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Section 1: 10-K (10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

 

 

 

[ x ]

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

 

 

For the fiscal year ended: December 31, 2019 OR

 

 

[      ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT O F 1934

 

 

 

Commission file number: 001‑3473

 

 

 

 

“COAL KEEPS YOUR LIGHTS ON”

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“COAL KEEPS YOUR LIGHTS ON”

 

HALLADOR ENERGY COMPANY

(www.halladorenergy.com)

 

 

 

Colorado

84-1014610

(State of incorporation)

(IRS Employer Identification No.)

 

 

1183 East Canvasback Drive, Terre Haute, Indiana

47802

(Address of principal executive offices)

(Zip Code)

 

Issuer’s telephone number: 303.839.5504

 

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

 

 

 

Title of each class

 

Trading Symbol(s)

 

Name of each exchange on which registered

Common Stock, $0.01 par value per share

 

HNRG

 

Nasdaq Capital Market

 

Securities registered pursuant to Section 12(g) of the Act: None

 

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15 (d) of the Act. Yes ☐ No☑

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

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

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

 

 

 

☐ Large accelerated filer

☑ Accelerated filer 

☐ Non-accelerated filer (do not check if a small reporting company)

☑ Smaller reporting company

 

☐ Emerging growth company

 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b‑2 of the Exchange Act). Yes ☐    No ☑

The aggregate market value of the common stock held by non-affiliates (public float) on June 28, 2019 was $113,764,353 based on the closing price reported that date by the NASDAQ of $5.51 per share.

As of March 6, 2020, we had 30,419,967, shares outstanding.    

Portions of our Proxy Statement to be filed with the SEC in connection with our annual stockholders’ meeting are incorporated by reference into Part III of this Form 10‑K.  Our Annual Meeting of Shareholders will be held on  May 29, 2020 in Terre Haute, IN.

 

 

 

 

FORWARD-LOOKING STATEMENTS

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

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changes in competition in coal markets and our ability to respond to such changes;

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changes in coal prices, which could affect our operating results and cash flows;

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risks associated with the expansion of our operations and properties;

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legislation, regulations, and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases, mining, miner health and safety, and health care;

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deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;

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dependence on significant customer contracts, including renewing customer contracts upon expiration of existing contracts;

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changing global economic conditions or in industries in which our customers operate;

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recent action and the possibility of future action on trade made by the United States and foreign governments;

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the effect of new tariffs and other trade measures;

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liquidity constraints, including those resulting from any future unavailability of financing;

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customer bankruptcies, cancellations or breaches to existing contracts, or other failures to perform;

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customer delays, failure to take coal under contracts or defaults in making payments;

·

adjustments made in price, volume or terms to existing coal supply agreements;

·

fluctuations in coal demand, prices, and availability;

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changes in oil & gas prices, which could, among other things, affect our investments in oil & gas mineral interests;

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our productivity levels and margins earned on our coal sales;

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changes in raw material costs;

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changes in the availability of skilled labor;

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our ability to maintain satisfactory relations with our employees;

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increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers’ compensation claims;

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increases in transportation costs and risk of transportation delays or interruptions;

·

operational interruptions due to geologic, permitting, labor, weather-related or other factors;

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risks associated with major mine-related accidents, mine fires, mine floods or other interruptions;

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results of litigation, including claims not yet asserted;

·

difficulty maintaining our surety bonds for mine reclamation;

·

decline in or change in the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels;

·

difficulty in making accurate assumptions and projections regarding post-mine reclamation;

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uncertainties in estimating and replacing our coal reserves;

·

the impact of current and potential changes to federal or state tax rules and regulations, including a loss or reduction of benefits from certain tax deductions and credits;

·

difficulty obtaining commercial property insurance;

·

evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;

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difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control; and

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other factors, including those discussed in “Item 1A. Risk Factors.”

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

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

ITEM 1.   BUSINESS.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our business.

Regulation and Laws

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

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employee health and safety;

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mine permits and other licensing requirements;

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air quality standards;

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water quality standards;

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storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could reach waterways or wetlands;

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plant and wildlife protection that could limit or prohibit mining or exploration;

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reclamation and restoration of mining properties after mining is completed;

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restricting the types, quantities and concentration of materials that can be released into the environment in the performance of mining or exploration and production activities;

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discharge of materials;

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storage and handling of explosives;

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wetlands protection;

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surface subsidence from underground mining; and

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the effects, if any, that mining has on groundwater quality and availability.

Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of strict, joint   and several liability, investigatory and remedial obligations and the issuance of injunctions limiting or prohibiting some or all of the operations on our properties. The regulatory burden on fossil fuel industries increases the cost of doing business and consequently affects profitability. The trend in environmental regulation has been to place more restrictions and limitations on activities that may  affect  the  environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly obligations could increase our or our mineral interest operators’ costs and adversely affect our performance.  In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has adversely affected demand for coal. It is possible that new legislation or regulations may be adopted, or that existing laws or regulations may be interpreted differently or more stringently enforced, any of which could have a significant impact on our mining operations or our customers’ ability to use coal. For more information, please see risk factors described in “Item 1A. Risk Factors” below.

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We are committed to conducting mining operations in compliance with applicable federal, state and local laws and regulations. However, because of the extensive and detailed nature of these regulatory requirements, particularly the regulatory system of the Mine Safety and Health Administration (“MSHA”) where citations can be issued without regard to fault, and many of the standards include subjective elements, it is not reasonable to expect any coal mining company to be free of citations. When we receive a citation, we attempt to remediate any identified condition immediately. While we have not quantified all of the costs of compliance with applicable federal and state laws and associated regulations, those costs have been and are expected to continue to be significant. Compliance with these laws and regulations has substantially increased the cost of coal mining for domestic coal producers.

Capital expenditures for environmental matters have not been material in recent years. We have accrued for the present value of the estimated cost of asset retirement obligations and mine closings, including the cost of treating mine water discharge, when necessary. The accruals for asset retirement obligations and mine closing costs are based upon permit requirements and the costs and timing of asset retirement obligations and mine closing procedures. Although management believes it has made adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if these accruals were insufficient.

Mining Permits and Approvals

Numerous governmental permits or approvals are required for mining operations. Applications for permits require extensive engineering and data analysis and presentation and must address a variety of environmental, health and safety matters associated with a proposed mining operation. These matters include the manner and sequencing of coal extraction, the storage, use and disposal of waste and other substances and impacts on the environment, the construction of water containment areas, and reclamation of the area after coal extraction. Meeting all requirements imposed by any of these authorities may be costly and may delay or prevent commencement or continuation of mining operations.

The permitting process for certain mining operations can extend over several years and can be subject to administrative and judicial challenge, including by the public. Some required mining permits are becoming increasingly difficult to obtain in a timely manner, or at all. We cannot assure you that we will not experience difficulty or delays in obtaining mining permits in the future or that a current permit will not be revoked.

We are required to post bonds to secure performance under our permits. Under some circumstances, substantial fines and penalties, including revocation of mining permits, may be imposed under the laws and regulations described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws and regulations. Regulations also provide that a mining permit can be refused or revoked if the permit applicant or permittee owns or controls, directly or indirectly through other entities, mining operations that have outstanding environmental violations. Although like other coal companies, we have been cited for violations in the ordinary course of our business, we have never had a permit suspended or revoked because of any violation, and the penalties assessed for these violations have not been material.

