of production at any of our mines would result in a decrease in our revenues and profitability, which could materially adversely impact our quarterly or annual results.

Although none of our employees are members of unions, our workforce may not remain union-free in the future.

None of our employees are represented under collective bargaining agreements.  However, all of our workforce may not remain union-free in the future, and legislative, regulatory or other governmental action could make it more difficult to remain union-free.  If some or all of our currently union-free operations were to become unionized, it could adversely affect our productivity and increase the risk of work stoppages at our mining complexes.  In addition, even if we remain union-free, our operations may still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate boycotts against our operations.

Our mining operations are subject to extensive and costly laws and regulations, and such current and future laws and regulations could increase current operating costs or limit our ability to produce coal.

We are subject to numerous federal, state and local laws and regulations affecting the coal mining industry, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air and water quality standards, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge or release of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability.  Certain of these laws and regulations may impose strict liability without regard to fault or legality of the original conduct.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial liabilities, and the issuance of injunctions limiting or prohibiting the performance of operations.  Complying with these laws and regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations.  The possibility exists that new laws or regulations may be adopted, or that judicial interpretations or more stringent enforcement of existing laws and regulations may occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our mining operations, or indirect impacts that discourage or limit our customers’ use of coal.  Please read “Item 1. Business—Regulations and Laws.”

State and federal laws addressing mine safety practices impose stringent reporting requirements and civil and criminal penalties for violations.  Federal and state regulatory agencies continue to interpret and implement these laws and propose new regulations and standards.  Implementing and complying with these laws and regulations has increased and will continue to increase our operational expense and to have an adverse effect on our results of operation and financial position.  For more information, please read “Item 1. Business—Regulation and Laws—Mine Health and Safety Laws.”

We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash flow and profitability.

Mining companies must obtain numerous governmental permits or approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining.  The permitting rules are complex and can change over time.  Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance.  The public has the right to comment on permit applications and otherwise participate in the permitting process, including through court intervention.  Accordingly, permits required to conduct our operations may not be issued, maintained or renewed, or may not be issued or renewed in a timely fashion, or may involve requirements that restrict our ability to economically conduct our mining operations.  Limitations on our ability to conduct our mining operations due to the inability to obtain or renew necessary permits or similar approvals could reduce our production, cash flow, and profitability.  Please read “Item 1. Business—Regulations and Laws—Mining Permits and Approvals.”

The EPA has begun reviewing permits required for the discharge of overburden from mining operations under Section 404 of the CWA.  Various initiatives by the EPA regarding these permits have increased the time required to obtain and the costs of complying with such permits.  In addition, the EPA previously exercised its “veto” power to withdraw or restrict the use of previously issued permits in connection with one of the largest surface mining operations in Appalachia.  The EPA’s action was ultimately upheld by a federal court. As a result of these developments, we may be unable to obtain or experience delays in securing, utilizing or renewing Section 404 permits required for our operations, which could have an adverse effect on our results of operation and financial position.  Please read “Item 1. Business—Regulations and Laws—Water Discharge.”

In addition, some of our permits could be subject to challenges from the public, which could result in additional costs or delays in the permitting process, or even an inability to obtain permits, permit modifications or permit renewals necessary for our operations. 

Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or by impairing our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision.  Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources.  Disruption of transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks or other events could temporarily impair our ability to supply coal to our customers.  Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues.  If there are disruptions of the transportation services provided by our primary rail carriers that transport our coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country.  For instance, difficulty in coordinating the many eastern coal loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make coal shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than coal shipments originating in the western U.S.  Historically, high coal transportation rates from the western coal producing areas into certain eastern markets limited the use of western coal in those markets.  Lower rail rates from the western coal producing areas to markets served by eastern U.S. coal producers have created major competitive challenges for eastern coal producers.  In the event of further reductions in transportation costs from western coal producing areas, the increased competition with certain eastern coal markets could have a material adverse effect on our business, financial condition and results of operations.

It is possible that states in which our coal is transported by truck may modify or increase enforcement of their laws regarding weight limits or coal trucks on public roads.  Such legislation and enforcement efforts could result in shipment delays and increased costs.  An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and could adversely affect revenues.

We may not be able to successfully grow through future acquisitions.

We have expanded our operations by adding and developing mines and coal reserves in existing, adjacent and neighboring properties.  We continually seek to expand our operations and coal reserves.  Our future growth could be limited if we are unable to continue to make acquisitions, or if we are unable to successfully integrate the companies, businesses or properties we acquire.  We may not be successful in consummating any acquisitions and the consequences of undertaking these acquisitions are unknown.  Moreover, any acquisition could be dilutive to earnings. Our ability to make acquisitions in the future could require significant amounts of financing that may not be available to us under acceptable terms and may be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties or the lack of suitable acquisition candidates.

Expansions and acquisitions involve a number of risks, any of which could cause us not to realize the anticipated benefits.

If we are unable to successfully integrate the companies, businesses or properties we acquire, our profitability may decline, and we could experience a material adverse effect on our business, financial condition, or results of operations.  Expansion and acquisition transactions involve various inherent risks, including:

Any one or more of these factors could cause us not to realize the benefits anticipated to result from an expansion or acquisition. Any expansion or acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. In addition, future expansions or acquisitions could result in us assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous expansions and/or acquisitions.

Completion of growth projects and future expansion could require significant amounts of financing that may not be available to us on acceptable terms, or at all.

We plan to fund capital expenditures for our current growth projects with existing cash balances, future cash flows from operations, borrowings under credit facilities and cash provided from the issuance of debt or equity.  At times, weakness in the energy sector in general and coal, in particular, has significantly impacted access to the debt and equity capital markets.  Accordingly, our funding plans may be negatively impacted by this constrained environment as well as numerous other factors, including higher than anticipated capital expenditures or lower than expected cash flow from operations.  In addition, we may be unable to refinance our current debt obligations when they expire or obtain adequate funding prior to expiry because our lending counterparties may be unwilling or unable to meet their funding obligations.  Furthermore, additional growth projects and expansion opportunities may develop in the future that could also require significant amounts of financing that may not be available to us on acceptable terms or in the amounts we expect, or at all.

Various factors could adversely impact the debt and equity capital markets as well as our credit ratings or our ability to remain in compliance with the financial covenants under our then current debt agreements, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows.  If we are unable to finance our growth and future expansions as expected, we could be required to seek alternative financing, the terms of which may not be attractive to us, or to revise or cancel our plans.

The unavailability of an adequate supply of coal reserves that can be mined at competitive costs could cause our profitability to decline.

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. Because we deplete our reserves as we mine coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable.  Replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those of the depleting mines.  We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition.  Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

The estimates of our coal reserves may prove inaccurate and could result in decreased profitability.

The estimates of our coal reserves may vary substantially from actual amounts of coal we are able to recover economically. All of the reserves presented in this Annual Report on Form 10-K constitute proven and probable reserves.  There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond our control.  Estimates of coal reserves necessarily depend upon a number of variables and assumptions, any one of which may vary considerably from actual results.  These factors and assumptions relate to:

For these reasons, estimates of the recoverable quantities of coal attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of future net cash flows expected from these properties as prepared by different engineers, or by the same engineers at different times, may vary substantially. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates, and these variations may be material.  Any inaccuracy in the estimates of our reserves could result in higher than expected costs and decreased profitability.

Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of the U.S., which could affect the mining operations and cost structures of these areas.

The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them difficult and costly to mine.  As mines become depleted, replacement reserves may not be available when required or, if available, may not be mineable at costs comparable to those characteristic of the depleting mines.  In addition, permitting, licensing and other environmental and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy.  These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines.

Unexpected increases in raw material costs could significantly impair our operating profitability.

Our coal mining operations are affected by commodity prices.  We use significant amounts of steel, petroleum products, and other raw materials in various pieces of mining equipment, supplies and materials, including the roof bolts required by the room-and-pillar method of mining.  Steel prices and the prices of scrap steel, natural gas and coking coal consumed in the production of iron and steel fluctuate significantly and may change unexpectedly.  There may be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials.  Future volatility in the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant fluctuations in our profitability.

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations and, therefore, our ability to mine or lease coal.

Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required by state and federal law to have these bonds in place before mining can commence or continue, failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.

Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the U.S. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

Certain federal income tax deductions currently available with respect to coal mining and production may be eliminated as a result of future legislation.

In past years, members of Congress have indicated a desire to eliminate certain key U.S. federal income tax provisions currently applicable to coal companies, including the percentage depletion allowance with respect to coal properties.  No legislation with that effect has been proposed, but the elimination of those provisions would negatively impact our financial statements or results of operations.

Risks Related to Our Indebtedness and Liquidity

If we are unable to comply with the covenants contained in our credit agreement, the lenders could declare all amounts outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and operations.
 
As disclosed in Note 3 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a minimum debt service coverage ratio (consolidated adjusted EBITDA/annual debt service) of 1.25 to 1 and (ii) a maximum leverage ratio (consolidated funded debt/trailing twelve months adjusted EBITDA) not to exceed 3.75 to 1, which also decreases in future periods further reducing the maximum leverage permitted.  On December 31, 2018, our debt service coverage ratio was 2.12, and our leverage ratio was 2.55. Therefore, we were in compliance with these two ratios.

Our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.

On December 31, 2018, our debt was $188 million.  Our leverage may:

Various limitations in our debt agreements may reduce our ability to incur additional indebtedness, to engage in some transactions and to capitalize on business opportunities.  Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Risk Related to Possible Future Impairment Charge

Bulldog Reserves

In October 2017, we entered into an agreement to sell land associated with the Bulldog reserves for $4.9 million. As part of the transaction, we will hold the rights to repurchase the property for 8 years. Because of the likelihood of exercising the repurchase option, we are accounting for the sale as a financing transaction. The Bulldog assets had an aggregate net carrying value of $15 million at December 31, 2018. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. In October 2018, we paid the required fee and bond and the permit is expected to be issued in the near future. We have determined that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.

ITEM 1B.    UNRESOLVED STAFF COMMENTS. None.

ITEM 2.      PROPERTIES.

See Item 7 MDA for a discussion of our mines.

Coal Reserve Estimates

“Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves mean coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. “Proven (measured) reserves” are defined by Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. “Probable reserves” are defined by Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

Our reserve estimates are prepared by Scott McGuire, one of our mining engineers. Mr. McGuire is a licensed Professional Engineer in the State of Indiana and Kentucky and has seventeen years’ experience estimating coal reserves.

Standards set forth by the USGS were used to place areas of the mine reserves into the Proven (measured) and Probable (indicated) categories. Under these standards, coal within 1,320' of a data point is considered to be proven, and coal within 1,320' to 3,960' is placed in the Probable category. Only seams greater than 4’ in thickness are included in our underground reserves. All reserves are stated as a final salable product.