Mine Health and Safety Laws

Stringent safety and health standards have been imposed by federal legislation since the Federal Coal Mine Health, and Safety Act of 1969 (“CMHSA”) was adopted. The Federal Mine Safety and Health Act of 1977 (“FMSHA”), and regulations adopted pursuant thereto, significantly expanded the enforcement of health and safety standards of the CMHSA, and imposed extensive and detailed safety and health standards on numerous aspects of mining operations, including training of mine personnel, mining procedures, blasting, the equipment used in mining operations, and numerous other matters. MSHA monitors and rigorously enforces compliance with these federal laws and regulations. In addition, the states where we operate have state programs for mine safety and health regulation and enforcement. Federal and state safety and health regulations affecting the coal mining industry are perhaps the most comprehensive and rigorous system in the U.S. for protection of employee safety and have a significant effect on our operating costs. Although many of the requirements primarily impact underground mining, our competitors in all of the areas in which we operate are subject to the same laws and regulations.

FMSHA has been construed as authorizing MSHA to issue citations and orders pursuant to the legal doctrine of strict liability, or liability without fault, and FMSHA requires imposition of a civil penalty for each cited violation. Negligence and gravity assessments and other factors can result in the issuance of various types of orders, including orders requiring

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withdrawal from the mine or the affected area, and some orders can also result in the imposition of civil penalties. FMSHA also contains criminal liability provisions. For example, criminal liability may be imposed upon corporate operators who knowingly and willfully authorize, order or carry out violations of the FMSHA, or its mandatory health and safety standards.

The Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) significantly amended the FMSHA, imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:

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sealing off abandoned areas of underground coal mines;

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mine safety equipment, training, and emergency reporting requirements;

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substantially increased civil penalties for regulatory violations;

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training and availability of mine rescue teams;

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underground “refuge alternatives” capable of sustaining trapped miners in the event of an emergency;

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flame-resistant conveyor belts, fire prevention and detection, and use of air from the belt entry; and

·

post-accident two-way communications and electronic tracking systems.

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

In 2014, MSHA began implementation of a finalized new regulation titled “Lowering Miner’s Exposure to Respirable Coal Mine Dust, Including Continuous Personal Dust Monitors.”  The final rule implemented a reduction in the allowable respirable coal mine dust exposure limits, requires the use of sampling data taken from a single sample rather than an average of samples, and increases oversight by MSHA regarding coal mine dust and ventilation issues at each mine, including the approval process for ventilation plans at each mine, all of which increase mining costs. The second phase of the rule began in February 2016 and requires additional sampling for designated and other occupations using the new continuous personal dust monitor technology, which provides real-time dust exposure information to the miner. Phase three of the rule began in August 2016 and resulted in lowering the current respirable dust level of 2.0 milligrams per cubic meter to 1.5 milligrams per cubic meter of air. Compliance with these rules can result in increased costs on our operations, including, but not limited to, the purchasing of new equipment and the hiring of additional personnel to assist with monitoring, reporting, and recordkeeping obligations. MSHA has published a request for information regarding engineering controls and best practices to lower miners’ exposure to respirable coal mine dust, which is currently set to close on July 9, 2022. The comment period for this request for information will close on July 9, 2019. It is uncertain whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period for the current request for information.

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

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

Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA’s request for information. The comment period for the request for information was reopened and closed in January 2018.

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The comment period is scheduled to close in September 2020. It is uncertain whether MSHA will present a proposed rule pertaining to exposure of underground miners to diesel exhaust, after completing its evaluation of the comments received.

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

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

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

Black Lung Benefits Act

The Black Lung Benefits Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981 (“BLBA”) requires businesses that conduct current mining operations to make payments of black lung benefits to current and former coal miners with black lung disease and to some survivors of a miner who dies from this disease. The BLBA levied a tax on coal sales of $1.10 per ton for underground-mined coal and $0.55 per ton for surface-mined coal, but not to exceed 4.4% of the applicable sales price in order to compensate miners who are totally disabled due to black lung disease and some survivors of miners who died from this disease, and who were last employed as miners prior to 1970 or subsequently where no responsible coal mine operator has been identified for claims. In addition, the BLBA provides that some claims for which coal operators had previously been responsible are or will become obligations of the government trust funded by the tax. The Revenue Act of 1987 extended the termination date of this tax from January 1, 1996, to the earlier of January 1, 2014, or the date on which the government trust becomes solvent. The Emergency Economic Stabilization Act of 2008 extended these rates through December 31, 2018. On January 1, 2019, the excise tax rates reverted to their original 1977 statutory levels of $0.50 per ton for underground-mined coal and $0.25 per ton for surface mined coal, but not to exceed 2% of the applicable sales price.  In December 2019, the excise tax rates were increased to their 2018 levels and that rate increase is set to expire on December 31, 2020.

Workers’ Compensation and Black Lung

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

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

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

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Surface Mining Control and Reclamation Act

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

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

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

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

In April 2015, the United States Environmental Protection Agency ("EPA") finalized rules on coal combustion residuals ("CCRs"); however, the final rule does not address the placement of CCRs in minefills or non-minefill uses of CCRs at coal mine sites. OSM has announced their intention to release a proposed rule to regulate placement and use of CCRs at coal mine sites, but to date, no further action has been taken. These actions by OSM potentially could result in additional delays and costs associated with obtaining permits, prohibitions or restrictions relating to mining activities, and additional enforcement actions.

Bonding Requirements

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

Air Emissions

The CAA and similar state and local laws and regulations regulate emissions into the air and affect coal mining operations. The CAA directly impacts our coal mining and processing operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment, achieve certain emissions standards, or implement certain work practices on sources that emit various air pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric power generating plants and other coal-burning

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facilities. There have been a series of federal rulemakings focused on emissions from coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required under applicable federal and state laws and regulations related to air emissions will make it more costly to operate coal-fired power plants and possibly other facilities that consume coal and, depending on the requirements of individual state implementation plans (“SIPs”), could make fossil fuels a less attractive fuel alternative in the planning and building of power plants in the future. A significant reduction in fossil fuels’ share of power generating capacity could have a material adverse effect on our business, financial condition and results of operations. Since 2010, utilities have completed or formally announced the retirement or conversion of almost 700 coal-fired electric generating units through 2030 in the United States.

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

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The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric generating facilities. Sulfur dioxide is a by-product of coal combustion. Affected facilities purchase or are otherwise allocated sulfur dioxide emissions allowances, which must be surrendered annually in an amount equal to a facility’s sulfur dioxide emissions in that year. Affected facilities may sell or trade excess allowances to other facilities that require additional allowances to offset their sulfur dioxide emissions. In addition to purchasing or trading for additional sulfur dioxide allowances, affected power facilities can satisfy the requirements of the EPA’s Acid Rain Program by switching to lower-sulfur fuels, installing pollution control devices such as flue gas desulfurization systems, or “scrubbers,” or by reducing electricity generating levels. These requirements would not be supplanted by a replacement rule for the Clean Air Interstate Rule (“CAIR”), discussed below.

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The CAIR calls for power plants in 28 states and Washington, D.C. to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-trade program similar to the system in effect for acid rain. In June 2011, the EPA finalized the Cross-State Air Pollution Rule (“CSAPR”), a replacement rule for CAIR, which would have required 28 states in the Midwest and eastern seaboard to reduce power plant emissions that cross state lines and contribute to ozone and/or fine particle pollution in other states. CSAPR has become increasingly irrelevant with continuing coal plant retirements making the nitrogen oxide ozone budget less stringent and lowering emission allowance prices to levels closer to average operating cost for many of our customers.  The full impact of CSAPR are unknown at the present time due to the implementation of Mercury and Air Toxic Standards ("MATS"), discussed below, and the impact of the continuing coal plant retirements.