Prior to acquiring coal mineral leases, title abstractors conduct a preliminary title search on the property.  This information provides a strong indication of the coal owner, with whom we will enter into a lease. The next step is to execute a lease with the owner, giving us the rights to explore and mine the property.   Prior to mining, attorneys review the chain of mineral ownership to verify the lessor is the mineral owner. Prior to purchasing coal properties, we follow a similar process

ITEM 3.      LEGAL PROCEEDINGS.   None

ITEM 4.      MINE SAFETY DISCLOSURES:

Safety is a core value for us. As such we have dedicated a great deal of time, energy, and resources to creating a culture of safety. Thus, we are very proud of the mine rescue team at Sunrise Coal whose current list of achievements include 1^st place at the 2018 Indiana Mine Rescue Association Contest which was held in June 2018 and top 3 finishes at several other contests over the last year.

See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.

PART II

ITEM 5.      MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Stock Price Information

Our common stock is traded on the NASDAQ Capital Market under the symbol HNRG, and 35% is held by our officers, directors and their affiliates.

At March 8, 2019, we had 197 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.”  We estimate we have over 5,000 street name holders.

Equity Compensation Plan Information

See Note 5 to our consolidated financial statements.

ITEM 7.      MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

Our consolidated financial statements should be read in conjunction with this discussion. 

Overview

The largest portion of our business is devoted to coal mining in the State of Indiana through Sunrise Coal, LLC (a wholly-owned subsidiary) serving the electric power generation industry.  We also own a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method. Additionally, we own 100% of the Class A shares of Hourglass Sands, LLC (Hourglass), a frac sand mining company in the State of Colorado which has not yet commenced full-scale operations, and we are consolidating the activity of Hourglass in these statements.

We operate three underground coal mines and one surface coal mine in southwestern Indiana with the following capacities:

*  The Oaktown 1 & Oaktown 2 underground mines share a common surface facility.

** Oaktown 2 & Carlisle’s underground reserves are contiguous.

All mines have the ability to truck coal to our Princeton Rail Loop, located near Princeton, IN, which is located on the NS Railroad.

Our Coal Contracts

In 2018, Sunrise sold coal to 17 power plants in 8 different states. This is a dramatic increase in customers versus 2017 where Sunrise served 9 power plants in 3 states. The total estimated coal consumption of our 2018 customers is 165% greater than our 2017 customer base.

This increase in customers is the result of three fundamental changes in our market that have increased demand and reduced supply.

During 2018, we derived 82% of our revenue from four customers (10 power plants), with each of the four customers representing at least 10% of our coal sales.  With the addition of the eight new power plants that we began shipping to in 2018, we expect to reduce the concentration from customers representing at least 10% of our coal sales to 70% in 2019.

Our significant customers include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE: CNP), Duke Energy Corporation (NYSE: DUK), Hoosier Energy, an electric cooperative, Orlando Utility Commission (OUC), and Indianapolis Power & Light Company (IPL), a wholly-owned subsidiary of The AES Corporation (NYSE: AES).

Of our 2018 sales, 73% were shipped to locations in the State of Indiana. We anticipate our coal shipments utilizing the following modes of transportation in 2019:

2018 brought the return of long-term contracts. We were successful in signing multiple contracts ranging from 2-4 years in length. When looking at 2019 through 2022, we have 25.2 million tons sold. Thus, we have ~78% of our sales contracted over the next four years at an ~8.0 million-ton annualized pace. The table below reflects our projected tons.

*Contracted tons are subject to adjustment in instances of force majeure and exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.

We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. All customer plants are expected to be long-lived, with only one plant potentially being retired in 2023.

Vectren Corporation filed a petition on February 20, 2018 with the Indiana Utility Regulatory Commission (IURC) proposing to retire Culley Unit 2 and Brown Units 1 and 2 and replace the coal fired units with a new Combined Cycle Gas Turbine Generation Facility. The retirement of these units, if the petition is approved, would represent a reduction of ~1.1MM tons of Estimated Customer Demand starting in late 2023. The Sierra Club, Citizens Action Coalition, Indiana Office of Utility Consumer Counselor, Indiana Coal Council, Alliance Resource Partners and Sunrise Coal filed a petition with IURC requesting that Vectren’s request be denied.

Asset Impairment Review

See Note 2 to our consolidated financial statements.

Reserve Table - Controlled Tons (in millions):

Our assigned underground coal reserves are high sulfur (5.0# – 6.5#) with an average BTU content in the 11,400 -11,600 range. Our reserves have lower chlorine (<0.12%) than average ILB reserves of 0.22%.  Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%. The relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants. As discussed below, the Ace surface mine is low sulfur (~2.0#) with an average BTU content of 11,200. We have no metallurgical coal reserves, only steam (thermal) coal reserves. Below is a discussion of our current projects. Only seams greater than 4 feet in thickness are included in our underground reserves.

Our underground mines are room and pillar mines that utilize developed entries for ventilation and transportation. Continuous miners extract coal from rooms by removing coal from the seam, leaving pillars to support the roof.  Coal haulers are used to transport coal to a conveyor belt for transport to the surface.  

Oaktown 1 Mine (underground) – Assigned

We have 54.4 million controlled, salable tons of the Indiana #V coal seam. We began 2018 with 51.1 million tons controlled. The increase is a result of new drilling and new leases, after accounting for current year production. Oaktown 1 reserves are located in Knox County, IN.

Access to the Oaktown 1 Mine is via a 90-foot-deep box cut and a 2,200-foot slope, reaching coal in excess of 375 feet below the surface. In 2017, we added an elevator 7 miles from the slope allowing miners to enter closer to the active face, thereby reducing unproductive daily travel time.

Oaktown 2 Mine (underground) – Assigned

We have 43.4 million controlled, saleable tons of the Indiana #V coal seam. We began 2018 with 42.9 million controlled tons. The increase is a result of new drilling and new leases, after accounting for current year production. Oaktown 2 reserves are located in both Knox County, Indiana and Lawrence County, Illinois.

Access to the Oaktown 2 Mine is via an 80-foot-deep box cut and a 2,600-foot slope, reaching coal in excess of 400 feet below the surface.

The two Oaktown mines are separated by a sandstone channel.  The coal seam thickness ranges from 4 feet to over 9 feet.  The Oaktown mines share the same wash plant which is rated at 1,800 tons per hour.  The two mines are connected to a rail loadout that can store two 120 car trains at once and is serviced by the CSX Railroad and Indiana Railroad.  Coal is also transported via truck to customers.

Carlisle Mine (underground) – Assigned

We have 22.5 million controlled, saleable tons at our Carlisle Mine. We began 2018 with 27.3 million controlled tons. Besides production, the remainder of the decrease relates to tons that were deemed unrecoverable due to geologic and economic conditions based on new drilling. The mine is located near the town of Carlisle, Indiana in Sullivan County and became operational in January 2007. The coal is accessed with a slope to a depth of 340'. The coal is mined in the Indiana #V coal seam which is highly volatile bituminous coal and has been extensively mined by underground and surface methods in the general area. The coal thickness in the project area is 4' to 7'. The Carlisle Mine is completely developed, but was idle for the entirety of 2017. In July 2018, we restarted production at the Carlisle Mine.

Ace in the Hole Mine (Ace) (surface) – Assigned

We have .5 million controlled, saleable tons at our Ace mine. The Ace mine is near Clay City, Indiana in Clay County and 42 road miles northeast of the Carlisle Mine. The two primary seams are low sulfur coal (~2# SO₂), which make up the vast majority of the tons controlled.  Mine development began in late December 2012, and we began shipping coal in late August 2013.  We truck low sulfur coal from Ace to Oaktown and Carlisle to blend with high sulfur coal. Many utilities in the southeastern U.S. have scrubbers with lower sulfur limits (4.5# SO₂) which cannot accept the higher sulfur contents of the ILB (4.5# - 6.5# SO₂). Blending high sulfur coal to a lower sulfur specification enables us to market our high sulfur coals to more customers.

The Ace mine is a multi-seam open pit strip mine. The majority of the seams are sold raw, but some of the seams will be washed prior to sales depending on quality. To convert the tons sold raw, the in-place tonnage is multiplied by a pit recovery of 95% based on seam thickness. To convert the tons sold washed, the in-place tonnage is multiplied by a pit recovery based on seam thickness then reduced by the projected wash plant recovery of 78 to 100% depending on the seam.

Bulldog Reserves (underground) – Unassigned

We have leased roughly 19,300 acres in Vermilion County, Illinois near the village of Allerton.  Based on our reserve estimates we currently control 30.6 million tons of coal.  We began 2018 with 35.8 million controlled tons. The decrease is due to the expiration of a lease that may be renewed in the future. A considerable amount of our leased acres has yet to receive any exploratory drilling.

In October 2017, we entered into an agreement to sell land associated with the Bulldog reserves for $4.9 million. As part of the transaction, we will hold the rights to repurchase the property for eight years. Also in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. In October 2018, we paid the required fee and bond and the permit is expected to be issued in the near future.

Ace in the Hole Mine #2 Reserves (surface) – Unassigned

In 2018, we leased property giving us 1.0 million controlled, saleable tons at a new location 2 miles southwest of our Ace in the Hole mine. Mine development is expected to begin in early 2020.

Unassigned reserves represent coal reserves that would require new mineshafts, mining equipment, and plant facilities before operations could begin on the property. The primary reason for this distinction is to inform investors which coal reserves will require substantial capital expenditures before production can begin.

Below is a map that shows the locations of our coal mines.

Railroad Legend:

CSX – CSX Railroad

INRD – Indiana Rail Road

ISRR – Indiana Southern Railroad

NS – Norfolk Southern Railway

Mine and Wash Plant Recovery and Capacity

* Does not include out-of-seam material extracted during the mining process.

** Oaktown 1 and Oaktown 2 share the wash plant.

Liquidity and Capital Resources

As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $51.6 million and $65.8 million for the years ended December 31, 2018 and 2017 respectively.  We have increased our coal inventory by $6.4 million in anticipation of larger sales in 2019, to build a base of inventory at the Princeton Loop, and as a result of restarting production at the Carlisle mine. We have also increased our prepaid expense by $5.8 million with one of our vendors. Our capex budget for 2019 is $31 million, of which $22 million is for maintenance capex. We expect cash from operations for 2019 to fund our maintenance capital expenditures, debt service, and our dividend.

See Note 3 to our consolidated financial statements for discussion about our bank debt.

Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded reclamation obligations of $14.6 million, which are presented as asset retirement obligations (ARO) in our accompanying balance sheets. In the event we are not able to perform reclamation, we have surety bonds totaling $26 million to cover ARO.

Capital Expenditures (capex)

For the year ended December 31, 2018, our capex was $35.1 million allocated as follows (in millions):

Results of Operations

The following table presenting our quarterly results of operations should be read in conjunction with the consolidated financial statements and related notes included in Item 8 of this Form 10-K. We have prepared the unaudited information on the same basis as our audited consolidated financial statements. Our operating results for any quarter are not necessarily indicative of results for any future quarters or for a full year.