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In February 2012, the EPA adopted the MATS, which regulates the emission of mercury and other metals, fine particulates, and acid gases such as hydrogen chloride from coal and oil-fired power plants. In March 2013, the EPA finalized a reconsideration of the MATS rule as it pertains to new power plants, principally adjusting emissions limits to levels attainable by existing control technologies. In subsequent litigation, the U.S. Supreme Court struck down the MATS rule based on the EPA’s failure to take costs into consideration.  The D.C. Circuit Court allowed the current rule to stay in place until the EPA issued a new finding.  In April 2016, the EPA issued a final supplemental finding upholding the rule and concluding that a cost analysis supports the MATS rule. In April 2017, the D.C Circuit Court of Appeals granted the EPA’s request to cancel oral arguments and ordered the case held in abeyance for an EPA review of the supplemental finding. In December 2018, the EPA issued a proposed Supplemental Cost Finding, as well as the CAA required "risk and technology review."  Many electric generators have already announced retirements due to the MATS rule. Although various issues surrounding the MATS rule remain subject to litigation in the D.C. Circuit, the MATS rule has forced generators to make capital investments to retrofit power plants and could lead to additional premature retirements of older coal-fired generating units. The announced and possible additional retirements are likely to reduce the demand for coal. Apart from MATS, several states have enacted or proposed regulations requiring reductions in mercury emissions from coal-fired power plants, and federal legislation to reduce mercury emissions from power plants has been proposed. Regulation of mercury emissions by the EPA, states, or Congress may decrease the future demand for coal. We continue to evaluate the possible scenarios associated with CSAPR and MATS and the effects they may have on our business and our results of operations, financial condition or cash flows.

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The EPA is required by the CAA to periodically re-evaluate the available health effects information to determine whether the National Ambient Air Quality Standards (“NAAQS”) should be revised. Pursuant to this process, the EPA has adopted more stringent NAAQS for fine particulate matter (“PM”), ozone, nitrogen oxide, and sulfur dioxide. As a result, some states will be required to amend their existing SIPs to attain and maintain compliance with the new air quality standards and other states will be required to develop new SIPs for areas that were previously in “attainment” but do not attain the new standards. In addition, under the revised ozone NAAQS, significant additional emissions control expenditures may be required at coal-fired power plants. Initial non-attainment determinations related to the revised sulfur dioxide standard became effective in October 2013. In addition, in January 2013, the EPA updated the NAAQS for fine particulate matter emitted by a wide variety of sources including power plants, industrial facilities, and gasoline and diesel engines, tightening the annual PM 2.5 standard to 12 micrograms per cubic meter. The revised standard became effective in March 2013. In November 2013, the EPA proposed a rule to clarify PM 2.5 implementation requirements to the states for current 1997 and 2006 non-attainment areas. In July 2016, the EPA issued a final rule for states to use in creating their plans to address particulate matter. In October 2015, the EPA published a final rule that reduced the ozone NAAQS from 75 to 70 ppb and completed attainment/non-attainment designations in July 2018.  In March 2019, the EPA published a final rule that retained the current primary NAAQS for sulfur oxide.  New standards may impose additional emissions control requirements on new and expanded coal-fired power plants and industrial boilers. Because coal mining operations and coal-fired electric generating facilities emit particulate matter and sulfur dioxide, our mining operations and our customers could be affected when the new standards are implemented by the applicable states, and developments might indirectly reduce the demand for coal.

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The EPA’s regional haze program is designed to protect and improve visibility at and around national parks, national wilderness areas, and international parks. Under the program, states are required to develop SIPs to improve visibility. Typically, these plans call for reductions in sulfur dioxide and nitrogen oxide emissions from coal-fueled electric plants. In prior cases, the EPA has decided to negate the SIPs and impose stringent requirements through FIPs. The regional haze program, including particularly the EPA’s FIPs, and any future regulations may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas and may require some existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions. These requirements could limit the demand for coal in some locations. In September 2018, the EPA issued a memorandum that detailed plans to assist states as they develop their SIPs.

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The EPA’s new source review (“NSR”) program under the CAA in certain circumstances requires existing coal-fired power plants, when modifications to those plants significantly increase emissions, to install more stringent air emissions control equipment. The Department of Justice, on behalf of the EPA, has filed lawsuits against a number of coal-fired electric generating facilities alleging violations of the NSR program. The EPA has alleged that certain modifications have been made to these facilities without first obtaining certain permits issued under the program. Several of these lawsuits have settled, but others remain pending. In addition, there are proposals to modify the NSR program as a part of the Affordable Clean Energy ("ACE") rule which is subject to current pending litigation as discussed below. A final rule on NSR reforms is expected in March 2020.  Depending on the ultimate resolution of these cases, demand for coal could be affected.

GHG Emissions

Combustion of fossil fuels, such as the coal we produce, results in the emission of GHGs, such as carbon dioxide and methane. Combustion of fuel for mining equipment used in coal production also emits GHGs. Future regulation of GHG emissions in the U.S. could occur pursuant to future U.S. treaty commitments, new domestic legislation or regulation by the EPA.  Congress has considered various proposals to reduce GHG emissions, and it is possible federal legislation could be adopted in the future. Internationally, there is an international climate agreement (“Paris Agreement”) that does not create any binding obligations for nations to limit their GHG emissions but includes pledges to voluntarily limit or reduce future emissions. These commitments could further reduce demand and prices for fossil fuels. In November 2019, the United States announced its withdrawal from such agreement, effective November 4, 2020.  However, the United States may subsequently decide to rejoin the Paris Agreement or another agreement at some point in the future.  Moreover, many states, regions and governmental bodies have adopted GHG initiatives and have or are considering the imposition of fees or taxes based on the emission of GHGs by certain facilities, including coal-fired electric generating

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facilities. Others have announced their intent to increase the use of renewable energy sources, displacing coal and other fossil fuels. Depending on the particular regulatory program that may be enacted, at either the federal or state level, the demand for coal could be negatively impacted, which would have an adverse effect on our operations.

Even in the absence of new federal legislation, the EPA has begun to regulate GHG emissions under the CAA based on the U.S. Supreme Court’s 2007 decision that the EPA has authority to regulate GHG emissions. Although the U.S. Supreme Court’s holding did not expressly involve the EPA’s authority to regulate GHG emissions from stationary sources, such as coal fueled power plants, the EPA has determined on its own that it has the authority to regulate GHG emissions from power plants and issued a final rule which found that GHG emissions, including carbon dioxide and methane, endanger both the public health and welfare.

On September 20, 2013, the EPA issued NSPS for carbon dioxide emissions from new fossil fuel-fired power plants.  This rule was finalized in 2015 and was immediately challenged by multiple parties.  In August 2017, this rule was stayed by a federal appeals court to allow the Trump administration’s EPA to review the NSPS rule. It is likely than any repeal or revisions to the NSPS will be subject to legal challenges as well. Future implementation of the NSPS is uncertain at this time.

In August 2015, the EPA issued its final Clean Power Plan ("CPP") rules that establish carbon pollution standards for power plants, called CO2 emission performance rates. Judicial challenges led the U.S. Supreme Court to grant a stay in February 2016 of the implementation of the CPP before the United States Court of Appeals for the District of Columbia ("Circuit Court") even issued a decision. Additionally, in October 2017 the EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time.  The EPA subsequently proposed the ACE rule to replace the CPP with a rule that utilizes heat rate improvement measures as the "best system of emission reduction." The ACE rule adopts new implementing regulations under the CAA to clarify the roles of the EPA and the states, including an extension of the deadline for state plans and EPA approvals; and, the rule revises the NSR permitting program to provide EGUs the opportunity to make efficiency improvements without triggering NSR permit requirements. In June 2019, the EPA published the final repeal of the Clean Power Plan and promulgation of the ACE rule.  The EPA’s attempts to replace the CPP with the ACE rule are currently subject to litigation, and we cannot predict the final outcome.

Notwithstanding the ACE rule, these requirements have led to premature retirements and could lead to additional premature retirements of coal-fired generating units and reduce the demand for coal. Congress has not currently adopted legislation to restrict carbon dioxide emissions from existing power plants, and it is unclear whether the EPA has the legal authority to regulate carbon dioxide emissions from existing and modified power plants as proposed in the NSPS and CPP. Substantial limitations on GHG emissions could adversely affect demand for the coal we produce.