The following table presents our unaudited quarterly results of operations for the eight quarters ended December 31, 2018. This table includes all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair presentation of our consolidated operating results for the quarters presented.

Quarterly coal sales and cost data follow (in 000’s, except for per ton data and wash plant recovery percentage): 

2018 v. 2017

For 2018, we sold 7,365,000 tons at an average price of $39.62/ton. For 2017, we sold 6,574,000 tons an average price of $40.80/ton. The decrease in average price per ton was expected and is the result of our changing contract mix caused by the expiration of contracts and the acquisition of new contracts.

Operating costs for our coal mines averaged $29.18/ton and $28.92/ton for the year ended December 31, 2018 and 2017, respectively. With the restart of production at the Carlisle mine in July 2018, our operating costs have increased, but a second Carlisle unit was fully staffed in late December 2018 and costs have been dropping. Therefore, we expect operating costs for our coal mines to remain $28-$30/ton in 2019.

Operating costs associated for the idled Prosperity mine were $1.3 million and $1.1 million for the years ending December 31, 2018 and 2017, respectively. We expect operating costs to be $1.3 million in 2019.

DD&A increased approximately $5.7 million during 2018. A portion of our assets are depreciated based on raw production which has increased in 2018, thus as production increases so do our DD&A. Additionally, we began depreciating a new elevator at Oaktown 1 and assets relating to the Carlisle mine that had been idled since 2015.

SG&A expenses decreased approximately $3.1 million in 2018. In May 2017, a stock bonus totaling $3.8 million was awarded to company executives. No such award occurred in 2018. In March 2018, accelerated vesting of restricted stock units totaling $1.5 million occurred due to the passing of our former Chairman, Victor Stabio. We expect SG&A to be $10 million in 2019.

Interest expense increased approximately $3.9 million in 2018. The change in estimated fair value of our interest rate swap agreement during 2018 resulted in additional expense of $2.2 million. The remaining increase in interest expense is a result of amending our credit agreement in May 2018, which increased our effective fixed rate from 5% to 6%.

Our full-time Sunrise Coal employees and temporary miners totaled 842 at December 31, 2018, compared to 736 at December 31, 2017.

Current Projects

Hourglass Sands

In February 2018, we invested $4 million in Hourglass Sands, LLC, a frac sand mining company in the State of Colorado. In April 2018, we closed on the purchase of a commercial sand dryer and contracted with a third party to process our sand in Colorado Springs, Colorado.

We began producing raw sand in Colorado in June 2018. We shipped test shipments of sand in September 2018. We are excited about its growth potential in future years. Currently, we believe we control the only permitted frac sand mine in the State of Colorado.

Princeton Rail Loop

The Princeton loop, which provides access to new markets and customers, was completed and our first coal shipments were delivered to customers in May 2018. The facility is a truck to rail transload facility located six miles east of Princeton, Indiana and is capable of loading 135 car unit trains in less than four hours. The facility serves utility coal plants served by Norfolk Southern Railway Company. In 2018, we shipped 828,000 tons of coal from this facility.

MSHA Reimbursements

Some of our legacy coal contracts allow us to pass on to our customers certain costs incurred resulting from changes in costs to comply with mandates issued by MSHA or other government agencies. After applying the provisions of ASU 2014-09, as of December 31, 2018, we do not consider unreimbursed costs from our customers related to these compliance matters to be material and have constrained such amounts and will recognize them when they can be estimated with reasonable certainty.

Income Taxes

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (Tax Act). The Tax Act reduced the corporate tax rate to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 requires the effect of a change in tax laws or rates to be recognized as of the date of enactment, we were required to adjust deferred tax assets and liabilities as of December 22, 2017. Accordingly, we recorded a deferred income tax benefit of $16.4 million for the year ended December 31, 2017.

Our effective tax rate (ETR) for 2018 was (116)% compared to (138)% for 2017. The negative ETR in 2018 is due mostly to the statutory depletion deduction which is in excess of our book income. The negative ETR in 2017 is due primarily to the effects of the Tax Act adjustment to our deferred taxes and prior year tax return reconciliation which were all recorded discretely for the year ended December 31, 2017. The tax rate for the years ended December 31, 2018 and 2017 are not predictive of future tax rates due to the deferred income tax benefit of the Tax Act. The tax rate for 2017 would have been 9% without the effects of the deferred income tax benefit of the Tax Act and the prior year tax return reconciliation. Historically, our actual effective tax rates have been lower than the statutory effective rate primarily due to the benefit received from statutory depletion allowances. The deduction for statutory depletion does not necessarily change proportionately to changes in income before income taxes.

Critical Accounting Estimates

We believe that the estimates of our coal reserves, our business acquisitions, our interest rate swaps, our deferred tax accounts, and the estimates used in our impairment analysis are our only critical accounting estimates.

The reserve estimates are used in the DD&A calculation and in our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our DD&A expense and impairment test may be affected.

We account for business combinations using the purchase method of accounting. The purchase method requires us to determine the fair value of all acquired assets, including identifiable intangible assets and all assumed liabilities. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining whether an acquisition is considered to be a business or an asset acquisition, and if deemed to meet the definition of a business, the fair value of assets acquired and liabilities assumed requires management's judgment and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions, including assumptions with respect to future cash inflows and outflows, discount rates and asset lives, among other items.

The fair value of our interest rate swaps is determined using a discounted future cash flow model based on the key assumption of anticipated future interest rates.

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. 

New Accounting Standards

See “Item 8. Financial Statements – Note 1. Summary of Significant Accounting Policies” for a discussion of new accounting standards.

ITEM 8.  FINANCIAL STATEMENTS.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of 

Hallador Energy Company 

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheet as of December 31, 2018 and the related consolidated statement of comprehensive income, stockholders’ equity, and cash flows for the year ended December 31, 2018 and the related notes (collectively referred to as the “financial statements”) of Hallador Energy Company (the “Company”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO framework”).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018, and the results of its operations, and its cash flows of the Company for the year ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the COSO framework.

Basis for Opinion

The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s financial statements and an opinion on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

To the Shareholders and Board of Directors of

Hallador Energy Company

Our audits of the financial statements included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

We have served as the Company’s auditor since 2003.

Denver, Colorado  

March 11, 2019

REPORT OF INDEPENDENT PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of

Hallador Energy Company

1660 Lincoln Street, Suite 2700

Denver, CO 80234

OPINIONS ON THE CONSOLIDATED FINANCIAL STATEMENTS 

We have audited the accompanying consolidated balance sheet of Hallador Energy Company (the “Company”) as of December 31, 2017, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows, for each year in the two year period ended December 31, 2017, and the related notes and schedules (collectively referred to as the “financial statements”). 

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017, and the results of its operations and its cash flows for each year in the two year period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. 

BASIS FOR OPINIONS

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.

March 12, 2018

Denver, Colorado

PART I - FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

Hallador Energy Company

Consolidated Balance Sheets

As of December 31,

(in thousands, except per share data)

See accompanying notes.

Hallador Energy Company

Consolidated Statements of Comprehensive Income

For the years ended December 31,

(in thousands, expect per share data)

*There is no material difference between net income and comprehensive income.

See accompanying notes.

Hallador Energy Company

Consolidated Statements of Cash Flows

For the years ended December 31,

(in thousands)

See accompanying notes.

Hallador Energy Company

Consolidated Statement of Stockholders’ Equity

(in thousands)

*Accumulated Other Comprehensive Income (loss)

See accompanying notes.

HALLADOR ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)        Summary of Significant Accounting Policies

Basis of Presentation and Consolidation

The condensed consolidated financial statements include the accounts of Hallador Energy Company (hereinafter known as, “we, us, or our”) and its wholly-owned subsidiaries Sunrise Coal, LLC (Sunrise) and Hourglass Sands, LLC (Hourglass), and Sunrise’s wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated. Sunrise is engaged in the production of steam coal from mines located in western Indiana. Hourglass is in the development stage and is engaged in the production of frac sand in the State of Colorado (see Note 15).

Segment Information

The Company’s significant operating segments include the Oaktown and Carlisle underground mines located in southwestern Indiana.  The Company’s chief operating decision maker (“CODM”) reviews the operating results, assesses performance and makes decisions about allocation of resources to these segments at the mine level, however, we aggregate the results of operations of the mines for reporting purposes since the nature of the product, production process, customer type, product distribution, and long-term economic characteristics at each location are similar.

Allowance for Doubtful Accounts

The Company evaluates the need for an allowance for uncollectible receivables based on a review of account balances that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables and disputed amounts. Historically, credit losses have been insignificant. At December 31, 2018 and 2017, no allowance was recorded for uncollectible accounts receivable as all amounts were deemed collectible.

Inventory

Inventory and parts and supplies are valued at the lower of average cost or net realizable value.  Inventory costs include labor, supplies, operating overhead, and other related costs incurred at or on behalf of the mining location, including depreciation, depletion, and amortization of equipment, buildings, mineral rights, and mine development costs.

Prepaid expenses

Prepaid expenses include prepaid insurance, prepaid maintenance expense, and a prepaid balance with our primary parts and supplies vendor.

Advance Royalties

Coal leases that require minimum annual or advance payments and are recoverable from future production are generally deferred and charged to expense as the coal is subsequently produced. Advance royalties are included in other assets.

Mining Properties

Mining properties are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase the productivity of the assets are expensed as incurred.  Other than land and most mining equipment, mining properties are depreciated using the units-of-production method over the estimated recoverable reserves. Most surface and underground mining equipment is depreciated using estimated useful lives ranging from three to twenty-five years.

If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed for recoverability. If this review indicates that the carrying value of the asset will not be recoverable through estimated undiscounted future net cash flows related to the asset over its remaining life, then an impairment loss is recognized by reducing the carrying value of the asset to its estimated fair value. See Note 2 for further discussion of impairments.

Mine Development

Costs of developing new mines, including asset retirement obligation assets, or significantly expanding the capacity of existing mines, are capitalized and amortized using the units-of-production method over estimated recoverable reserves.

Asset Retirement Obligations (ARO) - Reclamation

At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair value, with a corresponding charge to mine development. Obligations are typically incurred when we commence development of underground and surface mines and include reclamation of support facilities, refuse areas and slurry ponds.

Obligations are reflected at the present value of their future cash flows.  We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proved and probable) reserves.  We are using discount rates ranging from 5.0% to 10%. Federal and state laws require that mines be reclaimed in accordance with specific standards and approved reclamation plans, as outlined in mining permits.  Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.

We review our ARO at least annually and reflect revisions for permit changes, changes in our estimated reclamation costs and changes in the estimated timing of such costs. In the event we are not able to perform reclamation, we have surety bonds totaling $26 million to cover ARO.

The table below (in thousands) reflects the changes to our ARO:

Statement of Cash Flows

Cash equivalents include investments with maturities, when purchased, of three months or less.