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

In addition, environmental advocacy groups have filed a variety of judicial challenges claiming that the environmental analyses conducted by federal agencies before granting permits and other approvals necessary for certain coal activities do not satisfy the requirements of the National Environmental Policy Act (“NEPA”). These groups assert that the environmental analyses in question do not adequately consider the climate change impacts of these particular projects. In

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January 2020, CEQ issued a proposed revision to NEPA regulations that seeks to clarify the extent to which direct, indirect, and cumulative environmental impacts from a proposed project, including GHG emissions, should be examined under NEPA; however, the final form or impact of any such revisions is uncertain at this time.

Many states and regions have adopted GHG initiatives, and certain governmental bodies have or are considering the imposition of fees or taxes based on the emission of GHG by certain facilities, including coal-fired electric generating facilities. For example, in 2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement (“RGGI”), calling for implementation of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of RGGI have established in statutes and/or regulations a carbon dioxide trading program. Auctions for carbon dioxide allowances under the program began in September 2008. Since its inception, several additional northeastern states and Canadian provinces have joined RGGI as participants or observers. In 2019, New Jersey and Pennsylvania each announced they were joining RGGI.

Following the RGGI model, five Western states launched the Western Regional Climate Action Initiative to identify, evaluate, and implement collective and cooperative methods of reducing GHG in the region to 15% below 2005 levels by 2020. These states were joined by two additional states and four Canadian provinces and became collectively known as the Western Climate Initiative Partners. However, as of 2020, only California and the Canadian provinces of British Columbia, Novia Scotia and Quebec remain.  Nevertheless, it is likely that these regional efforts will continue based on current trends and concerns related to the reduction of GHG emissions.

It is possible that future international, federal and state initiatives to control GHG emissions could result in increased costs associated with fossil fuel production and consumption, such as costs to install additional controls to reduce carbon dioxide emissions or costs to purchase emissions reduction credits to comply with future emissions trading programs. Such increased costs for fossil fuel consumption could result in some customers switching to alternative sources of fuel, or otherwise adversely affect our operations and demand for our products, which could have a material adverse effect on our business, financial condition, and results of operations.  Finally, activists may try to hamper fossil fuel companies by other means, including pressuring financing and other institutions into restricting access to capital, bonding and insurance, as well as pursuing tort litigation for various alleged climate-related impacts.

Water Discharge

The Federal Clean Water Act (“CWA”) and similar state and local laws and regulations regulate discharges into certain waters, primarily through permitting. Section 404 of the CWA imposes permitting and mitigation requirements associated with the dredging and filling of certain wetlands and streams. The CWA and equivalent state legislation, where such equivalent state legislation exists, affect coal mining operations that impact such wetlands and streams. Although permitting requirements have been tightened in recent years, we believe we have obtained all necessary permits required under CWA Section 404 as it has traditionally been interpreted by the responsible agencies. However, mitigation requirements under existing and possible future “fill” permits may vary considerably. For that reason, the setting of post-mine asset retirement obligation accruals for such mitigation projects is difficult to ascertain with certainty and may increase in the future.  Although more stringent permitting requirements may be imposed in the future, we are not able to accurately predict the impact, if any, of such permitting requirements.

In order for us to  conduct certain activities, an operator may need to obtain a permit for the discharge of fill material from the United States Army Corps of Engineers ("Corps of Engineers") and/or a discharge permit from the   state regulatory authority under the state counterpart to the CWA. Our coal mining operations typically require Section 404 permits to authorize activities such as the creation of slurry ponds and stream impoundments. The CWA authorizes the EPA to review Section 404 permits issued by the Corps of Engineers, and in 2009, the EPA began reviewing Section 404 permits issued by the Corps of Engineers for coal mining in Appalachia. Currently, significant uncertainty exists regarding the obtaining of permits under the CWA for coal mining operations in Appalachia due to various initiatives launched by the EPA regarding these permits.

The EPA also has statutory “veto” power over a Section 404 permit if the EPA determines, after notice and an opportunity for a public hearing, that the permit will have an “unacceptable adverse effect.”  In January 2011, the EPA exercised its veto power to withdraw or restrict the use of a previously issued permit for Spruce No. 1 Surface Mine in West Virginia, which is one of the largest surface mining operations ever authorized in Appalachia. This action was the first time that such power was exercised with regard to a previously permitted coal mining project. A challenge to the EPA’s exercise of

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this authority was made in the U.S. District Court for the District of Columbia, and in March 2012, that court ruled that the EPA lacked the statutory authority to invalidate an already issued Section 404 permit retroactively. In April 2013, the D.C. Circuit Court of Appeals reversed this decision and authorized the EPA to retroactively veto portions of a Section 404 permit. The U.S. Supreme Court denied a request to review this decision. Any future use of the EPA’s Section 404 “veto” power could create uncertainty with regard to our continued use of current permits, as well as impose additional time and cost burdens on future operations, potentially adversely affecting our coal revenues. In addition, the EPA initiated a preemptive veto prior to the filing of any actual permit application for a copper and gold mine based on fictitious mine scenario. The implications of this decision could allow the EPA to bypass the state permitting process and engage in watershed and land use planning. In June 2018, the EPA Administrator issued a memorandum directing the EPA’s Office of Water to promulgate draft regulations eliminating the use of the EPA’s Section 404 authority before a Section 404 permit application has been filed, or after a permit has been issued. To date, the EPA has not issued a proposed rule.

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

Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. A 2015 rulemaking by the EPA to revise the standard was quickly challenged and nationwide implementation was blocked by a federal appeals court.  Should the 2015 rule take effect, or should a different rule expanding the definition  of what constitutes a water of the United States be promulgated as a result of the EPA and the Corps of Engineers' rulemaking process, we could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions. In December 2018, the EPA and the Corps of Engineers issued a proposed rule to “determine the scope of ‘waters of the United States’” subject to federal jurisdiction.  This proposal would lessen the number of waterbodies subject to the CWA as compared to the 2015 Rule.  In January 2020, the EPA finalized its rule regarding the scope of Waters of the United States”. Litigation surrounding these developments is ongoing and we cannot predict the outcome at this time.

Hazardous Substances and Wastes

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

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

RCRA impacts the coal industry in particular because it regulates the disposal of certain coal combustion by-products (“CCB”). On April 17, 2015, the EPA finalized regulations under RCRA for the disposal of CCB. Under the finalized regulations, CCB is regulated as "non-hazardous" waste and avoids the stricter, more costly, regulations under RCRA's hazardous waste rules. While classification of CCB as a hazardous waste would have led to more stringent restrictions and higher costs, this regulation may still increase our customers’ operating costs and potentially reduce their ability to purchase coal.

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On November 3, 2015, the EPA published the final rule Effluent Limitations Guidelines and Standards (“ELG”), revising the regulations for the Steam Electric Power Generating category which became effective on January 4, 2016. The rule sets the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the steam electric power industry over the last three decades. The combined effect of the CCB and ELG regulations has forced power generating companies to close existing ash ponds and will likely force the closure of certain older existing coal-burning power plants that cannot comply with the new standards. In November 2019, the EPA proposed revisions to the 2015 ELG rule and announced proposed changes to regulations for the disposal of coal ash in order to reduce compliance costs.   It is unclear what impact   these regulations will have on the market for our products.

Endangered Species Act

The federal Endangered Species Act (“ESA”) and counterpart state legislation protect species threatened with possible extinction. The U.S. Fish and Wildlife Service (the “USFWS”) works closely with the OSM and state regulatory agencies to ensure that species subject to the ESA are protected from potential impacts from mining-related activities. If the USFWS were to designate species indigenous to the areas in which we operate as threatened or endangered, or to re-designate a species from threatened to endangered, we could be subject to additional regulatory and permitting requirements, which in turn could increase operating costs or adversely affect our revenues.

Other Environmental, Health and Safety Regulations

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

Suppliers

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

Illinois Basin (ILB)

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

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

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U. S. Coal Industry

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

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

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

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

Employees

As of December 31, 2019, we had 915 full-time employees and temporary miners, of which 907 are Sunrise Coal employees and temporary miners.  With the closing of the Carlisle Mine, our head count has been reduced to 768.

Other

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

Our corporate office is located at 1183 East Canvasback Drive, Terre Haute, Indiana, 47802, phone 303.839.5504 and Sunrise Coal’s corporate office is at the same location, phone 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis.

ITEM 1A. RISK FACTORS.

Risks Related to our Business

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

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

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the demand for electricity in the U.S. and globally may decline if economic conditions deteriorate, which may negatively impact the revenues, margins, and profitability of our business;

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any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and

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our future ability to access the capital markets may be restricted as a result of future economic conditions, which could materially impact our ability to grow our business, including development of our coal reserves.

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A substantial or extended decline in coal prices could negatively impact our results of operations.

Our results of operations are primarily dependent upon the prices we receive for our coal, as well as our ability to improve productivity and control costs. The prices we receive for our production depends upon factors beyond our control, including:

the supply of and demand for domestic and foreign coal;

weather conditions and patterns that affect demand for or our ability to produce coal;

the proximity to and capacity of transportation facilities;

competition from other coal suppliers;

domestic and foreign governmental regulations and taxes;

the price and availability of alternative fuels;

the effect of worldwide energy consumption, including the impact of technological advances on energy consumption;

overall domestic and global economic conditions;

international developments impacting supply of coal; and

the impact of domestic and foreign governmental laws and regulations, including environmental and climate change regulations and regulations affecting the coal mining industry and coal-fired power plants, and delays in the receipt of, failure to receive, failure to maintain or revocation of necessary governmental permits.

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

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

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

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

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

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

According to the most recent information from the Energy Information Administration, since 2000, coal's share of United States electricity production has fallen from 53% to 24%, while natural gas' share has increased from 16% to 39%.

The domestic electric utility industry accounts for ~92% of domestic coal consumption. The amount of coal consumed by the domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other

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governmental regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as alternative sources of energy. Gas-fueled generation has the potential to displace coal-fueled generation, particularly from older, less efficient coal-powered generators.  We expect that many of the new power plants needed in the United States to meet increasing demand for electricity generation will be fueled by natural gas because gas-fired plants are cheaper to construct and permits to construct these plants are easier to obtain.

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

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

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

Increased regulation to address climate change (particularly GHG emissions) and uncertainty regarding such regulation could result in increased operating costs and reduced demand for coal as a fuel source, which could reduce demand for our products, decrease our revenues and reduce our profitability.

Combustion of fossil fuels, such as the coal we produce, results in the emission of carbon dioxide into the atmosphere. Concerns about the environmental impacts of such emissions, including perceived impacts on global climate issues, are resulting in increased regulation of fossil fuels. in many jurisdictions, unfavorable lending policies by lending institutions and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Global climate issues continue to attract public and scientific attention. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. Increasing government attention is being paid to global climate issues and to emissions of GHGs, including emissions due to fossil fuels.

Federal and possibly state governments may impose significant restrictions on fossil-fuel exploration, production and use if pledges made by certain candidates seeking various political offices were enacted   into law. Some proposals include bans on hydraulic fracturing of oil & gas wells, bans on new leases for production of minerals on federal properties, and imposing restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities. Other energy legislation and initiatives could include a carbon tax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Litigation risks are also increasing, as a number  of  cities,  local  governments and other plaintiffs have sued companies engaged in the exploration and production of fossil fuels in state and federal courts, alleging various legal theories to recover for the impacts of alleged global warming effects, such as rising sea levels.  Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.  Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.

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Apart from governmental regulation, there are also increasing financial risks for fossil fuel producers as stakeholders of fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their support into non-energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. In recent years, the insurance industry has been subject to similar intense lobbying efforts by environmental activist to restrict coverages available for fossil fuel producers.

Limitation of investments in and financing, bonding and insurance coverages for fossil fuel energy companies could adversely affect mining activities.

The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from fossil fuel companies could result in increased costs of compliance or costs of consuming, and thereby reduce demand for coal, which could reduce the profitability of our interests. Additionally, political, litigation and financial risks may result in us restricting or cancelling mining activities, incurring liability for infrastructure damages as a result of climatic changes, or having an impaired ability to continue to operate in an economic manner. One or more of these developments, as well as concerted conservation and efficiency efforts that result in reduced electricity consumption, and consumer and corporate preferences  for non-fossil fuel sources, including alternative energy sources, could cause prices and sales of our coal to materially decline and could cause our costs to increase and adversely affect our revenues and results of operations.

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

Increasing attention to climate change risk has also resulted in a recent trend of governmental investigations and private litigation by state and local governmental agencies as well as private plaintiffs in an effort to hold energy companies accountable for the alleged effects of climate change. Other public nuisance lawsuits have been brought in the past against power, coal, and oil & gas companies alleging    that their operations are contributing to climate change. The plaintiffs in these suits sought various remedies, including punitive and compensatory damages and injunctive relief. While the United States Supreme Court held that federal common law provided no basis for public nuisance claims against the defendants in those cases, tort-type liabilities remain a possibility and a source of concern. Government entities in other states (including California and New York) have brought similar claims seeking to hold a wide variety of companies that produce fossil fuels liable for the alleged impacts of the GHG emissions attributable to those fuels. Those lawsuits allege damages as a result of climate change and the plaintiffs   are seeking unspecified damages and abatement under various tort theories.

We have not been made a party to these other suits, but it is possible that we could be included in similar future lawsuits initiated by state and local governments as well as private claimants.

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

In 2019, approximately 87% of our sales were under contracts having a term greater than one year, which we refer to as long-term contracts. Long-term sales contracts have historically provided a relatively secure market for the amount of production committed under the terms of the contracts. From time to time industry conditions may make it more difficult for us to enter into long-term contracts with our electric utility customers, and if supply exceeds demand in the coal industry, electric utilities may become less willing to lock in price or quantity commitments for an extended period of time. Accordingly, we may not be able to continue to obtain long-term sales contracts with reliable customers as existing contracts expire, which could subject a portion of our revenue stream to the increased volatility of the spot market.

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

Some of our long-term contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins. Accordingly, long-term contracts may

17

provide only limited protection during adverse market conditions. In some circumstances, failure of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.

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

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

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

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

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

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

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

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

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

·

mining and processing equipment failures and unexpected maintenance problems;

·

unavailability of required equipment;

·

prices for fuel, steel, explosives and other supplies;

·

fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;

·

variations in thickness of the layer, or seam, of coal;

·

amounts of overburden, partings, rock and other natural materials;

·

weather conditions, such as heavy rains, flooding, ice and other natural events affecting operations, transportation or customers;

·

accidental mine water discharges and other geological conditions;

·

seismic activities, ground failures, rock bursts or structural cave-ins or slides;

18

·

fires;

·

employee injuries or fatalities;

·

labor-related interruptions;

·

increased reclamation costs;

·

inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;

·

fluctuations in transportation costs and the availability or reliability of transportation; and

·

unexpected operational interruptions due to other factors.

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

Our inability to obtain commercial insurance at acceptable rates or our failure to adequately reserve for self-insured exposures might increase our expenses and have a negative impact on our business.

We believe that commercial insurance coverage is prudent in certain areas of our business for risk management. Insurance costs may increase substantially in the future and may be affected by natural disasters, fear of terrorism, financial irregularities, cybersecurity breaches and other fraud at publicly traded companies, intervention by the government, an increase in the number of claims received by the carriers, and a decrease in the number of insurance carriers. In addition, the carriers with which we hold   our policies may go out of business or be otherwise unable to fulfill their contractual obligations or may disagree with our interpretation of the coverage or the amounts owed. In addition, for certain types or levels of risk, such as risks associated with certain natural disasters or terrorist attacks, we may determine that we cannot obtain commercial insurance at acceptable rates, if at all. Therefore, we may choose to forego or limit our purchase of relevant commercial insurance, choosing instead to self-insure one or more types or levels of risks. If we suffer a substantial loss that is not covered by commercial insurance or our self-insurance reserves, the loss and related expenses could harm our business and operating results. Also, exposures exist for which no insurance may be available and for which we have not reserved. In addition, environmental activists may try to hamper fossil fuel companies by other means including pressuring insurance and surety companies into restricting access to certain needed coverages.

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

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

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

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

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

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

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

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

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

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

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

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

20

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

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

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

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

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

·

uncertainties in assessing the value, strengths, and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental or mine safety liabilities) of, expansion and acquisition opportunities;

·

the ability to achieve identified operating and financial synergies anticipated to result from an expansion or an acquisition;

·

problems that could arise from the integration of the new operations; and

·

unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying our rationale for pursuing the expansion or acquisition opportunity.

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

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

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

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

21

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

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

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

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

·

geological and mining conditions, which may not be fully identified by available exploration data and/or differ from our experiences in areas where we currently mine;

·

the percentage of coal in the ground ultimately recoverable;

·

historical production from the area compared with production from other producing areas;

·

the assumed effects of regulation and taxes by governmental agencies;

·

future improvements in mining technology; and

·

assumptions concerning future coal prices, operating costs, capital expenditures, severance and excise taxes and development and reclamation costs.

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

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

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

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

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

22

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

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

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

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

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

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

Public health threats could have an adverse effect on our operations and financial results. 

Public health threats and other highly communicable diseases, outbreaks of which have already occurred in various parts of the world, could adversely impact our operations, the operations of our customers and the global economy.

In particular, the outbreak in December 2019 of a novel coronavirus (COVID-19) in China has resulted in quarantines, restrictions on travel to and from China and a decrease in economic activity in China, the world’s second largest economy.  To date, these impacts have not had a material adverse effect on our business but no assurance can be given that they will not have such an effect, or that any further spread of the novel coronavirus (COVID-19) will not have a material adverse effect on our business, operations and financial results.

We may not recover our investments in our mining and other assets, which may require us to recognize impairment charges related to those assets.

The value of our assets have from time to time been adversely affected by numerous uncertain factors, some of which are beyond our control, including unfavorable changes in the economic environments in which we operate, lower-than-expected coal pricing, technical and geological operating difficulties, an inability to economically extract our coal reserves and unanticipated increases in operating costs. During the year ended December 31, 2019, we recorded $77.9 million of impairment charges related to such factors, as further described in Note 2 to the accompanying consolidated financial statements. These factors may trigger the recognition of additional impairment charges in the future, which could have a substantial impact on our results of operations.

23

Risks Related to Our Indebtedness and Liquidity

 

If we are unable to comply with the covenants contained in our credit agreement, the lenders could declare all amounts outstanding to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and operations.

As disclosed in Note 5 to our financial statements, there are two key ratio covenants stated in our credit agreement: (i) a Minimum Debt Service Coverage Ratio (consolidated adjusted EBITDA/annual debt service) of 1.25 to 1 and (ii) a Maximum Leverage Ratio (consolidated funded debt/trailing twelve months adjusted EBITDA) not to exceed 3.00 to 1, which also decreases in future periods further reducing the maximum leverage permitted. On December 31, 2019, our debt service coverage ratio was 1.84, and our leverage ratio was 2.62. Therefore, we were in compliance with these two ratios.

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

On December 31, 2019, our debt was $180 million. Our leverage may:

·

adversely affect our ability to finance future operations and capital needs;

·

limit our ability to pursue acquisitions and other business opportunities; and

·

make our results of operations more susceptible to adverse economic or operating conditions.

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

ITEM 1B. UNRESOLVED STAFF COMMENTS.  None.

ITEM 2. PROPERTIES.

 

See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of our mines.

Coal Reserve Estimates

 

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

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

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

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

ITEM 3.  LEGAL PROCEEDINGS.  None

ITEM 4.  MINE SAFETY DISCLOSURES:

Safety is a core value at for us and our subsidiaries. As such we have dedicated a great deal of time, energy, and resources to creating a culture of safety. We are proud of the mine rescue team at Sunrise Coal who placed 2nd overall in the National Mine Rescue contest held in Lexington, Kentucky in September 2019.  We would also like to recognize Willie Hamilton who finished second in the nation on pre-shift and Steve Earle who was first in Indiana on bench.

 

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

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PART II

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

 

Stock Price Information

 

Our common stock is traded on the NASDAQ Capital Market under the symbol HNRG, and 30.4% is held by our officers, directors and their affiliates.

At March 2, 2020, we had 231 shareholders of record of our common stock; this number does not include the shareholders holding stock in "street name.”  We estimate we have over 5,000 street name holders.

Equity Compensation Plan Information

See Note 10 to our consolidated financial statements.

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

 

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

Overview

The largest portion of our business is devoted to coal mining in the State of Indiana through Sunrise Coal, LLC (a wholly owned subsidiary) serving the electric power generation industry. We also own a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method.   Additionally, we own 100% of the Class A shares of Hourglass Sands, LLC (Hourglass), a frac sand dry plant in the State of Colorado.  Based on weak market conditions for frac sand in Colorado for the foreseeable future, we are impairing the assets to fair market value as of December 31, 2019.  See Note 2 to our consolidated financial statements for further discussion.

Mining Operations

In February 2020, we decided to permanently close the Carlisle Mine and to focus our efforts on lower cost operations at Oaktown.  Due to unforeseen geologic conditions and other issues experienced in 2019, cost of producing coal at Carlisle was much higher than anticipated. When considering capital expenses, Carlisle did not produce positive cash flow in 2019. The decision to permanently close Carlisle was made after a thorough review of future mining conditions, operations and expected future coal market conditions. Operating only Oaktown will significantly decrease costs in 2020 as compared to 2019 allowing additional EBITDA per ton in 2020.  We will remove $24 million of Carlisle equipment and parts inventory and utilize those assets at Oaktown which will further reduce future capital expenditures. See Note 2 to our consolidated financial statements for a discussion on the impairment of the Carlisle Mine assets.  After the closure, we will operate two underground coal mines and one surface coal mine in southwestern Indiana with the following capacities:

 

 

 

 

 

 

 

 

 

 

    

    

    

    

    

Annual

    

    

 

 

 

 

Surface/

 

Tons Capacity

 

 

Mine

 

Location

 

Underground

 

(in millions)

 

Transportation

Oaktown 1*

 

Oaktown, IN

 

Underground

 

4.0

 

CSX, Truck Direct & Truck to NS

Oaktown 2**

 

Oaktown, IN

 

Underground

 

4.0

 

CSX, Truck Direct & Truck to NS

Ace in the Hole

 

Clay City, IN

 

Surface

 

0.3

 

Truck to CSX & NS

Total

 

 

 

  

 

8.3

 

  


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

26

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

Our Coal Contracts

 

In 2019, Sunrise sold a record 8.1 million tons of coal to 14 power plants in 7 different states. Though we served more plants in 2018, tonnage in 2019 increased significantly due to new customers buying more tons.  The total estimated coal consumption of our 2019 customers is 165% greater than our 2017 customer base.

 

    

 

    

 

    

Estimated Tonnage

    

 

    

 

 

 

 

 

 

 

 

Demand of 

 

 

 

 

 

 

 

# of Plants

 

# of States

 

Customers Served

 

Tons Sold

 

% of Customer

 

Year

 

Served

 

Served

 

(millions)

 

(millions)

 

Supply

 

2019

 

14

 

 7

 

42.9

 

8.1

 

18.9

%

2018

 

17

 

 8

 

42.9

 

7.4

 

17.2

%

2017

 

 9

 

 3

 

16.2

 

6.6

 

40.7

%

 

We have gained more customers by focusing on increasing “Customer Value”, meaning the total lifetime value of a customer’s business.  We work to increase “Customer Value” by acquiring more customers, earning more business from existing ones and retaining customers longer.  An example of acquiring more customers would be our investment in our Princeton Rail Loop, which has enabled us to provide transportation flexibility and access to new customers.  Though markets are currently challenging, we continue to see opportunities to increase “Customer Value” over the long run.

During 2019, we derived 70% of our revenue from four customers (8 power plants), with each of the four customers representing at least 10% of our coal sales. With the addition of the new power plants that we began shipping to in 2018, we reduced the concentration from customers representing at least 10% of our coal sales from 82% in 2018.

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

Of our 2019 sales, 74% were shipped to locations in the State of Indiana. We anticipate our coal shipments utilizing the following modes of transportation in 2020:

 

 

 

 

 

CSX Railroad

    

44

%

CSX/INRD

 

23

%

Truck

 

23

%

NS Railroad

 

10

%

Total

 

100

%

 

 

 

 

 

Currently, domestic coal inventories and natural gas (a competitor to coal) inventory levels are high and will take time to normalize.  Thus, for 2020 and 2021 we have reduced our targeted tons to 6.7 million tons annually, of which we are 100% sold for 2020 and 79% sold for 2021.  For 2020, we have reduced our contracted tons in the table below to the minimum amounts that customers are contractually obligated to take. 

27

 

 

 

 

 

 

 

 

 

 

 

 

 

Targeted

 

Contracted

 

 

 

Estimated

 

 

tons

 

tons

 

%

 

price

Year

 

(millions)

 

(millions)*

 

Committed

 

per ton

2020

 

           6.7

 

           6.7

 

          100

%  

$

$     40.00

2021

 

           6.7

 

           5.3

 

            79

%  

 

$     40.00

2022

 

           7.0

 

           5.3

 

            76

%  

 

$     40.50

Total

 

         20.4

 

         17.3

 

            85

%  

 

 

 


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

We expect to continue selling a significant portion of our coal under supply agreements with terms of one year or longer. Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices while we seek stable sources of revenue to support the investments required to open, expand and maintain, or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers.

With the following exception, our customer plants are expected to have many years of life.  In January 2020, Hoosier Energy announced that they intend to close their Merom Generating Station in 2023.  Merom represents 700,000 tons or ~10% of our sales volume in 2020.

Asset Impairment Review

See Note 2 to our consolidated financial statements.

Reserve Table - Controlled Tons (in millions):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2019 Year-End Reserves

 

 

 

 

 

 

Tons

 

Annual

 

 

 

 

 

 

 

 

 

 

 

    

Sold*

    

Capacity

    

Proven

    

Probable

    

Total

    

Sulphur #

    

BTU

Oaktown 1 (assigned)

 

4.1

 

4.0

 

39.4

 

8.5

 

47.9

 

6.1

 

11,500

Oaktown 2 (assigned)

 

2.3

 

4.0

 

31.1

 

7.9

 

39.0

 

5.7

 

11,600

Ace in the Hole (assigned)

 

0.3

 

0.3

 

0.3

 

 —

 

0.3

 

1.8

 

11,200

Ace in the Hole #2 (unassigned)

 

 —

 

 —

 

1.0

 

 —

 

1.0

 

3.5

 

11,100

Total

 

6.7

 

8.3

 

71.8

 

16.4

 

88.2

 

  

 

  

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Assigned

 

  

 

  

 

  

 

  

 

87.2

 

  

 

  

Unassigned

 

  

 

  

 

  

 

  

 

1.0

 

  

 

  

 

 

  

 

  

 

  

 

  

 

88.2

 

  

 

  

_____________

*The table above excludes Carlisle tons sold of 1.4 million.

 

Our assigned underground coal reserves are high sulfur (5.0# – 6.5# SO2) with an average BTU content in the 11,400 -11,600 range. Our reserves have lower chlorine (<0.12%) than average ILB reserves of 0.22%. Much of the ILB’s new production is located in Illinois and possesses chlorine content in excess of .30%. The relatively low chlorine content of our reserves is attractive to buyers given their desire to limit the corrosive effects of chlorine in their power plants. As discussed below, the Ace surface mine is low sulfur (~2.0# SO2) with an average BTU content of 11,200. We have no metallurgical coal reserves, only steam (thermal) coal reserves. Below is a discussion of our current projects. Only seams greater than 4 feet in thickness are included in our underground reserves.

 

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

28

Oaktown 1 Mine (underground) – Assigned

We have 47.9 million controlled, salable tons of the Indiana #V coal seam.  We began 2019 with 54.4 million tons controlled. After accounting for current year production, the remaining decrease is a result of revised mining plans relating to tons that were deemed unrecoverable due to geologic conditions. Oaktown 1 reserves are located in Knox County, IN.

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

Oaktown 2 Mine (underground) – Assigned

We have 39.0 million controlled, saleable tons of the Indiana #V coal seam. We began 2019 with 43.4 million controlled tons. After accounting for current year production, the remaining decrease relates to tons that were deemed unrecoverable due to geologic conditions based on new drilling.  Oaktown 2 reserves are located in both Knox County, Indiana and Lawrence County, Illinois.

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

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

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

We have 0.3 million controlled, saleable tons at our Ace mine. The Ace mine is near Clay City, Indiana in Clay County and 42 road miles northeast of the Carlisle Mine. The two primary seams are low sulfur coal (~2# SO2), which make up the vast majority of the tons controlled. Mine development began in late December 2012, and we began shipping coal in late August 2013. We truck low sulfur coal from Ace to Oaktown to blend with high sulfur coal. Many utilities in the southeastern U.S. have scrubbers with lower sulfur limits (4.5# SO2) which cannot accept the higher sulfur contents of the ILB (4.5# - 6.5# SO2). Blending high sulfur coal to a lower sulfur specification enables us to market our high sulfur coals to more customers.

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

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

In 2018, we leased property giving us 1.0 million controlled, saleable tons at a new location 2 miles southwest of our Ace in the Hole mine. Mine development is expected to begin in early 2021.

29

 

Bulldog Reserves (underground) – Unassigned

We have leased roughly 19,300 acres in Vermilion County, Illinois near the village of Allerton. Based on our reserve estimates we currently control 30.6 million tons of coal.  A considerable amount of our leased acres has yet to receive any exploratory drilling.  See Note 2 to our consolidated financial statements for a discussion on the impairment of the Bulldog assets.

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

 

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

Picture 4

Railroad Legend:

CSX – CSX Railroad

INRD – Indiana Rail Road

ISRR – Indiana Southern Railroad

NS – Norfolk Southern Railway

30

Mine and Wash Plant Recovery and Capacity

 

 

 

 

 

 

 

   

    

 

    

 

    

Wash Plant Capacity

 

 

Mine recovery

 

Wash plant recovery*

 

(Clean Tons)

Oaktown 1

 

49

%  

81

%  

8.0 million**

Oaktown 2

 

46

%  

81

%  

  


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

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

Liquidity and Capital Resources

As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $38.2 million and $51.6 million for the years ended December 31, 2019 and 2018 respectively. Operating cash flow decreased due to : (1) operating margins from our coal operations decreased in 2019 by $7.0 million due to increased operating costs related primarily to the Carlisle Mine, (2) management chose to increase inventory at the end of 2019 in anticipation of the winter shipping season, which resulted in an additional $8.3 million in inventory over 2018, and (3) other changes in working capital items that are strictly timing related.

Our capital expenditure budget for 2020 is $20 million, of which $11 million is for maintenance capex.  With the closure of the Carlisle Mine, equipment and parts inventories totaling $23 million will be re-deployed to Oaktown and are expected to be fully utilized over the next 12 months, helping reduce our capital expenditures in the future.  We expect cash from operations for 2020 and the utilization of our revolver, if necessary, to fund our maintenance capital expenditures, debt service, and our dividend.

See Note 5 to our consolidated financial statements for discussion about our bank debt.

Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded reclamation obligations of $15.8 million, with the long-term portion presented as asset retirement obligations (ARO) and the remainder in accounts payable and accrued liabilities in our accompanying balance sheets. In the event we are not able to perform reclamation, we have surety bonds totaling $27 million to cover ARO.

Capital Expenditures (capex)

For the year ended December 31, 2019, our capex was $35.5 million allocated as follows (in millions):

 

Oaktown – maintenance capex

 

$

         19.3

Oaktown – investment

  

        

         10.4

Carlisle - maintenance capex

 

 

           3.1

Ace - investment

 

 

           1.6

Other

 

 

           1.1

Capex per the Consolidated Statements of Cash Flows

 

$

         35.5

 

31

Results of Operations

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

The following table presents our unaudited quarterly results of operations for the eight quarters ended December 31, 2019. This table includes all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair presentation of our consolidated operating results for the quarters presented.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

Dec-31

 

Sep-30

 

Jun-30

 

Mar-31

 

Dec-31

 

Sep-30

 

Jun-30

 

Mar-31

 

 

2019

 

2019

 

2019

 

2019

 

2018

 

2018

 

2018

 

2018

Revenue:

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

Coal sales

 

$

78,205

 

$

82,883

 

$

71,113

 

$

85,235

 

$

89,019

 

$

79,055

 

$

56,922

 

$

66,787

Other

 

 

538

 

 

213

 

 

1,197

 

 

4,078

 

 

709

 

 

667

 

 

321

 

 

77

Total revenue

 

 

78,743

 

 

83,096

 

 

72,310

 

 

89,313

 

 

89,728

 

 

79,722

 

 

57,243

 

 

66,864

 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

Costs and expenses:

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

Operating costs and expenses

 

 

60,083

 

 

71,363

 

 

54,001

 

 

62,419

 

 

69,619

 

 

60,230

 

 

38,874

 

 

46,640

DD&A

 

 

12,960

 

 

11,778

 

 

12,096

 

 

11,738

 

 

11,403

 

 

10,815

 

 

11,120

 

 

10,829

ARO accretion

 

 

329

 

 

320

 

 

314

 

 

309

 

 

301

 

 

293

 

 

291

 

 

282

Coal exploration costs

 

 

390

 

 

347

 

 

208

 

 

280

 

 

374

 

 

279

 

 

315

 

 

217

SG&A

 

 

3,463

 

 

2,926

 

 

3,475

 

 

2,984

 

 

2,958

 

 

2,519

 

 

2,474

 

 

3,890

Bank interest

 

 

2,765

 

 

2,801

 

 

2,933

 

 

3,012

 

 

3,364

 

 

3,377

 

 

2,781

 

 

2,360

Non-cash interest

 

 

(313)

 

 

757

 

 

2,436

 

 

1,607

 

 

2,640

 

 

(116)

 

 

1,534

 

 

348

Asset Impairment*

 

 

77,882

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

 —

 

 

 —

Total cost and expenses

 

 

157,559

 

 

90,292

 

 

75,463

 

 

82,349

 

 

90,659

 

 

77,397

 

 

57,389

 

 

64,566

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

 

(78,816)

 

 

(7,196)

 

 

(3,153)

 

 

6,964

 

 

(931)

 

 

2,325

 

 

(146)

 

 

2,298

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Less income taxes:

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

Current

 

 

52

 

 

(426)

 

 

78

 

 

(229)

 

 

(1,362)

 

 

(204)

 

 

(19)

 

 

(203)

Deferred

 

 

(19,081)

 

 

(3,047)

 

 

113

 

 

193

 

 

(2,167)

 

 

(385)

 

 

(104)

 

 

369

Total income taxes

 

 

(19,029)

 

 

(3,473)

 

 

191

 

 

(36)

 

 

(3,529)

 

 

(589)

 

 

(123)

 

 

166

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

(59,787)

 

$

(3,723)

 

$

(3,344)

 

$

7,000

 

$

2,598

 

$

2,914

 

$

(23)

 

$

2,132

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) per share:

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

Basic and diluted

 

$

(1.95)

 

$

(0.12)

 

$

(0.11)

 

$

0.23

 

$

0.09

 

$

0.09

 

$

 —

 

$

0.07

 

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

Weighted average shares outstanding:

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

 

 

  

Basic and diluted

 

 

30,274

 

 

30,249

 

 

30,245

 

 

30,245

 

 

30,180

 

 

30,177

 

 

29,980

 

 

29,955

 

*Impairment and tax effects primarily related to the decision to idle the Carlisle Mine.  See Note 2 to our Consolidated Financial Statements.

32

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

    

 

 

 

 

 

 

 

    

 

 

All Mines

 

1st 2019

    

2nd 2019

    

3rd 2019

    

4th 2019

 

T4Qs

 

Tons produced

 

 

2,205

 

 

2,003

 

 

1,891

 

 

2,122

 

 

8,221

 

Tons sold

 

 

2,130

 

 

1,807

 

 

2,118

 

 

2,015

 

 

8,070

 

Coal sales

 

$

85,235

 

$

71,113

 

$

82,883

 

$

78,205

 

$

317,436

 

Average price/ton

 

$

40.02

 

$

39.35

 

$

39.13

 

$

38.81

 

$

39.34

 

Wash plant recovery in %

 

 

73

%  

 

71

%  

 

70

%  

 

74

%  

 

 

 

Operating costs

 

$

62,271

 

$

53,915

 

$

71,372

 

$

60,082

 

$

247,640

 

Average cost/ton

 

$

29.24

 

$

29.84

 

$

33.70

 

$

29.82

 

$

30.69

 

Margin

 

$

22,964

 

$

17,198

 

$

11,511

 

$

18,123

 

$

69,796

 

Margin/ton

 

$

10.78

 

$

9.52

 

$

5.43

 

$

8.99

 

$

8.65

 

Capex

 

$

8,840

 

$

9,448

 

$

8,981

 

$

8,264

 

$

35,533

 

Maintenance capex

 

$

6,672

 

$

6,164

 

$

5,537

 

$

4,115

 

$

22,488

 

Maintenance capex/ton

 

$

3.13

 

$

3.41

 

$

2.61

 

$

2.04

 

$

2.79

 

 

 

All Mines

 

1st 2018

 

 

2nd 2018

 

3rd 2018

 

4th 2018

T4Qs

 

Tons produced

 

 

1,975

 

 

1,983

 

 

1,713

 

 

1,938

 

 

7,609

 

Tons sold

 

 

1,707

 

 

1,477

 

 

1,962

 

 

2,219

 

 

7,365

 

Coal sales

 

$

66,787

 

$

56,922

 

$

79,055

 

$

89,019

 

$

291,783

 

Average price/ton

 

$

39.13

 

$

38.54

 

$

40.29

 

$

40.12

 

$

39.62

 

Wash plant recovery in %

 

 

69

%  

 

73

%  

 

72

%  

 

68

%

 

 

 

Operating costs

 

$

46,640

 

$

38,809

 

$

60,132

 

$

69,364

 

$

214,945

 

Average cost/ton

 

$

27.32

 

$

26.28

 

$

30.65

 

$

31.26

 

$

29.18

 

Margin

 

$

20,147

 

$

18,113

 

$

18,923

 

$

19,655

 

$

76,838

 

Margin/ton

 

$

11.80

 

$

12.26

 

$

9.64

 

$

8.86

 

$

10.43

 

Capex

 

$

10,428

 

$

7,784

 

$

5,856

 

$

8,996

 

$

33,064

 

Maintenance capex

 

$

5,772