Income Taxes

Income taxes are provided based on the liability method of accounting.  The provision for income taxes is based on pretax financial income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between income tax and financial reporting and principally relate to differences in the tax basis of assets and liabilities and their reported amounts, using enacted tax rates in effect for the year in which differences are expected to reverse.

Net Income per Share

Basic net income per share is computed on the basis of the weighted average number of shares of common stock outstanding during the period using the two-class method for our common shares and RSUs which share in the Company’s earnings. Diluted net income per share is computed on the basis of the weighted average number of shares of common stock plus the effect of dilutive potential common shares outstanding during the period. Dilutive potential common shares include restricted stock units and are included in basic net income per share, using the two-class method. 

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting period.  Actual amounts could differ from those estimates.  The most significant estimates included in the preparation of the financial statements relate to: (i) deferred income tax accounts, (ii) coal reserves, (iii) depreciation, depletion, and amortization, (iv) estimates relating to interest rate swaps, and (v) estimates used in our impairment analysis.

Long-term Contracts

As of December 31, 2018, we are committed to supplying our customers up to a maximum of 30.5 million tons of coal through 2024 of which 20.7 million tons are priced.

For 2018, we derived 82% of our coal sales from four customers, each representing at least 10% of our coal sales. 77% of our accounts receivable were from five customers, each representing more than 10% of the December 31, 2018 balance.

For 2017, we derived 92% of our coal sales from five customers, each representing at least 10% of our coal sales. 83% of our accounts receivable were from four of these customers, each representing more than 10% of the December 31, 2017 balance.

Stock-based Compensation

Stock-based compensation is measured at the grant date based on the fair value of the award and is recognized as expense over the applicable vesting period of the stock award (generally two to four years) using the straight-line method.

New Accounting Standards Issued and Adopted

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU 2014-09 is a comprehensive revenue recognition standard that supersedes nearly all existing revenue recognition guidance under current U.S. GAAP and replaces it with a principle-based approach for determining revenue recognition. On January 1, 2018, we adopted the new accounting standard and all of the related amendments to all contracts using the modified retrospective method. Adoption of the new revenue standard did not result in a material cumulative effect adjustment to the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We do not expect the adoption of the new revenue standard to have a material impact to our net income on an ongoing basis, however we recognized revenue of $0.5 million over the course of the year related to MSHA costs that would have been recognized in a future period under the old standard. See “Note 14 - Revenue” to these consolidated financial statements for additional disclosures.

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments (Topic 825): Recognition and Measurement of Financial Assets and Financial Liabilities. ASU 2016-01 requires equity investments that are not accounted for under the equity method of accounting or that do not result in consolidation of the investee to be measured at fair value with changes recognized in net earnings. ASU 2016-01 also eliminates the available-for-sale classification for equity investments that recognized changes in fair value as a component of other comprehensive income. We adopted ASU 2016-01 on January 1, 2018, using the modified retrospective method, which resulted in a $1.1 million (net of tax) cumulative-effect adjustment from accumulated other comprehensive income to retained earnings. Adoption of ASU 2016-01 did not have a material impact on our results of operations and/or cash flows.

In November 2016, the FASB issued guidance regarding the presentation of restricted cash in the statement of cash flows (ASU 2016-18). This update is effective for annual reporting periods beginning after December 15, 2017, and early adoption is permitted. We have adopted the new standard as of January 1, 2018. Adoption of ASU 2016-18 did not have a material impact on the company’s results of operations and/or cash flows.

In January 2017, the FASB issued new guidance to assist in determining if a set of assets and activities being acquired or sold is a business (ASU 2017-01). It also provided a framework to assist entities in evaluating whether both an input and a substantive process are present, which at a minimum, must be present to be considered a business. We have adopted the new standard as of January 1, 2018. The standard does not have an impact on our historical recognition of asset acquisitions and business combinations. However, we expect there may be an impact on how we account for such acquisitions in the future. 

In February 2018, the FASB issued ASU 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. ASU 2018-02 allows companies to reclassify stranded tax effects resulting from the 2017 Tax Act from accumulated other comprehensive income to retained earnings. The company elected to early adopt ASU 2018-02 on January 1, 2018, which resulted in a reclassification of $192,000 of stranded tax effects, related to our unrealized gain on marketable securities, from accumulated other comprehensive income to retained earnings. Adoption of ASU 2018-02 did not have a material impact on our results of operations and/or cash flows.

New Accounting Standards Issued and Not Yet Adopted

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (ASU 2016-02). ASU 2016-02 increases transparency and comparability among organizations by requiring lessees to record right-to-use assets and corresponding lease liabilities on the balance sheet and disclosing key information about lease arrangements. The new guidance will classify leases as either finance or operating (similar to current standard’s “capital” or “operating” classification), with classification affecting the pattern of income recognition in the statement of income. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. The FASB continues to issue clarifications, updates and implementation guidance to ASU 2016-02 which we continue to monitor, such as ASU 2018-01, Leases (Topic 842) ("ASU 2018-01") and ASU 2018-11,  Leases (Topic 842) ("ASU 2018-11") which provides practical expedients for transition to Topic 842.  ASU 2018-01 allows for companies that did not previously recognize land easements as leases to continue this practice for existing leases but will still require the evaluation of new lease arrangements, including land easements.  ASU 2018-11 provides an option to apply the transition provisions of the new standard at its adoption date instead of at the earliest comparative period presented and permits lessors to not separate non-lease components from the associated lease component if certain conditions are met.  We will elect to apply this option at the adoption date.

We have completed our review of our current population of leases and continue our efforts to update the population for new leases. We have also developed internal controls and systems for our implementation and ongoing accounting for leases.  We will recognize lease liabilities and offsetting right-of-use assets of approximately $0.5 million in our consolidated balance sheets for operating leases upon adoption on January 1, 2019.

Subsequent Events

In January 2019, we declared a dividend of $.04 per share to shareholders of record as of January 31, 2019. The dividend was paid on February 15, 2019.

In January 2019, we sold our overriding royalty interests in certain producing oil properties in Southern Wyoming for $2.5 million and recognized a gain for the same amount.

(2)         Asset Impairment Review

Carlisle Mine

In July 2018, we restarted production at the Carlisle Mine and began shipping coal to customers. We conducted a review of the Carlisle Mine assets as of December 31, 2018, based on estimated future net cash flows, and determined that no impairment to the aggregate net carrying value of $107 million was necessary. If in future periods we reduce our estimate of the future net cash flows attributable to the Carlisle Mine, it may result in future impairment of such assets and such charges could be significant.

Bulldog Reserves

In October 2017, we entered into an agreement to sell land associated with the Bulldog reserves for $4.9 million. As part of the transaction, we hold the rights to repurchase the property for eight years at the original sale price of $4.9 million plus interest. We accounted for the sale as a financing transaction with the liability recorded in other long-term liabilities. The Bulldog assets had an aggregate net carrying value of $15 million at December 31, 2018. Also, in October 2017, the Illinois Department of Natural Resources (ILDNR) notified us that our mine application, along with modifications, was acceptable. In October 2018, we paid the required fee and bond and the permit is expected to be issued in the near future. We have determined that no impairment is necessary. If estimates inherent in the assessment change, it may result in future impairment of the assets.

(3)         Bank Debt

On May 21, 2018, we executed the Third Amended and Restated Credit Agreement with PNC, as administrative agent for our lenders. The $267 million credit facility is a combination of a $147 million term loan and $120 million revolver. The credit facility extends the term through May 21, 2022, reduces the debt service requirements, changes the borrower from Sunrise Coal to Hallador, and allows for investments in Hourglass Sands. The credit facility is collateralized primarily by Hallador’s assets. Our borrowing capacity increased by $6 million as of the effective date of the amended agreement.

Liquidity

Our bank debt at December 31, 2018, was $188 million (term - $130 million, revolver - $58 million). Our debt is recorded at cost which approximates fair value due to the variable interest rates in the agreement. As of December 31, 2018, we had additional borrowing capacity of $62 million and total liquidity of $80 million.

Fees

We incurred $5.7 million in debt issuance costs at the closing of the new credit facility that were added to our bank debt. Bank fees and other costs incurred in connection with the amended credit agreement and unamortized costs incurred in connection with the initial facility and a subsequent amendment totaled $8.8 million. These costs were deferred and are being amortized over the term of the loan. Unamortized costs as of December 31, 2018 and 2017, were $7.4 million and $3.0 million, respectively.

Covenants

The credit facility includes a Maximum Leverage Ratio (consolidated funded debt / trailing twelve months adjusted EBITDA), calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed the amounts below:

The credit facility also requires a Minimum Debt Service Coverage Ratio (consolidated adjusted EBITDA / annual debt service) calculated as of the end of each fiscal quarter for the trailing twelve months of 1.25 to 1 through the maturity of the credit facility.

At December 31, 2018, our Leverage Ratio was 2.55, and our Debt Service Coverage Ratio was 2.12. Therefore, we were in compliance with those two ratios.

Rate

The interest rate on the facility ranges from LIBOR plus 3.00% to LIBOR plus 4.50%, depending on our Leverage Ratio. We entered into swap agreements to fix the LIBOR component of the interest rate to achieve an effective fixed rate of ~6% on the original term loan balance and on $53 million of the revolver. At December 31, 2018, we are paying LIBOR of 2.52% plus 4.00% for a total interest rate of 6.52%.

Bank debt, less debt issuance costs, is presented below (in thousands):

(4)         Income Taxes (in thousands)

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (Tax Act). The Tax Act made broad and complex changes to the U.S. tax code including, but not limited to, (1) bonus depreciation that will allow for full expensing of qualified property; (2) reduction of the U.S. federal corporate tax rate; (3) elimination of the corporate alternative minimum tax; (4) a new limitation on deductible interest expense; (5) the repeal of the domestic production activity deduction; (6) limitations on the deductibility of certain executive compensation; and (7) limitations on net operating losses generated after December 31, 2017, to 80 percent of taxable income.

The SEC staff issued SAB 118, which provides guidance on accounting for the tax effects of the Tax Act. SAB 118 provides a measurement period that should not extend beyond one year from the Tax Act enactment date for companies to complete the accounting under ASC 740. In accordance with SAB 118, a company must reflect the income tax effects of those aspects of the Act for which the accounting under ASC 740 is complete. We completed the accounting for the tax effects of the Tax Act in December 2017.

The Tax Act reduced the corporate tax rate to 21 percent, effective January 1, 2018. Because ASC 740-10-25-47 required the effect of a change in tax laws or rates to be recognized as of the date of enactment, we were required to adjust deferred tax assets and liabilities as of December 22, 2017. Accordingly, we recorded a decrease related to our net deferred tax liability of $16.4 million, with a corresponding net adjustment to deferred income tax benefit of $16.4 million for the year ended December 31, 2017.

Our income tax is different than the expected amount computed using the applicable federal and state statutory income tax rates.  The reasons for and effects of such differences for the years ended December 31 are below: