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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
☒
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended: December 31, 2024 OR
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number: 001-3473
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: 812.299.2800
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 (§
232.405 of this chapter) 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 “large 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
☑ 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial
reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the
correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the
registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
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, 2024, was $236,738,085, based on the closing price reported that date by
the NASDAQ of $7.77 per share.
As of March 10, 2025, we had 42,619,347 shares outstanding. Our Annual Meeting of Shareholders will be held on May 29, 2025, in Denver, Colorado.
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FORWARD-LOOKING STATEMENTS
Certain statements and information in this Annual Report on Form 10-K may constitute “forward-looking statements.” These
statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this
document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar
expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook,
anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These
statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a
wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among
the factors that could cause actual results to differ from those in the forward-looking statements are:
●
changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our
financial position;
●
fluctuations in weather, gas and electricity commodity costs, inflation and economic conditions impact demand of our
customers and our operating results;
●
the outcome or escalation of current hostilities in Ukraine and Israel;
●
changes in competition in electricity or coal markets and our ability to respond to such changes;
●
changes in coal prices, demand, and availability which could affect our operating results and cash flows;
●
risks associated with the expansion of our operations and properties;
●
legislation, regulations, administrative actions (e.g., Executive Orders), 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, as well as those relating to data privacy protection;
●
deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or
general economic conditions;
●
dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing
contracts;
●
changing global economic conditions or the geopolitical environment in industries in which our customers operate;
●
anticipated changes in the U.S. political environment, including those resulting from the change in Presidential Administration
and control of Congress, and to regulatory agencies;
●
changes in attitude toward environmental, social, and governance (“ESG”) matters among regulators, investors and parties
with which we do business;
●
the effect of changes in taxes or tariffs and other trade measures;
●
risks relating to inflation and increasing interest rates;
●
liquidity constraints, including due to restrictions contained in our indebtedness and those resulting from any future
unavailability of financing;
●
customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, or
other failures to perform;
●
customer delays, failure to take coal under contracts or defaults in making payments;
●
adjustments made in price, volume or terms to existing coal supply and customer agreements;
●
our productivity levels and margins earned on our coal or electricity sales;
●
supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to
inflationary pressures;
●
changes in the availability of skilled labor;
●
our ability to maintain satisfactory relations with our employees;
●
increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers’
compensation claims;
●
increases in transportation costs and risk of transportation delays or interruptions;
●
operational interruptions due to geologic, permitting, labor, weather-related or other factors;
●
risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including
unanticipated operating conditions and other events that are not within our control;
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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;
●
risks resulting from climate change or natural disasters;
●
difficulty in making accurate assumptions and projections regarding post-mine reclamation;
●
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;
●
difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity
investments in companies we do not control;
●
the severity, magnitude and duration of any future pandemics, including impacts of the pandemic and of businesses’ and
governments’ responses to the pandemic on our operations and personnel, and on demand for coal, the financial condition of
our customers and suppliers, available liquidity and capital sources and broader economic disruptions; and
●
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, unless
required by law.
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
www.halladorenergy.com and written or oral statements made by us or any of our officers or other authorized persons acting on our
behalf.
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PART I
Page
Item 1.
Business
5
Item 1A.
Risk Factors
21
Item 1B.
Unresolved Staff Comments
39
Item 1C.
Cybersecurity
39
Item 2.
Properties
39
Item 3.
Legal Proceedings
40
Item 4.
Mine Safety Disclosures
40
PART II
Item 5.
Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
40
Item 6.
[Reserved]
40
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
41
Item 8.
Financial Statements
61
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
96
Item 9A.
Controls and Procedures
96
Item 9B.
Other Information
98
Item 9C.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
98
PART III
Part IV
Item 15.
Exhibits and Financial Statement Schedules
99
Item 16.
Form 10-K Summary
100
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ITEM 1. BUSINESS.
Hallador Energy Company is a vertically integrated power and coal company with operations primarily in Indiana. The Company
operates across multiple stages of the energy supply chain, from coal extraction to electricity generation and mines coal from the rich,
high-quality, lower sulfur reserves found in the Illinois Basin (“ILB”).
Once the coal is mined by Sunrise Coal, LLC (“Sunrise”), the Company’s wholly-owned mining subsidiary, the Company processes
and transports it to power plants, where it is used as a primary fuel source for generating electricity. Through its wholly-owned
subsidiary Hallador Power, LLC (“Hallador Power”), the Company owns and operates the Merom Power Plant (“Merom”), a 1,080
MW net coal fired power generating station, consisting of two 590 MW sub-critical water tube drum type steam turbine
generators. Unit 1 entered commercial operations in 1982 and Unit 2 in 1983. The units are dispatched to the Midcontinental
Independent System Operator (“MISO”) interconnection. Hallador Power sells wholesale energy and accredited capacity to utilities
within the MISO system through power purchase agreements (“PPA”) and other bilateral transactions. Merom is located in Sullivan
County, Indiana, about twenty miles from Sunrise’s Oaktown Mining Complex. Sunrise also sells coal to other utilities in Indiana and
throughout the southeast United States. In addition, it has a developed infrastructure for the transport of coal, including rail networks
and truck loading systems, facilitating the efficient movement of the resource from the mine to its customers.
The vertically integrated structure allows the Company to control the entire process, from mining to power production, providing cost
efficiencies, greater operational flexibility, and the ability to manage supply and demand within the energy market. Hallador Power has
invested in technologies to reduce emissions and improve the environmental performance of coal-fired generation, particularly in
response to regulatory pressures.
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 electric power generation and coal mining industries are subject to extensive regulation by federal, state, and local authorities on
matters such as:
●
employee health and safety;
●
mine permits and other licensing requirements;
●
air quality standards and greenhouse gas emissions;
●
water quality standards;
●
storage of petroleum products and substances that are regarded as hazardous under applicable laws or that, if spilled, could
reach waterways, wetlands, or groundwater;
●
plant and wildlife protection, and historic and archeological site and cultural resource protection, that could limit or prohibit
electric power generation, mining or exploration;
●
restricting the types, quantities, and concentration of materials that can be released into the environment in the performance of
electric power generation, mining, exploration or production activities;
●
discharge of materials;
●
storage and handling of explosives;
●
wetlands protection;
●
surface subsidence from underground mining; and
●
the effects, if any, that electric power generation or mining activities, including coal combustion residuals, have on
groundwater quality and availability.
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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, capital
expenditures, interruptions, changes in operations, 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 costs and adversely affect our performance. In addition, the electric power
industry is subject to extensive regulation regarding the environmental impact of its power generation activities, which has also
adversely affected demand for coal. It is possible that new legislation or regulations may be adopted, that existing laws or regulations
may be interpreted differently or more stringently enforced, that existing regulations may be repealed or that the authority of current
regulators may be reduced or revoked, any of which could have a significant impact on our mining or electric power generating
operations or our customers’ ability to use coal. For more information, please see “Recent Regulatory Developments from the
Presidential Transition” in this section, below, and the risk factors described in “Item 1A. Risk Factors” below.
We are committed to conducting electric power generating and 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, including 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 electric power generating company or 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 electric power
generation and the cost of coal mining for domestic coal producers.
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, power plant closing, and mine closings, including the cost of treating mine water discharge, when
necessary. The accruals for asset retirement obligations, power plant closing and mine closing costs are based upon permit requirements
and the estimated 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.
Electric Power Generation Permits and Approvals
Numerous governmental permits or approvals are also required for electric power generation operations, including coal-fired power
plants such as Merom Generating Station. Applications for permits require extensive engineering and data analysis and presentation and
must address a variety of environmental, health, and safety matters associated with electric power generation. These matters include air
emissions, including greenhouse gas emissions, the management and disposal of coal combustion residuals and other wastes or
materials, and wastewater effluent treatment and discharge, among others. Meeting all requirements imposed to address these matters
may be costly and may delay or prevent commencement or continuation of power generation operations.
The permitting process for electric power generation operations can extend over many years as a result of necessary permit renewals
and those permitting decisions can be subject to administrative and judicial challenge, including by the public. We cannot assure you
that we will not experience difficulty or delays in obtaining electric power generation permits in the future or that a current permit will
not be revoked.
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We are required to post bonds to secure performance under our coal combustion residuals landfill permit. Under some circumstances,
substantial fines and penalties, including revocation of electric power generating permits, may be imposed under the laws and
regulations described above and below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure
to comply with these laws and regulations. Although, like other power generating 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.
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
The Federal Mine Safety and Health Act of 1977 (“FMSHA”) and regulations adopted pursuant thereto, imposes 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 United States (the “U.S.”) for the 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 the imposition of a civil penalty for each cited violation. Negligence and gravity
assessments, along with other factors, can result in the issuance of various types of orders, including orders requiring withdrawal from
the mine or the affected area, and some orders can also result in the imposition of civil penalties. 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.
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The Federal Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”) significantly amended the FMSHA,
imposing more extensive and stringent compliance standards, increasing criminal penalties and establishing a maximum civil penalty
for non-compliance, and expanding the scope of federal oversight, inspection, and enforcement activities. Following the passage of the
MINER Act, MSHA has issued new or more stringent rules and policies on a variety of topics, including:
●
sealing off abandoned areas of underground coal mines;
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mine safety equipment, training, and emergency reporting requirements;
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substantially increased civil penalties for regulatory violations;
●
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;
●
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 Miners’ 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 published a request for information regarding engineering controls and
best practices to lower miners’ exposure to respirable coal mine dust, and the comment period closed in July 2022. It is uncertain
whether MSHA will present additional proposed rules, or revisions to the final rule, following the closing of the comment period.
MSHA has also published, and may continue to publish, various proposed and final rules or requests for information, which may result
in additional rulemakings. For example, in June 2016, MSHA published a request for information on Exposure of Underground Miners
to Diesel Exhaust. Following a comment period that closed in November 2016, MSHA received requests for MSHA and the National
Institute for Occupational Safety and Health to hold a Diesel Exhaust Partnership to address the issues covered by MSHA’s request for
information. The comment period for the request for information closed in September 2020.
In August 2019, MSHA published a request for information regarding exposure to respirable crystalline silica, most commonly found in
the mining environment through quartz. The request solicited information regarding best practices to protect miners’ health from
exposure to quartz, including examination of a new reduced permissible exposure limit, potential new or developing protective
technologies, and/or technical and educational assistance. The comment period for the request for information closed in October 2019.
On December 10, 2024, MSHA published a final rule to revise Testing, Evaluation, and Approval of Electric Motor-Driven Mine
Equipment and Accessories within underground mining environments.
On December 20, 2023, MSHA published a final rule requiring that all mine operators develop and implement a written safety program
for mobile and powered haulage equipment at surface mines and surface areas of underground mines (Safety Program for Surface
Mobile Equipment).
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It is uncertain whether MSHA will engage in further rulemaking regarding the above issues or any of the other various proposed
rules or requests for information or whether any such rules would have material impacts on our operations or our costs of operation.
Subsequent to the 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, to some survivors of a miner who dies from this disease, and to a trust fund for the payment of benefits and medical
expenses where no responsible coal mine operator has been identified for claims. As of January 1, 2022, the trust fund was funded by an
excise tax on production of up to $0.50 per ton for underground-mined coal and up to $0.25 per ton for surface-mined coal, but not to
exceed 2% of the applicable sales price. The Inflation Reduction Act of 2022 raised the excise tax, effective October 1, 2022, up to
$1.10 per ton of coal from underground mines and up to $0.55 per ton of coal from surface mines, neither amount to exceed 4.4% of the
gross sales price.
Workers’ Compensation and Black Lung
We provide income replacement and medical treatment for work-related traumatic injury claims as required by applicable state laws.
Workers’ compensation laws also compensate survivors of workers who suffer employment-related deaths. We generally self-insure this
potential expense using our actuarial 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
workers’ pneumoconiosis or black lung. We also provide for these claims through self-insurance programs. Our actuarial calculations
are based on numerous assumptions, including disability incidence, medical costs, mortality, death benefits, dependents, and discount
rates.
The revised BLBA regulations took effect in January 2001, relaxing the stringent award criteria established under previous regulations
and thus potentially allowing new federal claims to be awarded and allowing previously denied claimants to re-file under the revised
criteria. These regulations may also increase black lung-related medical costs by broadening the scope of conditions for which medical
costs are reimbursable and increase legal costs by shifting more of the burden of proof to the employer.
The Patient Protection and Affordable Care Act enacted in 2010 includes significant changes to the federal black lung program
retroactive to 2005, including an automatic survivor benefit paid upon the death of a miner with an awarded black lung claim
and establishes a rebuttable presumption with regard to pneumoconiosis among miners with 15 or more years of coal mine employment
that are totally disabled by a respiratory condition. These changes could have a material impact on our costs expended in association
with the federal black lung program.
Surface Mining Control and Reclamation Act
The Federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes establish operational,
reclamation, and closure standards for all aspects of surface mining as well as many aspects of underground mining. Currently, 100% of
our production involves underground room and pillar mining (no surface subsidence). We do not engage in either mountain top removal
or long-wall mining. SMCRA nevertheless requires that comprehensive
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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 with the completion of surface mining operations. Federal law and some states impose on mine
operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for
damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly
other mining operations. We believe we are in compliance in all material respects with applicable regulations relating to reclamation.
In addition, the Abandoned Mine Lands Program, which is part of SMCRA, imposes a reclamation fee on all current mining operations,
the proceeds of which are used to restore mines closed before 1977. The fee expired on September 30, 2021, and was reauthorized
through September 30, 2034, under the Infrastructure Investment and Jobs Act which was signed on November 15, 2021. The fee, as
reauthorized, for surface-mined and underground-mined coal is $0.224 per ton and $0.096 per ton, respectively, through September 30,
2034. 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.
Coal Combustion Residuals
In April 2015, the United States Environmental Protection Agency (“EPA”) finalized rules on coal combustion residuals (“CCRs”). The
rule established nationally applicable minimum criteria for the disposal of CCRs in new and currently operating landfills and surface
impoundments, including location restrictions, design and operating criteria, groundwater monitoring, corrective action and closure
requirements, and post-closure care. CCRs are generated at Merom Station and the facility is subject to the CCR rule. The EPA has
indicated that it will implement a phased approach to amending the CCR Rule, which is ongoing. The CCR rule, current or proposed
amendments to the federal CCR rule or state CCR regulations, the results of groundwater monitoring data, or the outcome of CCR-
related litigation could have a material impact on our business, financial condition and results of operations.
Bonding Requirements
Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, for closure and post-closure landfill
care, and to satisfy other miscellaneous obligations. These bonds are typically renewable on a yearly basis. It has become increasingly
difficult for our competitors and us to secure new surety bonds without posting collateral, and in some cases, it is unclear what level of
collateral will be required. 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 and conduct electric power generating operations, which could affect our profitability and
cash flow.
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Air Emissions
The Clean Air Act (“CAA”) and similar state and local laws and regulations regulate emissions into the air and affect coal mining and
electric power generation operations. The CAA directly impacts our coal mining and processing and electric power generation
operations by imposing permitting requirements and, in some cases, requirements to install certain emissions control equipment,
achieve certain emissions standards, obtain emissions allowances, or implement certain work practices on sources that emit various air
pollutants. The CAA also indirectly affects coal mining operations by extensively regulating the air emissions of coal-fired electric
power generating plants and other coal-burning facilities. There have been a series of federal rulemakings focused on emissions from
coal-fired electric generating facilities. Installation of additional emissions control technology and any additional measures required
under applicable 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.
In addition to the greenhouse gas (“GHG”) issues discussed below, the air emissions programs that may affect our operations, directly
or indirectly, include, but are not limited to, the following:
●
The EPA’s Acid Rain Program, provided in Title IV of the CAA, regulates emissions of sulfur dioxide from electric power
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 electric
generating levels.
●
The Cross-State Air Pollution Rule (“CSAPR”) addresses the “good neighbor” provision in the Clean Air Act, which prohibits
sources within each state from emitting any air pollutant in an amount which will contribute significantly to any other state’s
nonattainment of, or interference with maintenance of, any National Ambient Air Quality Standards (“NAAQS”). CSAPR
requires power plants in certain states to reduce emission levels of sulfur dioxide and nitrogen oxide pursuant to a cap-and-
trade program similar to the Acid Rain Program. In October 2016, the EPA published a final rule to update the CSAPR to
address the 2008 ozone NAAQS ("CSAPR Update Rule"). Following legal challenges related to the CSAPR Update Rule, on
April 30, 2021, the EPA issued the Revised CSAPR Update Rule. The Revised CSAPR Update Rule required affected electric
generating units ("EGUs") within certain states (including Indiana) to participate in a new trading program. On June 5, 2023,
the EPA published a final Federal Implementation Plan to address air quality impacts with respect to the 2015 Ozone NAAQS
called the “Good Neighbor Plan.” However, on June 27, 2024, the United States Supreme Court granted emergency
applications seeking a stay of the Good Neighbor Plan pending judicial review. In response, on November 6, 2024, EPA
issued an interim final rule, which effectively reinstated the Revised CSAPR Update Rule during the stay. While our CSAPR
compliance costs to date have not been material, the future availability of and cost to purchase allowances to meet the
emission reduction requirements is uncertain at this time, but it could be material.
●
In February 2012, the EPA adopted the Mercury and Air Toxic Standards (“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 U.S. Court of Appeals for the District of
Columbia Circuit (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
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issued a proposed Supplemental Cost Finding, as well as the CAA required “risk and technology review.” In May 2020, EPA
issued a final rule that reverses the Agency’s prior determination from 2000 and 2016 that it was “appropriate and necessary”
to regulate hazardous air pollutants (“HAP”) from coal-fueled Electric Generating Units (“EGUs”) under the MATS rule.
However, in March 2023, EPA published a final rule revoking the May 2020 finding, and in May 2024, EPA issued a final rule
amending MATS and increasing the stringency of certain requirements. The MATS rule has forced electric power 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.
●
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. In March 2019, the EPA published a final rule that retained the current primary NAAQS for sulfur oxide. In
December 2020, EPA published a final rule to retain the current NAAQS for both PM and ozone; however, various entities
have filed litigation against one or both of these rulemakings, and the Biden Administration announced that it would
reconsider and potentially revise the NAAQS. On February 7, 2024, the EPA issued a new final rule regarding the
Reconsideration of the NAAQS for PM, and as part of that rule, EPA revised the level of the primary (health-based) annual
PM2.5 standard from 12.0 to 9.0 micrograms per cubic meter. With respect to ozone, in August 2023, EPA announced that it is
also conducting a new review of the ozone NAAQS. 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 electric power generating operations and 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 or electricity from coal-fired power plants.
●
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-fired power plants. In prior
cases, the EPA has decided to negate the SIPs and impose stringent requirements through Federal Implementation Plans
(“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, which was followed by a supplemental
memorandum in July 2021 for SIPs for the second implementation period.
●
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 been settled,
but others remain pending. In October 2020, the EPA finalized a rule to clarify the process for evaluating whether the NSR
permitting program would apply to a proposed modification of a source of air emissions. The EPA has announced that it will
review the NSR program. Depending on the ultimate resolution of the EPA’s litigation and review, demand for coal could be
affected as well as the process by which EPA evaluates modifications to power plants that trigger NSR.
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GHG Emissions
Combustion of fossil fuels, such as the coal we produce and the coal that is used at Merom Station, 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.
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-fired 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.
Several rulemakings have been issued under the EPA’s New Source Performance Standards (“NSPS”) that constrain the GHG emissions
of fossil-fuel-fired power plants. 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. Then, in October 2017 the EPA proposed to repeal the CPP. The EPA subsequently proposed
the Affordable Clean Energy (“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 adopted 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 CPP and promulgation of the ACE rule. On January 19, 2021, the Circuit Court struck down the ACE
rule and found the EPA’s “repeal of the CPP rested critically on a mistaken reading of the CAA.” On June 30, 2022, the Supreme Court
of the United States reversed and remanded the Circuit Court’s decision in West Virginia v. EPA and found that, in the promulgation of
the CPP, the EPA had acted outside the bounds of the legal authority granted to the agency by Congress.
On May 9, 2024, the EPA published a final rule that, among other things, repealed the ACE rule and also established emissions
guidelines for GHG emissions for existing coal-fired and new or substantially modified gas-fired power plants. The rule divides coal-
fired power plants into three categories. Those that will cease operation by 2032 are exempt from the rule. Those operating between
2032 and 2039 will be required to achieve emissions reductions equivalent to co-firing 40 percent by volume natural gas. Those
intending to operate after 2039 will be required to achieve emissions reductions equivalent to 90 percent capture of CO2 through carbon
capture and sequestration (“CCS”). While the rule has been challenged in court, the US Supreme Court declined to stay the rule while
those challenges proceed. Additionally, the new Trump Administration has indicated its intention to revise the rule. The rule could
potentially have a material adverse effect on our business, financial condition, and results of operations.
Future, additional 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 not currently adopted explicit legislation to restrict carbon dioxide emissions from
existing power plants and has not otherwise expanded the legal authority of the EPA following West Virginia v. EPA, including as it
relates to its authority to regulate carbon dioxide emissions from existing and modified power plants. However, we cannot predict
whether such legislation will be signed into law in the future. Internationally, the Paris Agreement requires member states to submit
non-binding, individually-determined emissions reduction targets. These commitments could further reduce demand and prices for
fossil fuels. Although the U.S. had withdrawn from the Paris Agreement, President Biden recommitted the U.S. in February 2021 and,
in April 2021, the Biden Administration announced a new, more rigorous nationally determined emissions reduction level of 50-52%
reduction from 2005 levels in economy-wide net GHG emissions by 2030. However, the new Trump administration has recently
announced its intention to withdraw from the Paris Agreement, so these targets from the Biden Administration may change.
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Since the 2021 Biden Administration targets were announced, the Parties of the UN Framework Convention on Climate Change have
met on several occasions, including at the 28th Conference to the Parties on the UN Framework Convention on Climate Change
(“COP28”). At the COP28, the Parties agreed to non-binding language calling on countries to transition away from fossil fuels in
energy systems to achieve net zero emissions by 2050. The impact of these actions remains unclear at this time. 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 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 and electricity from coal-fired power plants, such as Merom Station,
could be negatively impacted, which would have an adverse effect on our operations.
There have been numerous protests 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 April 2022, the White House Council on
Environmental Quality (“CEQ”) issued a final rule revoking some of the modifications made to the NEPA regulations under the
previous administration and reincorporated the consideration of direct, indirect and cumulative effects of major federal actions,
including GHG emissions. And, in January 2023, the CEQ released guidance, effective immediately, to assist federal agencies in
assessing the GHG emissions and climate change effects of their proposed actions under NEPA. However, in November 2024, the U.S.
Court of Appeals for the D.C. Circuit held that CEQ has no authority to issue regulations implementing NEPA and that CEQ’s NEPA
regulations are, therefore, invalid and of no effect.
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 power generating facilities. For example, in
2005, ten Northeastern states entered into the Regional Greenhouse Gas Initiative agreement (“RGGI”), calling for the implementation
of a cap and trade program aimed at reducing carbon dioxide emissions from power plants in the participating states. The members of
RGGI have established in statutes and/or regulations a carbon dioxide trading program. Auctions for carbon dioxide allowances under
the program began in September 2008. Since its inception, several additional states and Canadian provinces have joined RGGI as
participants or observers, while Virginia has withdrawn from RGGI via executive order by its governor. Similar to RGGI, five western
states launched the Western Regional Climate Initiative, although only California and certain Canadian provinces are currently active
participants. We cannot predict what other regional greenhouse gas reduction initiatives may arise in the future.
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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 402 of the CWA governs discharges of pollutants into waters of the United States, primarily
through National Pollutant Discharge Elimination System (“NPDES”) permits. Hallador’s Merom Generating Station is subject to an
NPDES permit for its wastewater and stormwater discharges.
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 electric power generation
operations and coal mining operations that impact such wetlands and streams. 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. The definition of
“waters of the United States,” which governs federal jurisdiction under the Clean Water Act, has been subject to many shifting
regulations and litigation in recent years. However, in May 2023, the U.S. Supreme Court issued its decision in Sackett v. EPA, which
significantly limited the scope of federal jurisdiction over wetlands under the Clean Water Act. In response to the Supreme Court’s
decision, in August 2023, EPA issued its final rule amending the definition of “waters of the United States” to conform its regulations to
the Supreme Court’s decision in Sackett. While the Sackett decision and the subsequent rule issued by EPA have reduced the scope of
federal regulation at this time, it is possible that more stringent permitting requirements may be imposed in the future, and we are not
able to accurately predict the impact, if any, of such permitting requirements.
In order for us to conduct certain activities, we may need to obtain a permit for the discharge of fill material from the U.S. 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 which veto was subsequently upheld by the D.C. Circuit Court in 2013. 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 a 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.
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Total Maximum Daily Load (“TMDL”) regulations under the CWA establish a process to calculate the maximum amount of a pollutant
that an impaired waterbody 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 or electric power generating operations could
require more costly water treatment and could adversely affect our coal production or electric power generation operations.
On November 3, 2015, the EPA published the final Effluent Limitations Guidelines and Standards (“ELG”) rule, revising the
regulations for the Steam Electric Power Generating category, which became effective on January 4, 2016. The rule sets the first federal
limits on the levels of toxic metals in wastewater that can be discharged from power plants, based on technology improvements in the
steam electric power industry over the last three decades. The combined effect of the CCR rule 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. In October 2020, the EPA published a
final rule. In August 2021, the EPA initiated supplemental rulemaking indicating that it intended to strengthen certain discharge limits.
The EPA issued a final rule for in May 2024, which established more stringent requirements for flue gas desulfurization (“FGD”)
wastewater, bottom ash transport water, and combustion residual leachate, among other measures. The new rule also established early
shutdown alternatives for plants permanently ceasing coal combustion by certain target dates. These regulations may impact the market
for our coal products and our electric power generating operations.
On April 23, 2020, the U.S. Supreme Court issued a decision in the Hawaii Wildlife Fund v. County of Maui case related to whether a
CWA permit is required when pollutants originate from a point source but are conveyed to navigable waters through a nonpoint source,
such as groundwater. The Court held that discharges to groundwater require a permit if the addition of the pollutants through
groundwater is the functional equivalent of a direct discharge from the point source into navigable waters. A number of legal cases
relevant to determination of “functional equivalent” are ongoing in various jurisdictions. It is too early to determine whether the
Supreme Court decision or the result of litigation to “functional equivalent” may have a material impact on our business, financial
condition, or results of operations.
In June 2016, the EPA published the final national chronic aquatic life criterion for the pollutant selenium in fresh water. NPDES
permits may be updated to include selenium water quality-based effluent limits based on a site-specific evaluation process, which
includes determining if there is a reasonable potential to exceed the revised final selenium water quality standards for the specific
receiving water body utilizing actual and/or project discharge information for the generating facilities. As a result, it is not yet possible
to predict the total impacts of this final rule at this time, including any challenges to such final rule and the outcome of any such
challenges.
The Merom Generating Station is subject to requirements under CWA Section 316(a) for thermal discharges and Section 316(b) for
cooling water intake structures. Section 316(a) standards allow thermal dischargers to have less stringent alternate thermal limits if they
can demonstrate that the current effluent limitations, based on water quality standards, are more stringent than necessary to protect the
aquatic organisms in the receiving water body. Merom Station is currently subject to a 316(a) variance and alternative thermal effluent
limits. If Merom Station’s 316(a) variance were revoked in the future, additional capital expenditures may be required that could be
material.
Section 316(b) standards require affected facilities to choose among seven best technology available (“BTA”) options to reduce fish
impingement. In addition, certain facilities must conduct studies to assist permitting authorities to determine whether and what site-
specific controls, if any, would be required to reduce entrainment of aquatic organisms. It is possible that this process, which includes
permitting and public input, could result in the need to install closed-cycle cooling systems (closed-cycle cooling towers), or other
technology, although the Indiana Department of Environmental Management has previously determined that the systems in place
currently at Merom Station meet the BTA requirements. If additional capital expenditures became necessary in the future, they could be
material.
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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 and electric power generating operations generate waste containing hazardous
substances. We are currently unaware of any material liability under CERCLA or analogous state laws associated with the release or
disposal of hazardous substances from our past or present mine sites or electric power generating operations.
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 as well as CCR
generated from our electric power generating operations 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.
Coal Combustion Residuals
RCRA impacts the coal industry and electric power generation industry in particular because it regulates the management and disposal
of certain coal combustion residuals (“CCR”). On April 17, 2015, the EPA finalized regulations under RCRA for the management and
disposal of CCR. Under the finalized regulations, CCR is regulated as “non-hazardous” waste and avoids the stricter, more costly,
regulations under RCRA’s hazardous waste rules. While classification of CCR 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 as well as increase the operating cost of our electric power generation operations. The CCR rule was subject to legal
challenge and ultimately remanded to the EPA. On August 28, 2020, the EPA published a final revised rule mandating closure of
unlined impoundments, with deadlines to initiate closure between 2021 and 2028, depending on site specific circumstances. Certain
provisions of the revised CCR rule were vacated by the D.C. Circuit Court in 2018. Meanwhile, on January 25, 2022, the EPA
published determinations for 9 of 57 CCR facilities who sought approval to continue disposal of CCR and non-CCR waste streams until
2023, as opposed to the initial 2021 deadline for unlined impoundments prescribed by the current rule. While the EPA issued one
conditional approval, the EPA is requiring the remaining facilities to cease receipt of waste within 135 days of completion of public
comment or around July 2022. And, in January 2023, the EPA issued six proposed determinations to deny facilities’ requests to continue
disposal into unlined surface impoundments. The current determinations, future determinations of the same nature, or similar actions in
expected future rulemakings could lead to accelerated, abrupt, or unplanned suspension of coal-fired boilers. Further, in May 2024, EPA
finalized changed to the CCR regulations for inactive surface impoundments at inactive electric utilities, referred to as “legacy CCR
surface impoundments,” and also established certain requirements for a new subcategory of CCR areas called “CCR management
units,” among other actions. The combined effect of the CCR rules and ELG regulations (discussed above) has compelled power
generating companies to close existing ash ponds and may force the closure of certain existing coal burning power plants that cannot
comply with the new standards. Such retirements may adversely affect the demand for our coal, and the CCR rule requirements and any
revisions affect our CCR landfill at Merom Generating Station.
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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. In October 2021, the Biden Administration proposed the
rollback of new rules promulgated under the Trump Administration and, in June 2022, the USFWS and the National Marine Fisheries
Service published a final rule rescinding the 2020 regulatory definition of “habitat.”
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 Regulation
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 regulations. 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.
Climate Change Issues
Physical Climate Risks. Increased frequency of severe and extreme weather events associated with climate change could materially
impact our facilities, energy sales, and results of operations. We are unable to predict these events. However, we perform ongoing
assessments of physical risk, including physical climate risk, to our business. More extreme and volatile temperatures, increased storm
intensity and flooding, and more volatile precipitation leading to changes in lake and river levels are among the weather events that are
most likely to impact our business.
Transition Climate Risks. Future legislative and regulatory programs, at both the federal and state levels, could significantly limit
allowed GHG emissions or impose a cost or tax on GHG emissions. Revised or additional future GHG legislation and/or regulation
related to the generation of electricity or the extraction, production, distribution, transmission, storage and end use of natural gas could
materially impact our gas supply, financial position, financial results and cash flows.
Regarding federal policies, we continue to monitor the implementation of any final and proposed climate change-related legislation and
regulations, including the Infrastructure Investment and Jobs Act, signed into law in November 2021; the development of the
Enhancement and Standardization of Climate-Related Disclosures, proposed by the SEC in March 2022; the Inflation Reduction Act
(“IRA”), signed into law in August 2022; and the EPA’s methane regulations for the oil and natural gas industry, but we cannot predict
their impact on our business at this time. We have identified potential opportunities associated with the Infrastructure Investment and
Jobs Act and the IRA and are evaluating how they may align with our strategy going forward. The energy-related provisions of the
Infrastructure Investment and Jobs Act include new federal funding for power grid infrastructure and resiliency investments, new and
existing energy efficiency and weatherization programs, electric vehicle infrastructure for public chargers and additional Low Income
Home Energy Assistance Program funding over the next five years. The IRA contains climate and energy provisions, including funding
to decarbonize the electric sector.
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Suppliers
The main types of goods we purchase for our mining operations are mining equipment and replacement parts, steel-related (including
roof control) products, belting products, lubricants, electricity, fuel, and tires. For our electric operations, we purchase coal, limestone,
fuel oil, anhydrous ammonia, and other chemicals and items necessary to operate Merom Station. 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 principal 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. CAA, 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 re-
opened as a significant fuel source for utilities and has enabled them to burn lower-cost high sulfur coal.
The ILB consists of coal mining operations covering more than 50,000 square miles in Illinois, Indiana, and western Kentucky. The ILB
is centrally located between four of the largest regions that consume coal as fuel for electricity generation (East North Central, West
South Central, West North Central, and East South Central). The region also has access to sufficient rail and water transportation routes
that service coal-fired power plants in these regions as well as other significant coal consuming regions of the South Atlantic and
Middle Atlantic.
U.S. Coal Industry
The major coal production basins in the U.S. include ILB, Central Appalachia (“CAPP”), Northern Appalachia (“NAPP”), 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 PRB is located in northeastern Wyoming
and southeastern Montana. The WB includes western Colorado, eastern Utah, and southern Wyoming. Hallador Energy Company
(“Hallador”), through its wholly-owned subsidiary Sunrise Coal, LLC (“Sunrise Coal”), 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 U.S. 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.
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Human Capital
As of December 31, 2024, Hallador and its subsidiaries employed 615 full-time employees and temporary miners, 582 of those
employees and temporary miners are directly involved in the coal mining or coal washing process. Our coal workforce is entirely
union-free. At our power plant, our operator, Consolidated Asset Management Services (CAMS) employs represented workers. While
these workers are not Hallador Power employees, labor disruptions within the CAMS workforce could disrupt our operations at the
plant. To attract and retain top talent, we provide competitive wages, an annual bonus for all employees, excellent benefits, an employee
health clinic and a culture that is committed to health and safety at all levels.
Employee health and safety is a top priority at Hallador’s wholly owned subsidiary, Sunrise Coal. With a robust safety department and
safety standards that exceed mandated guidelines, we make safety the foundation of everything we do. While every precaution is taken
to prevent mine emergencies, Sunrise Coal has its own private mine rescue team. This team is trained and ready to manage emergency
situations at a Sunrise Coal facility, but also ready and available to assist other mine rescue teams. We continuously monitor safety data
such as injury severity, violations per inspection day, and significant and substantial citations and compare to the national averages
noting that in 2021 we were at or below the national averages in all three categories. For more information about citations or orders for
violations of standards under the FMSHA, as amended by the Miner Act, please see our Exhibit 95 to this Annual Report on Form 10-
K.
While other companies have moved to high deductible health plans, Hallador is committed to providing comprehensive affordable
health insurance with low-cost deductibles and co-pays to take care of our employees and their families. We believe in decreasing the
barriers to healthcare, so employees and their dependents do not have to delay care. Our employees and their families also have access
to a private full-time health and wellness clinic, with free medications, no cost diagnostics, and a wellness coach.
Beyond investing in the safety and health of its employees, Hallador invests in educational opportunities for its employees. All
continuing education requirements and training are completely paid for by the company and tuition reimbursement programs are
available to every employee companywide.
Recent Regulatory Developments from the Presidential Transition
On January 20, 2025, Donald J. Trump was inaugurated as the 47th President of the United States of America. Since President Trump’s
inauguration, the new Administration has rescinded various Biden Administration Executive Orders and has issued new Executive
Orders and taken other related executive actions, which may impact the market for our coal products or our electric power generating
operations. These new Executive Orders reflect policy objectives such as promoting the development of domestic energy resources,
expedited permitting for energy projects, potential withdrawal from international climate change agreements, and the potential
reconsideration of US EPA’s 2009 endangerment finding for greenhouse gas emissions under the Clean Air Act, among other issues.
Many of these policy objectives will require further rulemaking actions or other formal steps before they would become law. In
addition, the new Administration has taken actions to reduce the number of federal employees and to eliminate certain federal agencies
or reduce their authority. As a result, there is significant uncertainty regarding whether or how regulations and the agencies that
administer and enforce these regulations may change as a result of the actions taken to date and possible future actions by the new
Administration. Additionally, there may be litigation over such regulatory changes, and if public enforcement decreases as a result of
such changes, private litigation over environmental matters may increase.
Other
We have no significant patents, trademarks, licenses, franchises, or concessions.
Our corporate office, as well as Sunrise Coal and Hallador Power’s corporate office, is located at 1183 East Canvasback Drive, Terre
Haute, Indiana, 47802. All offices can be reached at 812.299.2800. Terre Haute is approximately 70 miles west of Indianapolis.
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Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to these reports
are available, free of charge, on our website at www.halladorenergy.com under the “Investor Relations” section, as soon as reasonably
practicable after we electronically file such reports with, or furnish them to, the SEC at www.sec.gov.
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 could have material adverse impacts on our business and financial condition that we currently
cannot predict.
Weakness in global economic conditions or economic conditions in any of the industries we serve or in the financial markets could
materially adversely affect our business and financial condition. For example:
●
the demand for electricity in the U.S. and globally may decline if economic conditions deteriorate, which may negatively
impact the revenues, margins, and profitability of our business;
●
any inability of our customers to raise capital could adversely affect their ability to honor their obligations to us; and
●
our future ability to access the capital markets may be restricted as a result of future economic conditions, which could
materially impact our ability to grow our business, including development of our coal reserves.
The stability and profitability of our operations could be adversely affected if our customers do not honor existing contracts or do
not extend existing contracts or enter into new long-term contracts for electric power, capacity or coal.
In 2024, a significant portion of our electric power, capacity and coal sales were under contracts having a term greater than one year,
which we refer to as long-term contracts. These 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 could make it more difficult for us to
enter into long-term contracts with our customers, and if supply exceeds demand in the electric power, capacity and coal industries, our
customers 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 an
increasing portion of our revenue stream to the increased volatility of the spot market.
Our financial performance may be impacted by price fluctuations in the electric power markets, as well as fluctuations in coal
markets and other market factors that are beyond the Company’s control.
Market prices for power, capacity, coal and other ancillary services are unpredictable and tend to fluctuate substantially. Electric power
generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and
demand imbalances, especially in the day-ahead and spot markets. While we currently sell a significant portion of our electric power
pursuant to long-term contracts (where we may be less susceptible to day-to-day fluctuations), we also sell a material amount of power
in the competitive wholesale market including through MISO. A significant portion of the electricity we sell is used by residential and
commercial customers for heating and air conditioning Long and short-term power prices may fluctuate substantially due to factors
outside of the Company’s control, including:
●
changes in generation capacity in the Company’s markets, including the addition of new supplies of power as a result of the
development of new plants, expansion of existing plants, the continued operation of uneconomic power plants due to state
subsidies, retirement of existing plants or addition of new transmission capacity;
●
electric supply disruptions, including plant outages and transmission disruptions;
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●
changes in power transmission infrastructure;
●
transportation capacity constraints or inefficiencies;
●
weather conditions, including extreme weather conditions and seasonal fluctuations, including the effects of climate change;
●
changes in commodity prices and the supply and available inventory of commodities, including but not limited to natural gas,
coal and oil;
●
changes in the demand for power, or in patterns of power usage, including the potential development of demand-side
management tools and practices, distributed generation, and more efficient end-use technologies;
●
development of new fuels, new technologies and new forms of competition for the production of power;
●
economic and political conditions;
●
changes in law, including judicial decisions, environmental regulations and environmental legislation; and
●
federal, state and provincial power regulations and legislation, and regulations and actions of the ISO and RTOs.
Such factors and the associated fluctuations in power prices have affected the Company’s profitability in the past and are expected to
continue to do so in the future.
Some of our long-term sales contracts contain provisions allowing for the termination of the contract or the suspension of
purchases by customers or, in certain cases, the renegotiation of prices.
Several of our long-term electric power, capacity and coal contracts 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 could include force majeure, labor disputes, mechanical malfunctions and changes in government regulations, including, in
the case of our coal contracts, changes in environmental regulations rendering use of our coal inconsistent with the customer’s
environmental compliance strategies. Additionally, most of our long-term coal 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 or similar terms, our business, financial condition and results of operations could be adversely
affected.
Further, long-term coal sales contracts may contain provisions that allow for the purchase price to be renegotiated at periodic intervals,
however, we had no coal contracts with price reopeners at December 31, 2024. These price reopener provisions may automatically set a
new price based on the prevailing market price or, in some instances, require the parties to the contract to agree on a new price. Any
adjustment or renegotiation leading to a significantly lower contract price could adversely affect our operating profit margins.
Accordingly, long-term contracts may provide only limited protection during adverse market conditions. In some circumstances, failure
of the parties to agree on a price under a reopener provision can also lead to early termination of a contract.
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We depend on a few customers for a significant portion of our revenues, and the loss of one or more significant customers could
affect our ability to maintain the sales volume and price of our products.
In our Electric Operations, a material portion of our 2024 revenue was derived from a power purchase agreement with Hoosier (“PPA”),
which we entered into as part of our acquisition of Hoosier Energy’s Merom Generation Station (“Merom”) in 2022. The PPA (as
amended in August 2023) expires at the end of 2028. While we have subsequently added additional electric power customers and
purchasers of accredited capacity, the loss of one or more of these material customers could have a material adverse effect on our
business, financial condition and results of operations.
During 2024, we derived 89% of our delivered energy and 88% of our capacity sales revenue from three and four customers,
respectively, each of which representing at least 10% of sales revenue. Additionally, we derived 96% of our third-party coal sales from
four customers, each representing at least 10% of coal sales. 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.
Our recent efforts to sell our accredited capacity to long-term customers may not be successful.
In light of the fact that the Company believes it holds a considerable portion of the remaining unsold accredited capacity in MISO Zone
6, covering Indiana and parts of western Kentucky, the Company has recently focused its efforts on entering into one or more long-term
contracts for the sale of its energy and capacity to large load end user(s) through a utility or cooperative, including through a data center
targeted Request for Proposal (RFP) undertaken in 2024. This RFP resulted in a wholly owned subsidiary, Hallador Power Company,
LLC, executing a Conversion Transaction Commitment Agreement with a leading global data center developer on January 2, 2025. The
transaction contemplated thereby remains subject to a number of conditions, including negotiation of definitive documentation and the
selection of a utility partner and there can be no assurance that definitive agreements will be entered into or that the proposed
transaction will be consummated on the terms or timeframe currently contemplated, or at all. Failure to consummate the transaction
contemplated by the Conversion Transaction Commitment Agreement and/or any other similar agreement(s) contemplated by the
Company’s recent RFP efforts may 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 electric power, capacity and 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.
Contractors that we use to provide employees at our power plant may experience work stoppages, slowdowns, lockouts or other labor
disputes.
At Merom, our operator, Consolidated Asset Management Services (“CAMS”), employs represented workers. While these workers are
not Hallador Power employees, work stoppages, slowdowns, lockouts or other labor disputes within the CAMS workforce could
adversely affect and disrupt our productivity and operations at the plant.
In our Coal Operations, although none of our coal 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
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affect our productivity and increase the risk of work stoppages at our mining complexes. In addition, even if we remain union-free, our
operations could still be adversely affected by work stoppages at unionized companies, particularly if union workers were to orchestrate
boycotts against our operations.
The operation and maintenance of the Merom facilities or future investment in the Merom facilities are subject to operational risks
that could adversely affect our financial position, results of operations and cash flows.
In October 2022, the Company, through its subsidiary Hallador Power, completed its acquisition of Merom, our one Gigawatt
Generating Station located in Sullivan County, Indiana pursuant to an Asset Purchase Agreement (“APA”) with Hoosier Energy. The
operation and maintenance of generating facilities like Merom involves many risks, including the performance by key contracted
suppliers and maintenance providers; increases in the costs for or limited availability of key supplies, labor and services; breakdown or
failure of facilities; curtailment of facilities by counterparties; or the impact of unusual, adverse weather conditions or other natural
events, as well as the risk of performance below expected levels of output or efficiency. The Merom facilities contain older generating
equipment, which even if maintained in accordance with good engineering practices, may require additional capital expenditures to
continue operating at peak efficiency. From time to time, the Merom facilities may experience transformer failures that may cause one
or more of its units to be offline for an extended period of time. We may also be subject to costs associated with any unexpected failure
to produce and deliver power, including failure caused by breakdown or forced outage, as well as the repair of damage to facilities due
to storms, natural disasters, wars, sabotage, terrorist acts and other catastrophic events. Additionally, supply chain shortages or delays
on key operating components, including but not limited to, transformers, boiler equipment and chemicals or catalysts could materially
and adversely impact our operations and reduce revenues or expose the company to significant cover damages related to longer term
contracts. In connection with the APA, the Company assumed certain decommissioning costs and environmental responsibilities. In the
event these assumed costs and responsibilities exceed the Company’s estimates, the Company may incur additional liabilities that could
have an adverse effect on the Company’s business, financial results and prospects.
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. Under our outstanding Form S-3 “universal
shelf” registration statement, we have the ability, subject to market conditions, to access the debt and equity capital markets as needed,
including through the use of our outstanding At-the -Market (“ATM”) offering program. If we raise additional funds by issuing equity
securities under our ATM program or otherwise, our stockholders may experience dilution. 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.
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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, could 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 could 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.
We may not recover our investments in our power, mining, and other assets, which may require us to recognize impairment charges
related to those assets.
The value of our assets has from time to time been adversely affected by numerous uncertain factors, some of which are beyond our
control, including, but not limited to 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 fourth quarter of 2024, we completed our annual impairment analysis, which was based upon
the finalized operating plans of the Company, market driven pricing and cost trends. As part of that analysis, the Company determined
the carrying amount of its long-lived assets were not recoverable and recorded a non-cash, long-lived asset impairment charge of $215.1
million in the fourth quarter of 2024. See “Note 19 – Impairment of Coal Properties” to the Consolidated Finance Statements in this
Form 10-K for further information on the impairment analysis. The factors noted above may trigger the recognition of additional
impairment charges in the future, which could have a substantial impact on our results of coal operations.
In the future, as investments in Merom become more significant, the value of those assets could be adversely affected by numerous
uncertain factors, some of which are beyond our control, including, but not limited to unfavorable changes in the economic
environments in which we operate, environmental, litigation, weather, and regulatory and/or legal changes. These factors may trigger
the recognition of additional impairment charges in the future, which could have a substantial impact on our results of power
operations.
If we are unable to comply with the covenants contained in our credit agreement, the lenders could declare all amounts outstanding
to be due and payable and foreclose on their collateral, which could materially adversely affect our financial condition and
operations.
As disclosed in “Note 4 – Bank Debt” to our consolidated financial statements, on September 27, 2024, we executed the First
Amendment (“First Amendment”) to the Fourth Amended and Restated Credit Agreement, dated as of August 2, 2023 (as amended, the
“Credit Agreement”), in which we adjusted existing covenants and added new ones: (i) waived the Company’s Leverage Ratio
requirement for the third and fourth quarters of 2024, increased the threshold to 5.50 to 1.00 for the first quarter of 2025, and decreased
the threshold back to 2.25 to 1.00 for each fiscal quarter thereafter, (ii) the Debt Service Coverage Ratio requirement (1.25 to 1.00) was
waived from third quarter of 2024 through the first quarter of 2025, (iii) added a maximum First Lien Leverage Ratio for the first
quarter of 2025, calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 3.50 to 1.00; (iv) added a
minimum liquidity requirement of $10.0 million, beginning on the First Amendment execution date and ending when the second quarter
of 2025 compliance certificate is received, and (v) added a minimum quarterly EBITDA requirement, as defined in the First
Amendment, of $5.0 million for the third quarter of 2024 through the first quarter of 2025.
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As of December 31, 2024, our liquidity of $37.8 million and quarterly EBITDA of $6.2 million were in compliance with the
requirements of the Credit Agreement.
Our ability to comply with the covenants in our credit agreement may be affected by changes in economic or business conditions or
other events that are beyond our control. If we fail to comply with these covenants, we may be in default under our credit agreement,
which may entitle the lenders to accelerate the debt obligations. In order to avoid defaulting on our indebtedness, we may be required to
take actions such as reducing or delaying capital expenditures, reducing or eliminating dividends or share repurchases, selling assets,
restructuring or refinancing all or part of our existing debt, or seeking additional equity capital, any of which may not be available on
terms that are favorable to us, if at all. In the event of an event of default under 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.
Our indebtedness may limit our ability to borrow additional funds or capitalize on business opportunities.
As of December 31, 2024, our funded bank debt was $44.0 million and we held letters of credit totaling $19.4 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
capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have
similar or greater restrictions.
If our financial condition deteriorates, certain credit assurance provisions in our power contracts could require additional
collateral.
Certain of our power contracts contain credit assurance provisions tied to our financial condition. Should our financial condition
deteriorate, these provisions may require substantial collateral that may have a materially adverse effect on our financial condition.
Investor and lender focus on ESG matters may negatively impact our business, financial results, and stock price.
Companies across all industries, including companies in the fossil-fuel industry, have faced increased scrutiny from stakeholders related
to their ESG practices. Companies that do not adapt or comply with investor or stakeholder expectations and standards or are perceived
to have not responded appropriately to ESG issues, regardless of any legal requirement to do so, may suffer reputational damage and the
business, financial condition, and stock price of such companies could be materially and adversely affected. Several advocacy groups,
both domestically and internationally, have campaigned for governmental and private action to promote change at public companies
related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds,
universities, and other members of the investing community. These activities include increasing attention to and demands for action
related to climate change, promoting the use of substitutes to fossil-fuel products, encouraging the divestment of fossil-fuel equities,
and pressuring lenders to limit funding to companies engaged in the extraction of fossil-fuel reserves. These activities could increase
costs, impact our supply chain, reduce demand for our coal, reduce our profits, increase the potential for investigations and litigation,
impair our brand, limit our choices for lenders, insurance providers and business partners, and have negative impacts on our stock price
and access to capital markets.
In addition, certain organizations that provide corporate governance and other corporate risk information to investors have developed
scores and ratings to evaluate companies and investment funds based upon ESG or “sustainability” metrics. Currently, there are no
universal standards for such scores or ratings, but consideration of sustainability evaluations is becoming more broadly accepted by
investors. Indeed, many investment funds focus on positive ESG business practices and sustainability scores when making investments,
whereas other funds may use certain ESG criteria to “screen” certain sectors, such as coal or fossil fuels more generally, out of their
investments. In addition, investors,
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particularly institutional investors, use these scores to benchmark companies against their peers and if a company is perceived as
lagging, these investors may engage with companies to require improved ESG disclosure or performance or sell their interests in the
company, particularly if its ESG performance does not improve. Moreover, certain members of the broader investment community may
consider a company’s sustainability score as a reputational or other factor in making an investment decision. Companies in the energy
industry, and in particular those focused on coal, natural gas, or oil extraction, often do not score as well under ESG assessments
compared to companies in other industries. Consequently, a low ESG or sustainability score could result in our securities being
excluded from the portfolios of certain investment funds and investors, restricting our access to capital to fund our continuing
operations and growth opportunities. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to
compete as effectively to recruit or retain employees, which may adversely affect our operations.
Public statements with respect to ESG matters, such as emission reduction goals, other environmental targets, or other commitments
addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities
related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. Certain
non-governmental organizations and other private actors have filed lawsuits under various securities and consumer protection laws
alleging that certain ESG-statements, goals, or standards were misleading, false, or otherwise deceptive. As a result, we may face
increased litigation risks from private parties and governmental authorities related to our ESG efforts. Similarly, we could be criticized
by ESG detractors for the scope and nature of any ESG policies or initiatives we implement. We could also be subjected to negative
responses by governmental actors, such as state legislation, retaliatory legislative treatment or litigation by state or federal agencies, or
face negative publicity campaigns that could adversely affect our reputation, business, financial performance and growth. In addition,
any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of
investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further ESG-related focus and
scrutiny.
Enhanced data privacy and data protection laws and regulations or any non-compliance with such laws and regulations, could
adversely affect our business and financial results.
Consistent with the trend established by passage of the General Data Protection Regulation (the “GDPR”), the development and
evolving nature of domestic and international privacy regulation and enforcement could impact and potentially limit how Hallador
processes personal information. For example, California residents have certain privacy rights (including the right to limit the use and
disclosure of sensitive personal information, and the right to request that a business delete personal information collected about them,
among other rights), established by the California Consumer Privacy Act (“CCPA”) and enforced by a state privacy regulator, resulting
in more scrutiny of business practices and disclosures. Additional states including Virginia, Utah, Connecticut, Colorado, and
Nevada have similarly adopted enhanced data privacy legislation patterned after the standards set forth by CCPA, including broader
data access rights, with some states even requiring businesses to perform data protection assessments for certain processing activities. In
2025, state privacy laws go into effect in a number of states, including Delaware, Maryland, Minnesota, Nebraska, and New Jersey,
among others.
As new laws and regulations are enacted by legislators or adopted by regulators, requiring businesses to implement processes to enable
customer access to their data and enhanced data protection and management standards, we cannot forecast the impact that they may
have on the Company’s business. Any non-compliance with laws may result in proceedings or actions against the Company by as many
as 35 governmental entities or individuals. Moreover, any inquiries or investigations, government penalties or sanctions, or civil actions
by individuals may be costly to comply with, resulting in negative publicity, increased operating costs, significant management time
and attention, and may lead to remedies that harm the business, including fines, demands or orders that existing business practices be
modified or terminated.
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Risks Related to our Industry
Substantial or extended volatility in coal prices could negatively impact our results of operations in both our Electric Operations and
Coal Operations segments.
Our results of operations are primarily dependent upon the price we pay for our coal in the case of our Electric Operations, or the prices
we receive for our coal in our Coal Operations, as well as our ability to improve productivity and control costs. These prices
depend upon factors beyond our control, including:
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the supply of and demand for domestic and foreign coal;
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weather conditions and patterns that affect demand for or our ability to produce coal;
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the proximity to and capacity of transportation facilities;
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supply chain and cost of raw materials for coal operations;
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competition from other coal suppliers;
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domestic and foreign governmental regulations and taxes;
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the price and availability of alternative fuels;
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the effect of worldwide energy consumption, including the impact of technological advances on energy consumption;
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overall domestic and global economic conditions;
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international developments impacting supply of coal; and
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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. With respect to our Coal
Operations, 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 (although the adverse impact of a decline in coal prices may
in some cases be offset by lower coal prices we pay in our Electric Operations).
Competition within the coal industry could adversely affect our financial results.
In our Coal Operations, 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. In addition, deregulation within the coal industry, including as a result
of actions taken by the new Presidential Administration, may encourage new market entrants and could increase the number of
competitors we face. Some competitors could 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 could impact our ability to
retain or attract customers and could adversely impact our revenues and cash from operations. In our Electric Operations, similar risks
apply with respect to our ability to purchase coal on attractive terms relative to other competitors in the market.
Changes in taxes or tariffs and other trade measures could adversely affect our results of operations, financial position and cash
flows.
We pay certain taxes and fees related to our operations. Congress or state legislatures may seek to increase these taxes and fees that
relate specifically to the coal industry. We cannot predict further developments, and such increases could have a material adverse effect
on our results of operations, financial position, and cash flows.
Further, there is uncertainty surrounding tariffs and international trade relations, and it is difficult for us to predict future trade measures
and the impact they will have on our business and operations. In early 2025, the new U.S. Presidential
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Administration threatened and imposed tariffs on imports from various countries. In response, some of these countries threatened or
imposed tariffs on imports from the U.S. How long current tariffs will remain in place, and whether the new Administration will enact
the threatened tariffs or impose entirely new ones is uncertain.
These newly enacted tariffs, additional new tariffs and other trade measures could adversely affect our results of operations, financial
position and cash flows. In response to the tariffs imposed by the U.S., the European Union, Canada, Mexico and China have imposed
tariffs on U.S. goods and services. The new tariffs, along with any additional tariffs or trade restrictions that may be implemented by the
U.S. 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 U.S. or other
potentially adverse economic outcomes. While tariffs and other retaliatory trade measures imposed by other countries on U.S. 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, including plans by utilities to shut down or move away from
coal-fired generation, have affected our ability to sell the coal we produce.
The domestic electric utility industry accounts for the vast majority of domestic coal consumption. The amount of coal consumed by the
domestic electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental
regulations, and the price and availability of competing fuels for power plants such as nuclear, natural gas and fuel oil as well as
alternative sources of energy. Gas-fueled generation has the potential to displace a significant amount of coal-fired electric
power generation in the near term, particularly from older, less efficient coal-fired powered generators.
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. Such mandates,
combined with other incentives to use renewable energy sources, such as tax credits, could make alternative fuel sources more
competitive with coal. 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. A decrease in coal consumption by the domestic electric utility industry could adversely affect the
demand for or the price of coal, which could negatively impact our results of operations and reduce our cash from operations.
Other factors, such as efficiency improvements associated with technologies powered by electricity have slowed electricity demand
growth and could contribute to slower growth in the future. Further decreases in the demand for electricity, such as decreases that could
be caused by a worsening of current economic conditions or a prolonged economic recession, could have a material adverse effect on
the demand for coal and our business over the long term.
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 and pollutants in wastewater 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 could require further emission reductions and associated
emission control expenditures. These laws and regulations could 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, MATS, 316(a) and
(b) rules, CCR rules, and ELGs 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. These rules could also lead to material capital expenditures for our electric
generating operations.
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Our operations are subject to a series of risks resulting from climate change.
Combustion of fossil fuels, such as the coal we produce in our mining operations and the energy we produce in our electric operations,
results in the emission of carbon dioxide into the atmosphere. Concerns about the environmental impacts of such emissions have
resulted in a series of regulatory, political, litigation, and financial risks for our business. Global climate issues continue to attract public
and scientific attention. Many scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere could
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.
Following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations
that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources,
require the monitoring and annual reporting of GHG emissions from certain sources in the U.S., or constrain the emissions of power
plants (though such emissions restraints have been subject to challenge).
Separately, various states and groups of states have adopted or are considering adopting legislation, regulations, or other regulatory
initiatives that are focused on such areas as GHG cap-and-trade programs, carbon taxes, reporting and tracking programs, and
restriction of emissions. Internationally, the Paris Agreement requires member states to submit non-binding, individually-determined
emissions reduction targets. These commitments could further reduce demand and prices for fossil fuels. Although the U.S. had
withdrawn from the Paris Agreement, the U.S. rejoined the Agreement in 2021 and, in April 2021, established a goal of reducing
economy-wide net GHG emissions 50-52% below levels by 2030. However, the new Trump Administration has recently announced its
intention to withdraw from the Paris Agreement, so these targets from the Biden Administration may change.
Since the 2021 Biden Administration targets were announced, the Parties of the UN Framework Convention on Climate Change have
met on several occasions, including at the 28th Conference to the Parties on the UN Framework Convention on Climate Change
(“COP28”). At the COP28, the Parties agreed to non-binding language calling on countries to transition away from fossil fuels in
energy systems to achieve net zero emissions by 2050. Although no legally binding commitment or timeline to phase out or phase down
all fossil fuels was made, there can be no guarantees that countries will not seek to implement such a binding phase out in the future.
The full impact of these actions is uncertain at this time and it is unclear what additional initiatives may be adopted or implemented that
may have adverse effects upon us and our operators’ operations.
Governmental, scientific, and public concern over climate change has also resulted in increased political risks. For example, in
January 2021, President Biden issued an executive order that commits to substantial action on climate change, calling for, among other
things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil-fuel
industry, a doubling of electricity generated by offshore wind by 2030, and increased emphasis on climate-related risks across
governmental agencies and economic sectors. While the Biden executive order has now been rescinded by the new Trump
Administration, the political dynamic could change yet again in the future. Other actions that may be pursued include restrictive
requirements on new pipeline infrastructure or fossil-fuel export facilities or the promulgation of a carbon tax or cap and trade program.
Further, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions
inventories, regional GHG cap and trade programs, or the establishment of renewable energy requirements for utilities. Depending on
the particular program, we or our customers 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.
Additionally, on March 6, 2024, the SEC adopted new rules relating to the disclosure of a range of climate-related data risks and
opportunities, including financial impacts, physical and transition risks, related governance and strategy and GHG emissions, for certain
public companies. We are currently assessing this rule but at this time we cannot predict the ultimate impact of the rule on our business
or those of our customers. As a result of these final rules, we or our customers could incur increased costs related to the assessment and
disclosure of climate-related risks and certain emissions metrics. In addition, enhanced climate disclosure requirements could accelerate
the trend of certain
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stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive
sectors.
Apart from governmental regulation, there are also increasing financial risks for fossil-fuel producers as stakeholders of fossil-fuel
energy companies 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. For example, at COP26, the Glasgow Financial Alliance for Net Zero
(“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital
committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets
to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial
institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil-fuel sector. In late 2020,
the Federal Reserve announced it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial
regulators focused on addressing climate-related risks in the financial sector. However, in January 2025 the Board of Governors of
the US Federal Reserve System and Federal Deposit Insurance Corporation announced plans to withdrawing as members of the NGFS.
Although we cannot predict the effects of these actions, such limitation of investments in and financing, bonding, and insurance
coverages for fossil-fuel energy companies could adversely affect our coal mining operations.
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 could result in either us restricting or canceling 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.
Climate change may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or
changes in meteorological and hydrological patterns that could adversely impact our operations. Such physical risks may result in
damage to our facilities or otherwise adversely impact operations which could decrease our production. We may not have insurance to
cover these risks and the consequences for our operations could have a negative impact on the costs and revenues from operations.
We or our customers could be subject to risks related to 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 U.S. 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. Separately, litigation has been brought against certain fossil-fuel companies alleging that they have been aware of the
adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or consumers. 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.
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Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have
environmental contamination, which could result in liabilities to us. In addition, government inspectors, under certain
circumstances, have the ability to order our operations to be shut down based on environmental considerations.
Our operations currently use hazardous materials and generate limited quantities of hazardous wastes from time to time. Drainage
flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as “acid mine
drainage.” Additionally, our electric power generating operations result in air emissions, wastewater effluent, and the generation of coal
combustion residuals. We could become subject to claims for toxic torts, natural resource damages and other damages, as well as for the
investigation and clean-up of soil, surface water, groundwater and other media. Such claims may arise, for example, out of conditions at
sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such
claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or
for the entire share. In addition, government inspectors, under certain circumstances, may have the ability to order our operations to be
shut down based on a perceived or actual violation of regulations concerning hazardous substances and other matters related to
environmental protection.
These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to hazardous
substances or wastes associated with our operations, could result in costs and liabilities that could adversely affect us.
Litigation resulting from disputes with our customers could 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 could 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 profitability in our Coal Operations could decline due to unanticipated mine operating conditions and other events that are not
within our control and that may not be fully covered under our insurance policies.
Our mining operations are influenced by changing conditions or events that can affect production levels and costs at particular mines
for varying lengths of time and, as a result, can diminish our profitability. These conditions and events include, among others:
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mining and processing equipment failures and unexpected maintenance problems;
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unavailability of required equipment;
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prices for fuel, steel, explosives and other supplies;
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fines and penalties incurred as a result of alleged violations of environmental and safety laws and regulations;
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variations in thickness of the layer, or seam, of coal;
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amounts of overburden, partings, rock and other natural materials;
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weather conditions, such as heavy rains, flooding, ice and other natural events affecting operations, transportation or
customers;
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accidental mine water discharges and other geological conditions;
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seismic activities, ground failures, rock bursts or structural cave-ins or slides;
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fires;
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employee injuries or fatalities;
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labor-related interruptions;
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increased reclamation costs;
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inability to acquire, maintain or renew mining rights or permits in a timely manner, if at all;
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fluctuations in transportation costs and the availability or reliability of transportation; and
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unexpected operational interruptions due to other factors.
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These conditions have the potential to significantly impact our operating results. Prolonged disruption of production at any of our mines
would result in a decrease in our 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
could 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 could
increase substantially in the future and could 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 could go out of
business or be otherwise unable to fulfill their contractual obligations or could 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 could try to hamper fossil-fuel companies by other means including pressuring insurance and surety
companies into restricting access to certain needed coverages.
Our Electric and Coal 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 and the electric generation
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. Many of these same risks apply to our electric operations and the operation of a coal-fired
generating facility, including impacts on air, surface water, groundwater and the environment. 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 could be costly and time-
consuming and could 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
could occur, which could materially affect our mining operations, cash flow, and profitability, either through direct impacts on our
mining and electric operations, or indirect impacts that discourage or limit our customers’ use of coal or purchase of coal-fired
electricity. Federal and state laws addressing 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.
Anticipated changes in the U.S. political environment, including those resulting from the change in Presidential Administration and
control of Congress, and to regulatory agencies, may result in significant changes to regulatory framework and enforcements.
As a result of the 2024 presidential election, changes in the Presidency and both houses of Congress may result in significant changes
in, and have resulted in uncertainty with respect to, legislation, regulation, implementation or repeal of laws and rules related to our
industry, our coal products, and our electric power operations. The new Presidential Administration has rescinded various prior
Executive Orders and has issued new Executive Orders and taken other related executive actions. Many of these policy changes will
require further rulemaking actions or other formal steps
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before they would become law. In addition, the new Administration has taken actions to reduce the number of federal employees and to
eliminate certain federal agencies or reduce their authority. As a result, there is significant uncertainty regarding whether or how
regulations and the agencies that administer and enforce these regulations may change as a result of the actions taken to date and
possible future actions by the new Administration. Additionally, there may be litigation over such regulatory changes, and if public
enforcement decreases as a result of such changes, private litigation over environmental matters may increase.
Changes to existing policies and rules regarding our industry, including those recently instituted, in addition to anticipated new rule
proposals, may result in significant regulatory changes, increased penalties for non-compliance, increased competition, or increased
private litigation. We also anticipate that there may be changes in legislative control and legislative priorities. As a result, future
legislation may be proposed or passed that may adversely affect our business, operating results and financial condition.
We continually monitor these developments in order to respond to the changing regulatory environment impacting our business. While
it is not possible to predict whether and when any such changes will occur, specific proposals discussed during and after the election,
including the U.S. withdrawal from the Paris Agreement, could harm our business, operating results and financial condition. If we are
slow or unable to adapt to any such changes, our business, operating results and financial condition could be adversely affected.
We may be unable to obtain and renew permits necessary for our operations, which could reduce our production, cash flow and
profitability.
Mining and electricity generation companies must obtain numerous governmental permits or approvals that impose strict conditions and
obligations relating to various environmental and safety matters in connection with our operations. 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.
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.
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.
Inflation could result in higher costs and decreased profitability.
The U.S., European Union and other large economies have recently experienced inflation at a rate significantly higher than recent years.
Current and future inflationary effects may be driven by, among other things, governmental stimulus and monetary policies, supply
chain disruptions and geopolitical instability, including the ongoing military conflict between Ukraine and Russia, and conflicts in the
Middle East. This recent inflation has resulted in rising prices, including increases in freight rates, prices for energy and other costs, and
has adversely impacted us and may further impact us negatively in the future. Sustained inflation could result in higher costs for
transportation, energy, materials, supplies and labor. Our efforts to recover inflation-based cost increases from our customers may be
hampered as a result of the structure of our contracts and competitive pressures. Accordingly, substantial inflation may have an adverse
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impact on our business, financial position, results of operations and cash flows. Inflation has also resulted in higher interest rates in the
U.S., which could increase our cost of debt borrowing in the future.
Increases in interest rates could adversely affect our business.
Although the Federal Reserve decreased the federal interest rate multiple times in 2024, the rate continues to be elevated and there can
be no assurance that the rates will continue to decrease or that it will not be increased in 2025 or beyond. We have exposure to past
increases in interest rates and may be affected further in the future. Based on our current variable debt level of $44.0 million as of
December 31, 2024, comprised of funds drawn on our outstanding bank debt, an increase of one percentage point in the interest rate
will result in an increase in annual interest expense of slightly more than $0.4 million. Any indebtedness we incur in the future may also
expose us to increased interest rates, whether as a result of higher fixed rates at the time such a new facility is entered into or because
such new indebtedness accrues interest at a variable rate. As a result, our results of operations, cash flows and financial condition could
be materially adversely affected by significant increases in interest rates.
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 could face difficulties in the future
that could 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.
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.
Political or financial instability, currency fluctuations, the outbreak of pandemics or other illnesses (such as the COVID- 19 pandemic),
labor unrest, transport capacity and costs, port security, weather conditions, natural disasters, or other events that could alter or suspend
our operations, slow or disrupt port activities, or affect foreign trade are beyond our control and could materially disrupt our ability to
participate in the export market for coal sales, which could adversely affect our sales and our results of operations.
We may not be able to successfully grow through future acquisitions.
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
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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
companies for attractive opportunities 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 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.
The estimates of our coal reserves could prove inaccurate and could result in decreased profitability in our Coal Operations.
The estimates of our coal reserves could 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 could 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 in our Coal Operations.
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Mining in certain areas in which we operate is more difficult and involves more regulatory constraints than mining in other areas of
the U.S., which could affect the mining operations and cost structures of these areas.
The geological characteristics of some of our coal reserves, such as depth of overburden and coal seam thickness, make them difficult
and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be
mineable at costs comparable to those characteristics of the depleting mines. In addition, permitting, licensing and other environmental
and regulatory requirements associated with certain of our mining operations are more costly and time-consuming to satisfy. These
factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced
by, our mines.
Unexpected increases in raw material costs could significantly impair our operating profitability.
Our operations are affected by commodity prices. In our Coal Operations, 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 could change unexpectedly. Our Electric Operations are also affected by many of these same
commodity prices, including chemicals and catalysts necessary to operate the plant in accordance with environmental and other
regulations, fuel oil, limestone, and raw materials used in the manufacture and maintenance of equipment throughout the plant.
Inflationary pressures have and could continue to lead to price increases affecting many of the components of our operating expenses
such as fuel, steel, other materials and maintenance expense.
There could be acts of nature or terrorist attacks or threats that could also impact the future costs of raw materials. Future volatility in
the price of steel, petroleum products or other raw materials will impact our operational expenses and could result in significant
fluctuations in our profitability.
Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation and coal lease obligations
and, therefore, our ability to mine or lease coal.
Federal and state laws require us to obtain surety bonds to secure performance or payment of certain long-term obligations, such as
mine closure or reclamation costs. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand
higher fees, additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are
required by state and federal law to have these bonds in place before mining can commence or continue, failure to maintain surety
bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine or lease
coal. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the
exercise by third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for
current and future third-party surety bond issuers under the terms of our financing arrangements.
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. Elimination of those
provisions would negatively impact our financial statements and results of operations.
Disruptions in supply chains could significantly impair our operating profitability.
We are dependent upon vendors to supply equipment within our power plant, mining equipment, safety equipment, supplies, and
materials. If a vendor fails to deliver on its commitments, or if common carriers have difficulty providing capacity to meet demands for
their services, we could experience reductions in our production or increased production costs, which could lead to reduced profitability
and adversely affect our results of operations.
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Inflationary pressures could significantly impair our operating profitability.
Any future inflationary or deflationary pressures could adversely affect the results of our operations. For example, at times our results
have been significantly impacted by price increases affecting many of the components of our operating expenses such as fuel, steel,
maintenance expense, healthcare and labor. In addition to potential cost increases, inflation could cause a decline in global or regional
economic conditions that reduce demand for our electric power, capacity or coal and could adversely affect our results of operations.
The Russian-Ukrainian conflict, and sanctions brought against Russia, as well as other disruptions throughout Europe and the
Middle East have caused significant market disruptions that may lead to increased volatility in the price of commodities.
The extent and duration of the military conflict involving Russia and Ukraine, resulting sanctions and future market or supply
disruptions in the region are impossible to predict, but could be significant and may have a severe adverse effect on the region.
Globally, various governments have banned imports from Russia including commodities such as coal. Additionally, the ongoing conflict
between Israel and Hamas, as well as the increasing instability throughout the Middle East, could result in additional disruptions in the
commodities markets, supply chain and the global economy. These events have caused volatility in the aforementioned commodity
markets. Although we have not experienced any material adverse effect on our results of operations, financial condition or cash flows as
a result of the war or conflict or the resulting volatility from such events, such volatility, may significantly affect prices for our coal or
the cost of supplies and equipment, as well as the prices of competing sources of energy for our electric power plant customers.
These events, along with trade and monetary sanctions, as well as any escalation of the conflicts and future developments, could
significantly affect worldwide market prices and demand for our coal and cause turmoil in the capital markets and generally in the
global financial system. Additionally, the geopolitical and macroeconomic consequences of these events and associated sanctions
cannot be predicted, but could severely impact the world economy. If any of these events occur, the resulting political instability and
societal disruption could reduce overall demand for products, causing a reduction in our revenues or an increase in our costs and
thereby materially and adversely affecting our results of operations.
The integration of any expansions or acquisitions that we complete will be subject to substantial risks.
Even if we make expansions or acquisitions that we believe will increase our revenue, any expansion acquisition involves potential
risks, including, among other things:
●
the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, and
operating expenses;
●
a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to
finance acquisitions;
●
a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
●
the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity we receive
is inadequate;
●
mistaken assumptions about the overall cost of equity or debt;
●
our ability to obtain satisfactory title to the assets we acquire;
●
an inability to hire, train or retain qualified personnel to manage and operate the acquired assets; and
●
the occurrence of other significant changes, such as impairment of properties, goodwill or other intangible assets, asset
devaluation, or restructuring charges.
Natural disasters and other events beyond our control could materially adversely affect us.
Natural disasters or other events outside of our control may cause damage or disruption to our operations, and thus could have a
negative effect on us. Our business operations are subject to interruption by natural disasters, fire, power shortages, pandemics and
other events beyond our control. This may result in delivery delays, malfunctioning of
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facilities or shutdown of logistic points. Such events could make it difficult or impossible for us to deliver our products and services to
our customers and could decrease demand for our services. We could not assure you that the production facilities and logistic points will
always operate normally in the future.
ITEM 1B. UNRESOLVED STAFF COMMENTS. None.
ITEM 1C. CYBERSECURITY.
Risk Management and Strategy
We rely on information technology to operate our business. We have endpoint and other protection systems, and incident response
processes, both internally and through third-party consultants, designed to protect our information technology systems. These
established processes assist us to continuously assess and identify threats to our systems and minimize impact to our business in the
event of a breach or other security incident. With our third-party consultants, the processes protect our information systems and allow us
to resolve issues timely.
As new threats to security may be identified, our personnel are notified, with instruction to increase awareness of the threat and how to
react if such a threat or actual breach appears to be encountered. Periodic educational notices are also disseminated to all personnel.
Additionally, as our systems are modified and upgraded, all personnel are notified, with instruction as appropriate. Responsibility for
the identification and assessment of risks and the recommendation of upgrades to our systems resides with our expert consultants who
report to our IT Director.
Governance
Our Board oversees the risks involved in our operations as part of its general oversight function, integrating risk management into the
Company’s compliance policies and procedures. With respect to cybersecurity, the Board has the ultimate oversight responsibility, with
the Audit Committee and IT Steering Committee each having certain responsibilities relating to risk management of cybersecurity.
Among other things, the Audit Committee discusses with management the Company’s major policies with respect to risk assessment
and risk management, including cyber-security, as they relate to the integrity of the Company’s accounting and financial reporting
processes and the Company’s compliance with legal and regulatory requirement.
In addition to its other responsibilities, the IT Steering Committee oversees operational information technology risks, including
cybersecurity, as they relate to the technical aspects of the Company’s operations.
The IT Steering Committee and/or the full Executive Team receive at least quarterly reports from management on information
technology matters, including cybersecurity. The reports address upgrades to hardware, software, and IT systems throughout the
Company, and include the identification of IT and cybersecurity risks. Security scores, risk management, and mitigation measures are
routinely presented. As discussed above, we maintain endpoint and other protection systems, and incident response processes, both
internally and through third-party experts. As these systems, processes, training, and upgrades are implemented, updates are provided to
the Executive Team.
We have not identified an indication of a substantive cyber security incident that would have a material impact on our business, results
of operations or financial statements. For additional information regarding risks from cybersecurity threats, please refer to Item 1A,
“Risk Factors” above.
ITEM 2. PROPERTIES.
See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a discussion of the Merom
Power Plant and our mines.
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ITEM 3. LEGAL PROCEEDINGS.
The Company is subject to various legal proceedings and claims that arise in the ordinary course of business, including, but not limited
to, environmental matters, contractual disputes, regulatory issues, personal injury, and employment claims. As of the filing date of this
report, the Company does not have any active lawsuits or claims which are deemed material, but should facts or circumstances change,
some or all of these alleged claims could have a material impact on the Company’s financial results, results of operations and/or cash
flows.
The Company accrues liabilities for legal matters when it is probable that a liability has been incurred and the amount can be reasonably
estimated. While the Company believes that it has made appropriate provisions for all known legal matters, the outcome of legal
proceedings is inherently uncertain, and there can be no assurance that the resolution of such matters will not have a material adverse
effect on the Company's financial position, results of operations, or cash flows.
Subsequent to the end of the fourth quarter, the Company reached an agreement in principle to resolve a putative class action related to
certain of its employment practices for an amount not material to its financial results. The liability related to this settlement was
accrued during the fourth quarter, when settlement negotiations began. The resolution has not yet been finalized, but the Company
expects the matter to be closed during the first half of 2025. See “Note 22 – Contingencies” to our Consolidated Financial Statements.
The Company will continue to monitor all proceedings and will update shareholders as necessary, in accordance with applicable legal
and regulatory requirements.
ITEM 4. MINE SAFETY DISCLOSURES.
Safety is a core value for us and our subsidiaries. As such, we have dedicated a great deal of time, energy, and resources to creating a
culture of safety.
See Exhibit 95 to this Form 10-K for a listing of our mine safety violations.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES.
Stock Price Information
Our common stock trades on the NASDAQ Capital Market under the symbol HNRG, and 40.9% is held by our officers, directors, and
their affiliates.
On March 10, 2025, we had 193 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 8 – Stock Compensation Plans” to our consolidated financial statements.
ITEM 6. [RESERVED]
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41
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. The following analysis includes a discussion
of metrics on a per mega-watt hour (MWh) and per ton and basis as derived from the consolidated financial statements, which are
considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.
OVERVIEW
Hallador Energy Company (the “Company” or “Hallador”) is an energy company operating in the state of Indiana. Our wholly owned
subsidiary Hallador Power, operates our Merom Power Plant ("Merom"), a one gigawatt (“GW”) power plant located in Sullivan
County, Indiana. Merom is located in the Midcontinent Independent System Operator’s ("MISO") footprint.
We also mine coal in the State of Indiana through our wholly-owned subsidiary Sunrise Coal, LLC (“Sunrise”), serving the electric
power generation industry. During the fourth quarter of 2024, we completed our review of the coal mining facilities and future mining
plans. The impairment analysis was based upon our finalized coal mining operating plans, market driven pricing and cost trends. As
part of that analysis, we determined the carrying amount of our coal mining long-lived asset group was not recoverable and recorded a
non-cash, long-lived asset impairment charge of $215.1 million in the fourth quarter of 2024. See “Note 19 – Impairment of Coal
Properties” to the Consolidated Financial Statements in this Form 10-K for further information on the impairment analysis.
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal
Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses
operating performance measures related to our Electric Operations and our Coal Operations segments. In addition to these reportable
segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant enough, on a stand-alone basis,
to be considered an operating segment. Corporate and Other and Eliminations primarily consist of unallocated corporate costs and
activities, including a 50% interest in Sunrise Energy LLC and Oaktown Gas, LLC, which are accounted for using the equity method.
Throughout 2024, we made progress on transitioning Hallador Energy from a bituminous coal producer to an integrated independent
power producer (“IPP”). This strategic transition has been a deliberate response to market signals and what we believe to be the
superior economics of the IPP business model. As such, our focus remains on maximizing the value of Merom while actively seeking
opportunities to acquire additional dispatchable generators. We have also prioritized building strong relationships with counterparties to
secure favorable terms for collateral, enabling us to effectively leverage forward power sales in 2025 to offset pricing volatility in the
spot market. This approach enhances our financial flexibility and strengthens our position in the evolving energy market.
In the fall of 2024, we reached a key milestone in our IPP transformation by signing a non-binding term sheet with a leading global data
center developer for the supply of a significant portion of Merom's output of capacity and energy for well over a decade. As evidenced
by our announcement of an exclusivity agreement with this development partner in January 2025, we are continuing to make progress
as we seek to finalize a definitive agreement. As we have previously disclosed, the exclusivity period runs through the beginning of
June 2025, in exchange for payments from the developer to Hallador Power of up to $5.0 million, depending on if and when a definitive
agreement is finalized. This type of deal is complex and involves multiple parties, which adds time and challenges to negotiations.
Despite these challenges, we remain encouraged by our partners and the steady progress that we continue to make. Our pursuit of this
agreement further demonstrates our commitment towards forging a strategic partnership that we believe will create significant value for
our shareholders for years to come. The completion of this proposed transaction is subject to, among other matters, the negotiation and
execution of definitive agreements and there can be no assurance that definitive agreements will be entered into or that the proposed
transaction will be consummated on the terms or timeframe currently contemplated, or at all.
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We continue to witness the prevalent industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable
resources such as wind and solar. We believe this transition from dispatchable to non-dispatchable generation made the attributes of our
subsidiary, Hallador Power, much more valuable due to the enhanced reliability that we provide versus non-dispatchable generators.
However, we believe the retirement of coal-based generation and lower natural gas prices could reduce the demand for coal supply,
potentially lowering the value of Sunrise. During 2024, in response to declining coal demand, we reduced our coal production volume
by approximately 40% and idled the higher cost surface mines. This optimization of coal production reduced our operational cash cost
structure and better aligned our coal strategy to primarily support our internal electric generation.
Merom can produce up to 6.0 million Mega-Watthours (“MWh”) annually. The forward power price curves indicate that the margins
earned on energy produced at Merom and the value of the accredited capacity sales assigned to the plant continues to increase. We are
seeing strong indications for both energy and capacity sales in 2025 and beyond, especially considering our negotiations related to
supporting data center development within the State of Indiana. In addition, while we largely held to our traditional approach of selling
energy through bespoke bi-lateral agreements on a unit or plant contingent basis, during 2024 we sold a limited amount of power on a
firm basis. While we continue to limit these types of firm sales to mitigate risk and wait for higher priced contracts to take effect, we
will strategically utilize them to smooth our exposure to the spot market. This approach enables us to capture some of the episodic cash
generation driven by demand from extreme weather and various other conditions stressing the power grid while limiting our exposure
to periods of mild weather and lower demand.
In 2024, the ongoing surplus of natural gas in the market and mild weather patterns continued to moderate energy prices throughout the
year and kept spot energy prices weak. We began to see favorable pricing signals at the end of the fourth quarter of 2024 and
subsequent to year-end.
The ability to store a commodity is inherently tied to the volatility of that commodity. Coal can be piled up for years, thus its volatility
is low. Oil and natural gas face transportation and storage challenges which increase price volatility. The limitations of storing viable
energy, coupled with non-dispatchable generation gaining market share in an environment where there is unpredictability in the
weather, indicates to us that energy's price volatility is likely to increase over the next decade. This volatility will keep the forward
power price premium intact.
We are excited by the opportunity for Hallador Power to capture higher prices and energy volumes in 2025 and beyond compared to
what we have historically achieved in our relatively short ownership tenure of Merom. In 2024, we sold 4.2 million MWh at an average
sales price of approximately $48.62 per MWh. At the start of the year, we had 1.9 million MWh contracted, leaving us with significant
exposure to the spot electricity market. Heading into 2025, we have contracted approximately 4.3 million MWh at an average price of
$37.24 per MWh, which should help to smooth our exposure to the spot market. For 2026, we have already contracted 3.4 million
MWh at $44.43 per MWh. Following 2026, we are optimistic that we can sell energy at higher prices in support of data center
development and/or to traditional wholesale customers in line with the indicators of a higher forward curve. The tables included below
highlight some of the revenue and margin improvements we have seen in our forward contracted power sales for 2025 and thereafter.
These tables do not include the significantly higher prices that we are expecting if we are able to finalize our agreements in support of
data center development.
In addition to the transaction we are negotiating with Merom, we continue to evaluate other strategic transactions that could add
durability, scale, and geographic expansion opportunities to our electric operations. While these types of deals are limited and complex,
we believe that Hallador is uniquely positioned to transform retiring and/or underperforming assets into future opportunities. This will
enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail
consumers, unlike a traditional utility siphoning off consumer power to serve these types of large load end-users. By continuing the
operations of the dispatchable plants to support large load industrial users as the utilities transition to non-dispatchable generation, the
new generation becomes additive to the already struggling grid rather than cannibalizing the overall reliability of what exists today. We
are optimistic about the potential to add to our strategic portfolio and the long-term benefits that such a transaction could produce for
the Company, its shareholders and its customers. This model for growth enables us to shift from transactional pricing related to plant
acquisition, to traditional wholesale market pricing, and ultimately to the enhanced pricing associated with supporting data centers and
other large load end users.
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In the first quarter of 2024, we announced a restructuring of our Coal Operations to address the increase in costs we experienced at our
mines. See “Note 17 – Organizational Restructuring” to the Consolidated Financial Statements in this Form 10-K for further
information. We spent much of the year adjusting to this restructuring to optimize production, headcount, and strategy to best support
our Electric Operations and our existing third-party coal contracts. By reducing headcount, focusing production on our most profitable
mines and units within those mines, and improving our infrastructure and processes within those favored units, we were able to both
slow the impact of rapidly increasing costs and reduce costs to better support the continued operations of our mines.
Historically, Sunrise has produced between four and six million tons annually. As we continue to optimize the mines in support of the
plant, we expect to produce approximately 3.6 million tons of coal in 2025, with approximately 2.3 million tons produced directed to
support our Electric Operations. We have also secured supplemental coal from third party suppliers at favorable prices to diversify self-
production supply risk and to provide us additional flexibility in our sales portfolio and to fulfill future sales obligations to third-parties
and Merom as shown in the table below. The optionality to obtain low-cost tons either internally or from third parties while capturing
upward swings in the commodity markets for coal should further maximize margins while optimizing fuels costs at Merom.
We remain excited about the continued and deliberate transformation of Hallador from a commodity focused producer of coal to an IPP.
We believe this transition provides significant opportunity to capture the expanding margins of the energy markets and capitalize on the
soaring demand for electricity. We are pleased by the strong interest we continue to see from potential counterparties in our energy and
capacity offerings, bolstered by Indiana’s efforts to attract data centers and other high-density power users through its business-friendly
climate and favorable tax policies. With the continued growth of our sales book, coupled with our ongoing focus to transition our
operations to primarily electricity generation, we believe we are well positioned to materially strengthen our opportunities for growth
and cash flow generation.
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Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations
2025
2026
2027
2028
2029
Total
Power
Energy
Contracted MWh (in millions)
4.25
3.36
1.78
1.09
0.27
10.75
Average contracted price per MWh
$
37.24
$
44.43
$
54.66
$
52.94
$ 51.33
Contracted revenue (in millions)
$ 158.27
$ 149.28
$
97.29
$
57.70
$ 13.86
$
476.40
Capacity
Average daily contracted capacity MWh
773
727
623
454
100
Average contracted capacity price per MWd
$
201
$
230
$
226
$
225
$
230
Contracted capacity revenue (in millions)
$
55.95
$
61.12
$
51.40
$
37.33
$
3.47
$
209.27
Total Energy & Capacity Revenue
Contracted Power revenue (in millions)
$ 214.22
$ 210.40
$ 148.69
$
95.03
$ 17.33
$
685.67
Coal
Priced tons - 3rd party (in millions)
2.95
2.50
2.50
0.50
—
8.45
Avg price per ton - 3rd party
$
51.04
$
55.49
$
56.74
$
59.00
$
—
Contracted coal revenue - 3rd party (in millions)
$ 150.57
$ 138.73
$ 141.85
$
29.50
$
—
$
460.65
TOTAL CONTRACTED REVENUE (IN
MILLIONS) - CONSOLIDATED
$ 364.79
$ 349.13
$ 290.54
$ 124.53
$ 17.33
$ 1,146.32
Priced tons - Intercompany (in millions)
2.30
2.30
2.30
2.30
—
9.20
Avg price per ton - Intercompany
$
51.00
$
51.00
$
51.00
$
51.00
$
—
Contracted coal revenue - Intercompany (in millions)
$ 117.30
$ 117.30
$ 117.30
$ 117.30
$
—
$
469.20
TOTAL CONTRACTED REVENUE (IN
MILLIONS) - SEGMENT
$ 482.09
$ 466.43
$ 407.84
$ 241.83
$ 17.33
$ 1,615.52
*
Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment
features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.
Electric Operations
Internal Controls Disclosure
Our electric operations employ third party service providers for the day-to-day operations and maintenance of Merom as well as
managing market transactions and optimizing plant dispatch. We contract with Consolidated Asset Management Services (“CAMS”) to
manage ongoing operations, maintenance and asset management functions at Merom. CAMS provides an operations and maintenance
program which includes daily management of plant performance, safety protocols and workforce management. CAMS develops and
implements predictive and preventative maintenance schedules designed to maximize plant availability and maintain compliance with
environmental and regulatory standards. In coordination with our engineering teams, CAMS identifies and manages capital projects
that aim to improve operational efficiency and reduce long-term costs. CAMS also provides performance monitoring and reporting.
CAMS provides regular reports on key performance indicators (“KPIs”) such as heat rates and forced outage rates to help us assess
plant efficiency. CAMS assists in ensuring adherence to local, state and federal regulations including
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environmental rules and safety mandates. We maintain oversight of CAMS through regular audits and performance reviews,
confirming all procedures align with our company policies and best practices.
We engage with Alliance for Cooperative Energy Services Power Marketing, LLC (“ACES”), as our agent to manage our wholesale
power market activities and risk management strategies related to electric operations. Through this relationship, ACES manages the
dispatch and scheduling on the real-time and day-ahead markets. ACES manages bidding strategies, scheduling our generation in the
relevant regional transmission organizations (“RTOs”) or independent system operators (“ISOs”). To optimize our sales portfolio,
ACES analyzes energy market dynamics, identifies opportunities to optimize plant dispatch, and recommends operational adjustments
to capture favorable margins. ACES assists in risk management by executing short-term trades on our behalf to mitigate price volatility
and lock in predictable revenues as well as ensures that our participation in the energy markets adheres to relevant market rules and
regulations. We receive regular risk reports and settlement statements, which our internal teams review to confirm accuracy and
compliance with our company policies.
We regularly review the performance and controls of CAMS and ACES. Our formal review processes include monthly performance
reviews through joint meetings with CAMS and ACES to evaluate KPI trends, discuss operational challenges, and plan market
strategies. Periodic internal and external audits examine environmental, safety, and financial compliance, ensuring third-party activities
align with regulatory standards and Company objectives. We also have a risk committee that evaluates all marketing activities and
exposures.
Merom operates under permits issued by various agencies. CAMS provides support and expertise to ensure compliance with emissions
requirements, water use regulations, and waste disposal guidelines. The power markets we operate in periodically update their rules and
tariffs, which may affect how we dispatch our plants or manage financial positions. ACES continuously monitors changes,
recommending updates to our strategies as needed.
Volatility in wholesale power prices can impact revenue. ACES provides strategies to mitigate price risk.
Equipment failures or unexpected downtime at coal plants can lead to missed market opportunities or contractual liabilities. Our
relationship with CAMS is designed to minimize these risks through comprehensive operations and maintenance practices. Future
environmental or market regulations may require capital investments or shift market behavior. Our teams, in conjunction with CAMS
and ACES, monitor emerging policies to proactively plan operational or strategic adjustments.
Property
Through Hallador Power, the Company owns and operates Merom, a 1,080 MW net coal fired power generating station, consisting of
two 590 MW sub-critical water tube drum type steam turbine generators. Unit 1 entered commercial operations in 1982 and Unit 2 in
1983. The units are dispatched to the MISO interconnection. Hallador Power sells wholesale energy and accredited capacity to utilities
within the MISO system through PPA’s and other bilateral transactions. Merom is located in Sullivan County, Indiana, on approximately
691 acres, which also holds a 112-acre landfill. Hallador Power has two tracts under option for approximately 72 acres for expansion
and future development at Merom. Merom is about twenty miles from Sunrise’s Oaktown Mining Complex and has rail and truck
access. The Company acquired Merom from Hoosier Energy Rural Electric Cooperative, Inc. in 2022.
Year Ended December 31,
2024
2023
Power Capacity and Utilization
Nameplate capacity (MW)(i)
1,080
1,080
Accredited capacity for the period (MW)(ii)
823
860
Accredited capacity utilization(iii)
49 %
45 %
i.
Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period
presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational
conditions, and other factors.
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46
ii.
Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 808
MW and 838 MW per day for 2024 and 2023, respectively. Accreditations are weighted and adjusted annually based on 3-year
rolling performance metrics.
iii.
Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW)
multiplied by 24 times the number of days for the period.
Permits are required by federal and state law for Merom’s facilities and landfill. Merom holds several construction and environmental
permits for air, wastewater and solids waste disposal. All necessary permits to support current operations are in place. New permits or
permit revisions may be necessary from time to time to facilitate future operations or to keep pace with the changing regulatory
landscape. Given sufficient time and planning, we should be able to secure new permits, as required, to maintain our planned operations
within the context of the current regulations. Merom continually excels in environmental excellence and compliance.
Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide
assurance that any disturbance or liability created is properly mitigated, and (2) assure that all regulation requirements of the permit are
fully satisfied. We hold surety bonds of $9.7 million to cover obligations relating to reclamation at Merom.
Coal Operations
Internal Controls Disclosure
The preparation of coal reserve and resource estimates is conducted by independent individuals who are by virtue of their education,
experience and professional association considered qualified persons (as defined in SEC rules). Company personnel meet on an annual
basis with the independent qualified person to provide updates to the reserve and resource estimates. Company personnel review the
work of the qualified person to ensure such work is prepared in accordance with applicable rules and regulations and that the data and
assumptions provided were properly applied to the final reserve and resource model. The Company’s engineering personnel ensure
estimates are based on current mine plans, incorporate the most recent drilling and lab data, properly reflect changes in permitting
status, consider known encumbrances, and are consistent with operating knowledge and expectations in terms of mining methods,
recovery rates, minimum seam heights or maximum strip ratios, and saleable qualities.
An American National Standards Institute-certified third-party laboratory is utilized to support reserve and resource estimates. The
laboratory follows standard sample preparation, security, and environmental procedures. In addition, the Company’s qualified person
performs independent data verification procedures to ensure data is of sufficient quantity and reliability to reasonably support the coal
reserve and resource estimates.
Estimates of any mineral reserve and resources are always subject to a degree of uncertainty. The level of confidence that can be applied
to a particular estimate is a function of, among other things, the amount, quality, and completeness of exploration data; geological
complexity of the deposit; and economic, legal, social, and environmental factors associated with mining the reserve/resource. The
Company’s current coal reserves and resource estimates are based on the best information available and are subject to updates as
conditions change. Also refer to "Item 1A. Risk Factors" for discussion of risks associated with the estimates of the Company’s reserves
and resources.
Summary of All Mining Properties
The Company has seven total mining properties. These properties are the Oaktown Mining Complex (“Oaktown”), which is comprised
of Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine, the Ace in the Hole Mine, the Ace in the Hole Mine #2 Reserves,
Prosperity, Freelandville and Carlisle. Oaktown Fuels No. 2, Prosperity and Freelandville were temporarily idled in February of 2024 as
part of the Organizational Restructuring in “Note 17 – Organizational Restructuring” to the Consolidated Financial Statements below.
Ace in the Hole Mine and Carlisle are fully depleted.
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47
The Oaktown Fuels No. 1 Mine is an underground mine in the Illinois Basin located near Oaktown in Knox County, Indiana. Oaktown
Fuels No. 1 Mine utilizes continuous mining units operating in room and pillar mining techniques to produce high-sulfur coal. The
Oaktown Fuels No. 2 Mine is an underground mine in the Illinois Basin (“ILB”) located near Oaktown in Knox County, Indiana. The
Oaktown Fuels No. 2 Mine utilizes continuous mining units operating in room and pillar mining techniques to produce high-sulfur coal.
The preparation plant at Oaktown has a throughput capacity of 1,600 tons of raw coal per hour. Freelandville is a surface mine in the
Illinois Basin located near Freelandville in Knox County, Indiana. Freelandville utilizes surface mining techniques to produce high-
sulfur coal from as many as three seams. Prosperity is a surface mine in the Illinois Basin located near Petersburg in Pike County,
Indiana. Prosperity utilizes surface mining techniques to produce low-sulfur coal. The low-sulfur coal is trucked to the Oaktown and
other Sunrise Coal logistic facilities where it is blended with coal from the Oaktown Mines.
These properties and further summaries concerning property description, purpose, property overview, geology, background, processing
operations, mine infrastructure, and market analysis can be found and are hereby incorporated by reference from Sections 1.1, 1.2, 1.3,
1.6, 2.1, 3, 4, 5, 6, 7.1, 7.3, 7.4, 8, 9, and 10 from the March 2025 Technical Report Summary prepared by the John T. Boyd Company,
attached as Exhibit 99.1 to this Form 10-K.
The following figure shows the general location of Merom and our mining properties discussed above:
Individual Mining Properties
The following information concerning our mining properties has been prepared in accordance with the requirements of subpart 1300 of
Regulation S-K. Subpart 1300 of Regulation S-K requires us to disclose our mineral (coal) resources, which we have none, in addition
to our mineral (coal) reserves, as of the end of our most recently completed fiscal year both in the aggregate and for each of our
individually material mining properties.
As used in this Annual Report on Form 10-K, the terms “mineral resources,” “mineral reserve,” “proven mineral reserve” and “probable
mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K,
mineral resources may not be classified as “mineral reserves” unless the determination
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48
has been made by a qualified person (“QP”) that the mineral resources can be the basis of an economically viable project. You are
specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories
will ever be converted into mineral reserves, as defined by the SEC.
Internal qualified person(s) have estimated the Company’s mineral reserves and mineral resources based on geologic data, coal
ownership (control) information, and current and/or proposed operating plans. Periodic updates occur to mineral reserve and mineral
resource estimates attributable to revised mine plans, new exploration data, depletion from coal production, property acquisitions or
dispositions, and/or other geologic or mining data. Sunrise’s estimates of mineral reserves are proven and probable reserves that could
be extracted or produced at the time of the reserve determination, economically, legally, and after considering all material modifying
factors. Modifications or updates of the estimates of the Company’s mineral reserves is limited to qualified geologists and mining
engineers. All modifications or updates of the estimates of recoverable coal reserves are documented. The John T. Boyd Company, a
qualified person firm, has assessed the Company’s estimates of mineral reserves and mineral resources and supporting information.
Based upon the review, John T. Boyd Company provided modification to the Company’s estimates of mineral reserves where
warranted.
The information that follows is derived, for the most part, from, and in some instances is extracted from, the Oaktown Mining Complex
technical report summary (“TRS”) from John T. Boyd Company dated March 2025 in accordance with Subpart 1300 of Regulation S-K
(Coal Resources and Coal Reserves, Oaktown Mining Complex) attached hereto as Exhibit 99.1 to this Form 10-K; and a letter, dated
March 7, 2025, from John T. Boyd Company providing an update of estimated coal reserves at the Oaktown Mining Complex as of
December 31, 2024, attached as Exhibit 99.2 to this Form 10-K. The Oaktown Mining Complex is the Company’s individually material
property. Sections of the following information provided herein do not fully describe assumptions, qualifications, and procedures.
Reference should be made to the full text of the TRS which is made a part of this Annual report on Form 10-K and incorporated hereby
by reference. The Oaktown Mining Complex TRS was prepared by the John T. Boyd Company in compliance with the Item 60(b)(96)
and subpart 1300 of Regulation S-K.
The Company hereby incorporates by reference Section 6.3 "Coal Reserves" from the TRS, attached as Exhibit 99.1 to this Form 10-K,
as to the mineral price, cut-off grade, and metallurgical recovery factors utilized in John T. Boyd Company’s preparation of the mineral
reserve estimates. The Company hereby incorporates the letter, dated March 7, 2025, from John T. Boyd Company, attached as
Exhibit 99.2 to this Form 10-K, providing an update of the Company’s mineral reserves at the Oaktown Mining Complex as of
December 31, 2024 and including a comparison of the Company’s mineral reserves at the Oaktown Mining Complex as of
December 31, 2024 and as of December 31, 2023. The following table provides a summary of all of the Company’s mineral reserves
determined by the John T. Boyd Company as of the end of the fiscal year ended December 31, 2024:
SUMMARY MINERAL RESERVES AT END OF THE
FISCAL YEAR ENDED DECEMBER 31, 2024
Mineral Reserves (tons in millions)
Proven
Probable
Total
Oaktown
Oaktown Fuels No. 1 Mine
25.7
2.7
28.4
Oaktown Fuels No. 2 Mine
5.9
0.2
6.1
Total
31.6
2.9
34.5
Oaktown Mining Complex
The Oaktown Mining Complex is a coal mining and processing operation located in Knox and Sullivan counties, Indiana, and Crawford
and Lawrence counties, Illinois.
Oaktown is an underground Room-and-Pillar (“R&P”) coal mining complex. It is comprised of 83 square miles within the ILB coal-
producing region of the mid-western U.S. Oaktown operations currently consists of one active underground mine - Oaktown Fuels
No. 1 Mine - and related infrastructure. Geographically, the Oaktown Complex Coal Preparation
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49
Plant is located at approximately 28°51’24.7” N latitude and 87°25’30.9” W longitude. Within the Oaktown area and its immediate
vicinity, our Company controls approximately 64,000 acres of mineral rights. We have a complex collection of leases that apply to more
than 1,000 tracts. Leased tracts range from less than an acre to several hundred acres in size. Ownership of the surface rights and the
mineral rights is often severed for the properties and the estates are often fractions, in which mineral rights are split between several
owners. The Company and its predecessors have acquired the necessary rights to support development and operations through purchase
or lease agreements with predominately private owners or entities. The Company controls surface rights through fee simple ownership
for over 1,700 permitted acres, holding mine accesses, processing, storing, shipping, and refuse disposal facilities (i.e., refuse
impoundment site and fine refuse injection sites). We acquired Oaktown Fuels No. 1 and No. 2 Mines from Vectren Fuels in 2014.
Oaktown utilizes R&P mining (employing Continuous Miners, or CM) for primary production. This mining method is highly
productive and commercially demonstrated; it has been one of the primary approaches to underground mining the Indiana V Seam for
decades. Oaktown has utilized this mining method since the inception of each operation. To date, Oaktown has produced a combined
75.0 million tons of clean coal. Oaktown is configured to operate up to 6 CM sections (currently operating 4 CM sections), with an
annual production target of approximately 3.6 million tons. The Oaktown Preparation Plant serves as the coal washing and shipment
facility for Oaktown’s two R&P mines. The plant was commissioned in 2009 to wash coal by the Oaktown Fuels No. 1 Mine. The
Oaktown Preparation Plant’s processing capacity was upgraded to 1,800 raw tons-per-hour (TPH) from its previous 1,600 raw TPH in
2023. Coal from Oaktown is transported to customers via rail and truck. The Oaktown Preparation Plant is served by both the CSX
Railroad and Indiana Railroad (INRD) via a rail spur and rail loop that connects the complex with the mainline rail just north of
Oaktown, Indiana.
Additionally, the Oaktown Preparation Plant can facilitate the loading of trucks for direct transport to select customers, or to our
transload facility in Princeton, Indiana serviced by the Norfolk Southern (NS) Railroad.
Sources of electrical power, water, supplies, and materials are readily available. Electrical power is provided to the mines and facilities
by regional utility companies. Water is supplied by public water services, surface impoundments, or water wells.
Multiple permits are required by federal and state law for underground mining, coal preparation and related facilities, and other
incidental activities. All necessary permits to support current operations are in place or pending approval. New permits or permit
revisions may be necessary from time to time to facilitate future operations. Given sufficient time and planning, we should be able to
secure new permits, as required, to maintain our planned operations within the context of the current regulations.
Permits generally require that the Company post a performance bond in an amount established by the regulator program to: (1) provide
assurance that any disturbance or liability created during mining operation is properly mitigated, and (2) assure that all regulation
requirements of the permit are fully satisfied. We hold surety bonds of $10.0 million to cover obligations relating to mining and
reclamation, road repair, etc. at the Oaktown Mining Complex.
Additional information is provided in the following table regarding Oaktown’s mineral reserves:
OAKTOWN
Recoverable Coal Reserves as of December 31, 2024 and 2023
As Received As Received
Heat
SO2
Value
Content
(Btu/lb)
(lbs/MMBtu)
Owned
Leased
Recoverable Coal Reserves (As-Received)
Mine/Reserve
Approximate Approximate
(%)
(%)
Proven Probable 12/31/2024 12/31/2023
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine
11,630
6.0
—
100.0
25.7
2.7
28.4
34.1
Oaktown Fuels No. 2 Mine
11,576
5.0
—
100.0
5.9
0.2
6.1
26.6
Total
31.6
2.9
34.5
60.7
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50
Oaktown Fuels No. 1 Mine
As of December 31, 2024, the assigned and accessible reserve base for the Oaktown Fuels No. 1 Mine contains 28.4 million tons of
recoverable Indiana V seam coal, of which 28.4 million tons are currently permitted. The reserve contains saleable tons which average
heating content of approximately 11,630 Btu per pound with approximately 6.0 pounds of sulfur dioxide per MMBtu on an as-received
basis. Access to the Oaktown Fuels No. 1 Mine is via a 90-foot-deep box cut and a 2,200-foot long slope, which facilitates the egress of
coals being mined in excess of 375 feet below the surface. Since beginning first commercial coal production in 2009, the mine
workings have substantially grown, and an additional mine access (elevator) was constructed for employee and supply ingress/egress
closer to the active production faces.
Oaktown Fuels No. 2 Mine
As of December 31, 2024, the assigned and accessible reserve base for the Oaktown Fuels No. 2 Mine contains 6.1 million tons of
recoverable Indiana V seam coal, of which 5.4 million tons are currently permitted. The reserve contains saleable tons which average
heating content of approximately 11,576 Btu per pound with approximately 5.0 pounds of sulfur dioxide per MMBtu on an as-received
basis. Access to the Oaktown Fuels No. 2 Mine is via an 80-foot-deep box cut and 2,600-foot long slope, which facilitates the egress of
coals being mined in excess of 400 feet below the surface. In 2021, an additional mine access (elevator) was constructed for employee
and supply ingress/egress closer to the active production faces. Oaktown Fuels No. 2 was temporarily idled in February of 2024.
Coal tons are reported on a clean recoverable basis with average long-term pricing based on available third-party forecasts and
historical pricing adjusted for quality at the end of 2024, with the coal sales price estimated over the life of the reserve averaging
approximately $49 (ranging from $47.25 to $51.47 per ton), which are the coal sales prices used by John T. Boyd Company to estimate
the amount of coal mineral reserves for the Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2 Mine as listed above. Coal sales
prices vary based on coal quality, access to transportation, and other factors at each location. All reserves are classified as underground
mineable in the production stage.
The Company hereby incorporates by reference (i) the TRS, attached as Exhibit 99.1 to this Form 10-K, including Section 6.3 thereof
titled "Coal Reserves", as to the recoverable coal reserves reported above for the Oaktown Fuels No. 1 Mine and Oaktown Fuels No. 2
Mine; and (ii) letter, dated March 7, 2025, from John T. Boyd Company, attached as Exhibit 99.2 to this Form 10-K, providing an
update of the Company’s mineral reserves at Oaktown as of December 31, 2024 and including a comparison of the Company’s mineral
reserves at Oaktown as of December 31, 2024 and as of December 31, 2023.
Historical production for Oaktown during the years ended December 31, 2024, 2023, and 2022 are provided in the following table:
Annual Saleable Production Tons
(Million Tons)
Mine/Reserve
2024
2023
2022
Oaktown Mining Complex
Oaktown Fuels No. 1 Mine
3.5
3.9
3.9
Oaktown Fuels No. 2 Mine
0.4
2.5
2.5
Total Oaktown Mining Complex Production
3.9
6.4
6.4
Other Properties
The Company holds other recoverable coal reserves in the ILB, which are not deemed individually material.
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51
Ace in the Hole Mine (Ace) (surface) – Assigned
Ace Mine is now depleted. Remaining inventory of coal and base was moved to our Oaktown wash plant in early 2023. Reclamation
resumed in the Spring of 2023. There are four phases of reclamation that extend through 2029, of which, Phase 1 and 2 were completed
as of December 31, 2024.
Prosperity (surface) – Assigned
The Prosperity mine contains approximately 0.2 million tons of low sulfur coal. The mine opened in the summer of 2022. The
mine produced coal and reclaimed the slurry pond and refuse pile left by the Prosperity underground mine. Additional reserves are in
the area that may extend the life of this mine. In February 2024, this mine was temporarily idled.
Freelandville (surface) – Assigned
Sunrise is a contract miner at the Freelandville East Mine Center Pit, Permit No. S 358. Sunrise had an option through May 31, 2023 to
assume the permit that contained approximately 1.7 million tons of salable coal with an additional 0.6 million available. That option
was extended from May 2023 until May 2026. Mining started in the fall of 2022 and continued through April 2023 with limited
production in 2024. Remaining reserves under the permit are 0.4 million tons. There are additional reserves of 1.2 million tons
available with the completion and approval of an Army Corps of Engineers permit. In February 2024, this mine was idled.
Carlisle
The Carlisle mine is located near the town of Carlisle, Indiana in Sullivan County. It became operational in January 2007 for both
surface and underground mining. The mine was permanently closed for mining operations in 2020. A wash plant was relocated to the
Carlisle mine in 2022 and was sold in 2024.
Our Coal Contracts
In 2024, on a segment basis Sunrise sold 3.9 million tons of coal to 6 power plants in four different states across five different
customers.
During 2024, on a segment basis we derived 96% of our revenue from four customers (5 power plants), with each of the four customers
representing at least 10% of our coal sales. During 2023, on a segment basis we derived 94% of our revenue from five customers
(11 power plants), with each of the five customers representing at least 10% of our coal sales.
Significant third-party customers in 2024 include Vectren Corporation, a wholly-owned subsidiary of CenterPoint Energy (NYSE:
CNP), Orlando Utility Commission (OUC), and Duke Energy Corporation (NYSE: DUK).
Of our 2024 sales, on a segment basis 43%, excluding Merom, were derived to locations in the State of Indiana.
Our future coal commitments are as follows:
3rd Party
Merom Power Plant
Contracted
Contracted
Estimated
tons
tons
Priced
Year
(millions)*
(millions)*
Total
per ton
2025
3.0
2.3
5.3
$
51.03
2026 - 2028 (total)
5.5
6.9
12.4
53.38
Total
8.5
9.2
17.7
*
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.
**
Unpriced or partially priced committed tons
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52
As of December 31, 2024, we are committed to supplying third-party customers a base amount of 8.5 million tons of coal through
2028 of which 8.5 million tons are priced. We are committed to supplying coal to Merom a base amount of 9.2 million tons of coal
through 2028. All committed tons to Merom are priced.
Based on the contracted tons described above, we anticipate our mines will need to produce at a 3.6 million ton annualized pace for the
foreseeable future to meet Merom and third-party market demand. We also have contracts in place to purchase coal through March of
2026, and anticipate similar contracts in the future.
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.
Some utility customers have proposed shuttering certain plant units or entire plants in the coming years. It remains to be seen whether
these plans will be implemented.
Liquidity and Capital Resources
As set forth in our Consolidated Statements of Cash Flows, cash provided by operations was $65.9 million and $59.4 million for
the years ended December 31, 2024 and 2023 respectively. Operating cash flow increased mainly due to prepaid physically delivered
power contracts entered into during 2024.
Our capital expenditure budget for 2025 is $66.0 million. Of the $66.0 million, the electric operations budget is $31.0 million for
maintenance capex and $14.0 million for ELG. The coal operations budget is $14.8 million plus an additional $5.8 million for
discretionary items.
As of December 31, 2024, our bank debt was $44.0 million. On March 13, 2023, we executed an amendment to our credit agreement
with PNC Bank, National Association (in its capacity as administrative agent, “PNC”), administrative agent for our lenders under our
credit agreement. The primary purpose of the amendment was to convert $35 million of the revolver into a new term loan with a
maturity of March 31, 2024, and extend the maturity date of the revolver to May 31, 2024. On August 2, 2023, we executed an
additional amendment with PNC. The primary purpose of the amendment was to convert $65 million of the existing outstanding debt
into a new term loan with a maturity of March 31, 2026, and enter into a revolver of $75 Million with a maturity date of July 31, 2026.
Principal payments for the term loan were $3.3 million per quarter for September 30, 2023, and December 31, 2023, and $6.5 million
per quarter starting March 31, 2024, through maturity. The effect of the amendment on our future cash flow is to extend the maturity
date of $65.0 million of our outstanding term debt to March 31, 2026, and our revolver to July 31, 2026.
On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit
Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC. The primary purpose of the First Amendment
was to provide the Company with short-term covenant relief to pursue additional liquidity. The First Amendment provides for additional
flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repays outstanding term
loans under the Credit Agreement (“Term Loan”) with proceeds received from certain eligible power purchase agreements, up to a
maximum of $20.0 million. These required prepaid forward power sale Term Loan repayments, if any, will take the place of the
$6.5 million quarterly Term Loan payments.
We expect cash from operations generated primarily by our expected higher Electric Operation margins in 2025 to fund our capital
expenditures and our debt service.
See “Note 4” to our Consolidated Financial Statements for additional discussion about our bank debt and related liquidity.
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53
Off-Balance Sheet Arrangements
Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value
of reclamation obligations of $16.9 million, including $5.7 million at Merom, presented as asset retirement obligations (ARO) in our
accompanying consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling
$30.8 million to cover ARO.
Capital Expenditures (“Capex”)
For the year ended December 31, 2024, our Capex was $53.4 million allocated as follows (in millions):
Oaktown – maintenance capex
$
22.5
Oaktown – investment
11.3
Merom Plant
18.7
Other
0.9
Capex per the Condensed Consolidated Statements of Cash Flows
$
53.4
Results of Operations
Presentation of Segment Information
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal
Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses
operating performance measures related to our Electric Operations and our Coal Operations segments.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant
enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of
unallocated corporate costs and activities, including a 50.0% interest in Sunrise Energy, which is accounted for using the equity method.
Electric Operations
Year Ended December 31,
2024
2023
(in thousands)
Delivered Energy
$
203,434
$
211,772
Capacity Revenue
58,093
56,155
Electric Sales
$
261,527
$
267,927
Fuel
$
(111,768)
$
(139,496)
Other Operating Costs (1)
(19)
(32)
Other Operating and Maintenance Costs (2)
(28,622)
(33,777)
Cost of Purchased Power
(10,888)
—
Utilities
(2,070)
(429)
Labor
(30,842)
(31,245)
General and Administrative
(5,311)
(4,914)
EBITDA Margin
72,007
58,034
Other Operating Revenue
982
414
Amortization of Contract Asset
—
(26,581)
Depreciation, Depletion and Amortization
(19,290)
(18,739)
Asset Retirement Obligations Accretion
(457)
(576)
Interest expense
(1,875)
(322)
Income (Loss) before Income Taxes
$
51,367
$
12,230
1)
Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
2)
Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered
variable as discussed above in 1).
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54
Year Ended December 31,
2024
2023
(per MWh)
MWh Generated (in thousands)
3,830
4,224
MWh Purchased (in thousands)
354
—
MWh Sold (in thousands)
4,184
4,224
Delivered Energy
$
48.62
$
50.14
Capacity Revenue
13.88
13.29
Electric Sales
$
62.50
$
63.43
Fuel
$
(26.71)
$
(33.02)
Other Operating Costs (1)
—
(0.01)
Other Operating and Maintenance Costs (2)
(6.84)
(8.00)
Cost of Purchased Power
(2.60)
—
Utilities
(0.49)
(0.10)
Labor
(7.37)
(7.40)
General and Administrative
(1.27)
(1.16)
EBITDA Margin
17.22
13.74
Other Operating Revenue
0.23
0.10
Amortization of Contract Asset
—
(6.29)
Depreciation, Depletion and Amortization
(4.61)
(4.44)
Asset Retirement Obligations Accretion
(0.11)
(0.14)
Interest expense
(0.45)
(0.08)
Income (Loss) before Income Taxes
$
12.28
$
2.89
1)
Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
2)
Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered
variable as discussed above in 1).
Fuel decreased $27.7 million, or 19.9%, from 2023 due to production decreasing by 394 MWh, or 9.3%, and the expiration of a
purchased coal contract in 2023 reducing our average coal pricing by $8.61 per ton, or 14%, on a segment basis. We used 189,000 tons,
or 9.2%, less in production compared to the prior year. The decrease in demand for electric power was related to mild weather
throughout 2024 and the associated higher demand for natural gas as natural gas inventories remained high causing a decline in the
average spot prices for natural gas which changed $0.34 per mbtu, or 13.5% from 2023.
Other operating and maintenance costs decreased $5.2 million, or 15.3%, from 2023 primarily due to 2023 year-to-date planned
maintenance of $13.0 million compared to $9.1 million in 2024.
Cost of purchased power increased $10.9 million, or 100.0%, from 2023. When energy hours at the Merom Hub are priced below our
production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.
Amortization of the contract asset decreased by $26.6 million, or 100.0%, from 2023 due to the expiration of our coal purchase
contract.
Income (loss) before income taxes increased $39.1 million, or 320.0%, and increased $9.39 per MWh, from 2023 due to the items
described in the discussion above.
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55
Coal Operations
Year Ended December 31,
2024
2023
(in thousands)
Coal Sales
$
202,525
$
432,888
Fuel
$
2,851
$
7,089
Other Operating and Maintenance Costs
89,283
165,479
Utilities
13,844
17,301
Labor
85,322
121,172
General and Administrative
9,877
10,287
EBITDA Margin
1,348
111,560
Other Operating Revenue
2,756
2,936
Depreciation, Depletion and Amortization
(46,245)
(48,365)
Asset Impairment
(215,136)
—
Asset Retirement Obligations Accretion
(1,171)
(1,228)
Exploration Costs
(260)
(904)
Gain (loss) on disposal or abandonment of assets, net
(1,629)
(398)
Interest expense
(11,033)
(11,869)
Loss on Extinguishment of Debt
—
(1,491)
Settlement of Litigation
(2,750)
—
Income (Loss) before Income Taxes
$
(274,120)
$
50,241
Year Ended December 31,
2024
2023
(per ton)
Tons Sold
3,864
6,922
Coal Sales
$
52.41
$
62.54
Fuel
$
0.74
$
1.02
Other Operating and Maintenance Costs
23.11
23.91
Utilities
3.58
2.50
Labor
22.08
17.51
General and Administrative
2.56
1.49
EBITDA Margin
0.34
16.11
Other Operating Revenue
Depreciation, Depletion and Amortization
(11.97)
(6.99)
Asset Impairment
(55.68)
—
Asset Retirement Obligations Accretion
(0.30)
(0.18)
Exploration Costs
(0.07)
(0.13)
Gain (loss) on disposal or abandonment of assets, net
(0.42)
(0.06)
Interest expense
(2.86)
(1.71)
Loss on Extinguishment of Debt
—
(0.22)
Settlement of Litigation
(0.71)
—
Income (Loss) before Income Taxes
$
(71.67)
$
6.82
During 2024, we undertook an Organizational Restructuring of our Coal Operations. See “Note 17 – Organizational Restructuring” in
the Consolidated Financial Statements for further information.
Segment operating revenues from coal operations decreased $230.4 million, or 53.2%, from 2023. Consolidated operating revenues
from coal operations decreased $224.5 million, or 62.0%, from 2023. These declines were due to reductions in volume and average
sales price for our coal. Our average sales price, on a segment basis, decreased $10.13 per ton and we sold 3.1 million tons less
compared to 2023. Our average sales price, on a consolidated basis, for 2024 decreased $7.58 per ton and we sold 3.3 million tons less
compared to 2023.
Other operating and maintenance costs decreased $76.2 million, or 46.0%. Labor decreased $35.9 million, or 29.6%, from 2023,
however labor cost per ton sold increased $4.57 per ton sold. These changes were driven by the Reorganization Plan disclosed
in “Note 17 — Organizational Restructuring” to the Consolidated Financial Statements. As part of the Organizational Restructuring,
we incurred aggregate expenses of $1.9 million ($1.1 million in the first
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56
quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in coal operations “Labor”. These charges related
to compensation, tax, professional, and insurance related expenses and are considered one-time charges paid during 2024. During 2024,
we produced 2.7 million tons less on a segment basis than 2023. Additionally, we went from 5 mines producing to 1 mine producing
and reduced our coal employee headcount by 305 employees.
We recorded an asset impairment of $215.1 million during 2024. During the fourth quarter of 2024, we began our annual business plan
review. We evaluated core hole samples at several of our mines, reviewing the quality of the mine seam and density of the coal. Based
upon market price trends, we believe that the required course of action is to only produce those reserves that will allow us the lowest
possible cost, and therefore capture the highest possible margins. The core hole samples at our Oaktown 2 mine were of a lower quality
and density than that of the Oaktown 1 mine. As such, at the conclusion our annual business plan review during the fourth quarter of
2024, we decided to temporarily seal the Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower
recovery costs. Due to that decision, we determined a triggering event had occurred and completed an impairment review to determine
if the carrying value of our coal properties were impaired by comparing the net book value of our coal properties to estimated
undiscounted future net cash flows. The result of this undiscounted cash flow test indicated the carrying amount of our coal properties
may not be recoverable. As a result, the Company prepared a discounted cash flow model (Level 3 fair value measurement under the
fair value hierarchy) to estimate fair value.
Income (loss) before income taxes decreased $324.4 million, or 645.6%, and decreased $78.49 per ton, from 2023. The main drivers of
this change in income from operations are described in the discussion above.
The following tables 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 tables present our unaudited quarterly results of operations for the eight quarters ended
December 31, 2024, and include all adjustments, consisting only of normal recurring adjustments, that we consider necessary for fair
presentation of our consolidated operating results for the quarters presented. In the fourth quarter of 2024, the Company made certain
reclassifications that reduced “other operating and maintenance costs” and increased “depreciation, depletion and amortization” for
certain assets with a useful life of one to three years. The entire adjustment is reflected in the fourth quarter of 2024. Previous interim
periods and prior year periods were not adjusted as the amounts were not material. The amounts recognized in the fourth quarter of
2024 that are related to the first, second and third quarters of 2024 were $2.1 million, $2.6 million and $1.7 million, respectively.
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57
Mar-31
Jun-30
Sep-30
Dec-31
2024
2024
2024
2024
Total 2024
(in thousands, except per share information)
SALES AND OPERATING REVENUES:
Electric sales
$
60,681
$
59,465
$
71,715
$
69,666
$
261,527
Coal sales
49,630
32,801
31,662
23,355
137,448
Other revenues
1,263
1,045
1,377
1,734
5,419
Total revenue
111,574
93,311
104,754
94,755
404,394
EXPENSES:
Fuel
8,059
10,439
13,176
17,669
49,343
Other operating and maintenance costs
37,482
35,912
33,320
11,650
118,364
Cost of purchased power
1,926
2,619
3,149
3,194
10,888
Utilities
4,374
3,396
3,185
4,959
15,914
Labor
35,168
26,555
26,721
27,720
116,164
Depreciation, depletion and amortization
15,443
13,649
13,838
22,696
65,626
Asset retirement obligations accretion
399
399
410
420
1,628
Exploration costs
70
47
62
81
260
General and administrative
5,944
7,803
6,471
6,309
26,527
Asset impairment
—
—
—
215,136
215,136
(Gain) loss on disposal or abandonment of assets, net
(24)
(222)
(290)
486
(50)
Settlement of litigation
—
—
—
2,750
2,750
Total operating expenses
108,841
100,597
100,042
313,070
622,550
INCOME (LOSS) FROM OPERATIONS
2,733
(7,286)
4,712
(218,315)
(218,156)
Interest expense (1)
(3,937)
(3,735)
(2,692)
(3,486)
(13,850)
Loss on extinguishment of debt
(853)
(1,937)
—
—
(2,790)
Equity method investment income (loss)
(249)
(257)
(234)
(6)
(746)
INCOME (LOSS) BEFORE INCOME TAXES
(2,306)
(13,215)
1,786
(221,807)
(235,542)
INCOME TAX EXPENSE (BENEFIT):
Current
—
—
—
(169)
(169)
Deferred
(610)
(3,011)
232
(5,846)
(9,235)
Total income tax expense (benefit)
(610)
(3,011)
232
(6,015)
(9,404)
NET INCOME (LOSS)
$
(1,696)
$
(10,204)
$
1,554
$ (215,792)
$ (226,138)
NET INCOME (LOSS) PER SHARE:
Basic
$
(0.05)
$
(0.27)
$
0.04
$
(5.06)
$
(5.72)
Diluted
$
(0.05)
$
(0.27)
$
0.04
$
(5.06)
$
(5.72)
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic
34,816
37,879
42,598
42,617
39,504
Diluted
34,816
37,879
43,018
42,617
39,504
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58
Mar-31
Jun-30
Sep-30
Dec-31
2023
2023
2023
2023
Total 2023
(in thousands, except per share information)
SALES AND OPERATING REVENUES:
Electric sales
$
92,392
$
71,017
$
67,403
$
37,115
$
267,927
Coal sales
94,602
88,574
97,420
81,330
361,926
Other revenues
1,361
1,640
965
1,059
5,025
Total revenue
188,355
161,231
165,788
119,504
634,878
EXPENSES:
Fuel
55,973
32,641
11,345
3,429
103,388
Other operating and maintenance costs
32,520
41,908
65,551
59,876
199,855
Cost of purchased power
—
—
—
—
—
Utilities
4,497
4,343
4,507
4,383
17,730
Labor
40,531
36,528
37,639
37,719
152,417
Depreciation, depletion and amortization
17,976
17,169
16,230
15,836
67,211
Asset retirement obligations accretion
451
461
468
424
1,804
Exploration costs
206
305
171
222
904
General and administrative
6,947
5,595
6,054
7,563
26,159
(Gain) loss on disposal or abandonment of assets, net
21
37
20
320
398
Total operating expenses
159,122
138,987
141,985
129,772
569,866
INCOME (LOSS) FROM OPERATIONS
29,233
22,244
23,803
(10,268)
65,012
Interest expense (1)
(3,899)
(3,541)
(3,030)
(3,241)
(13,711)
Loss on extinguishment of debt
—
—
(1,491)
—
(1,491)
Equity method investment income (loss)
69
(217)
(177)
(227)
(552)
INCOME (LOSS) BEFORE INCOME TAXES
25,403
18,486
19,105
(13,736)
49,258
INCOME TAX EXPENSE (BENEFIT):
Current
432
61
(178)
(479)
(164)
Deferred
2,920
1,510
3,208
(3,009)
4,629
Total income tax expense (benefit)
3,352
1,571
3,030
(3,488)
4,465
NET INCOME (LOSS)
$
22,051
$
16,915
$
16,075
$
(10,248)
$
44,793
NET INCOME (LOSS) PER SHARE:
Basic
$
0.67
$
0.51
$
0.49
$
(0.31)
$
1.35
Diluted
$
0.61
$
0.47
$
0.44
$
(0.31)
$
1.25
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic
32,983
33,137
33,140
33,245
33,133
Diluted
36,740
36,708
36,848
33,245
36,827
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59
Quarterly coal sales and cost data follow on a segment basis (in 000’s, except for per ton data and wash plant recovery percentage):
All Mines
1st 2024
2nd 2024
3rd 2024
4th 2024
T4Qs
Tons produced
1,271
889
873
971
4,004
Tons sold
1,214
849
926
875
3,864
Wash plant recovery in %
60 %
59 %
60 %
62 %
Capex (Coal Operations)
$
8,632
$
7,560
$
6,810
$ 11,079
$ 34,081
Maintenance capex (Coal Operations)
$
8,085
$
6,014
$
4,208
$
4,492
$ 22,799
Maintenance capex per ton sold (Coal Operations)
$
6.66
$
7.08
$
4.54
$
5.13
$
5.90
Average cost per ton sold⁽ⁱ⁾
$
51.65
$
49.94
$
52.22
$
43.25
$
49.51
All Mines
1st 2023
2nd 2023
3rd 2023
4th 2023
T4Qs
Tons produced
2,006
1,723
1,594
1,331
6,654
Tons sold
1,693
1,714
2,054
1,461
6,922
Wash plant recovery in %
70 %
67 %
65 %
62 %
Capex (Coal Operations)
$ 12,639
$ 14,445
$ 11,570
$ 17,867
$ 56,521
Maintenance capex (Coal Operations)
$
7,778
$
9,754
$
7,938
$ 13,567
$ 39,037
Maintenance capex per ton sold (Coal Operations)
$
4.59
$
5.69
$
3.86
$
9.29
$
5.64
Average cost per ton sold⁽ⁱ⁾
$
38.81
$
41.52
$
46.54
$
53.78
$
44.94
i)
Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”,
“Utilities” and “Labor” costs as adjusted for the fourth quarter 2024 reclassification adjustments previously described, divided by tons
sold for the respective period in this table. Coal Operations costs are presented in the “Presentation of Segment Information” above.
Critical Accounting Estimates
We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory,
treatment of business combinations, and the estimates used in impairment analysis are our critical accounting estimates.
The reserve estimates are used in the depreciation, depletion and amortization calculations and our internal cash flow projections. If
these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test
may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available
geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and
external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year
were nominal.
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 with the completion of surface mining operations. Federal law and some states impose on mine
operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for
damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly
other mining operations.
Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the
date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over
estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to
discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive
of market risk premiums. Activities include
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60
reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and
slurry ponds.
Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our
entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and
extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any
difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the
obligation is settled.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as
well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax
jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any
adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax
positions and our tax provision and returns are prepared by a large public accounting firm with significant experience in energy related
industries. Changes to the estimates from reported amounts in the prior year were not significant.
Inventory is valued at lower of cost or net realizable value (NRV). The NRV adjustments are subject to change as our costs may
fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of
December 31, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $0.3 million and $2.0 million, respectively.
Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and
circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For
impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are
identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of
cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management
oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset
impairment. This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the
Company and its Board of Directors no less than annually, normally during the 4
th quarter of each year. Changes in anticipated activity
levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.
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61
ITEM 8. FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm (PCAOB ID Number 248)
62
Consolidated Balance Sheets
65
Consolidated Statements of Operations
66
Consolidated Statements of Cash Flows
67
Consolidated Statement of Stockholders’ Equity
69
Notes to Consolidated Financial Statements
70
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62
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Hallador Energy Company
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Hallador Energy Company (a Colorado corporation) and subsidiaries
(the “Company”) as of December 31, 2024 and 2023, the related consolidated statements of operations, cash flows and stockholders’
equity for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the
“consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the
two years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of
America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013
Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(“COSO”), and our report dated March 17, 2025 expressed an unqualified opinion.
Change in accounting principle
As discussed in Notes 1 and 20 to the consolidated financial statements, the Company has adopted new accounting guidance in 2024
related to the disclosure of segment information in accordance with ASU 2023-07, Segment Reporting (Topic 280). The adoption was
retrospectively applied to 2023.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the
Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of
the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding
the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that
our audits provide a reasonable basis for our opinion.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that was
communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to
the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical
audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the
critical audit matters below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which they
relate.
Asset retirement obligations
As of December 31, 2024, the Company’s asset retirement obligations totaled $16.9 million. As described further in Note 1 to the
consolidated financial statements, the Company’s asset retirement obligations are associated with retirement of long-lived assets and
recognized at fair value at the time the obligations are incurred. The Company reviews its asset retirement obligations at least annually
and makes necessary adjustments for revisions of inputs and
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63
assumptions utilized in the calculations. The calculation of asset retirement obligations requires significant management judgment due
to the inherent complexity in estimating the amount and timing of future reclamation activities. We identified the accounting for the
asset retirement obligations as a critical audit matter.
The principal consideration for our determination that the accounting for the asset retirement obligations is a critical audit matter is that
management utilized significant judgment in determining the amount of asset retirement obligations. In particular, the obligations’
value is estimated based upon a discounted cash flow technique and includes inputs and assumptions related to uncertain future
reclamation costs and the timing of reclamation activities. Accordingly, auditing management’s assumptions involved a high degree of
subjectivity due to the uncertainty of management’s significant judgments.
Our audit procedures related to the accounting for asset retirement obligations included the following, among others:
●
We tested the design and operating effectiveness of internal controls over the asset retirement obligations estimation and
recognition process.
●
We assessed the reasonableness of the Company’s methodology to calculate asset retirement obligations.
●
We tested the completeness and accuracy of the underlying data used in management’s asset retirement obligations
calculation.
●
We evaluated the reasonableness of significant judgments including inflation rate, credit-adjusted risk-free rate, reclamation
cost estimates and timing of expected reclamation activities.
●
We interviewed the Company’s professionals with specialized skill and knowledge regarding the regulatory requirements and
mine plans.
Impairment of coal properties
As described further in Notes 1 and 19 to the consolidated financial statements, long-lived assets are evaluated for impairment
whenever events or changes in circumstances indicate the carrying value may not be recoverable. When performing the impairment
assessments, the Company projects undiscounted cash flows at the asset group level. If the asset group is determined not to be
recoverable, the Company, with the assistance of third-party valuation specialists, performs an analysis of the fair value of the asset
group and recognizes an impairment loss when the fair value of the asset group is less than the carrying value. As of December 31,
2024, the Company recorded asset impairment charges of $215.1 million associated with its coal properties. The identification of
impairment indicators and the calculation of the amount of impairment requires significant management judgment. We identified the
long-lived asset impairment assessment of coal properties as a critical audit matter.
The principal consideration for our determination that the long-lived asset impairment assessment of coal properties is a critical audit
matter is due to the uncertainties and significant management judgment when estimating the fair value of the coal properties. This in
turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to
management’s forecasted future revenues and cash flows and evaluation of the reasonableness of the valuation model used. In addition,
the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing these procedures and
evaluating the audit evidence obtained.
Our audit procedures related to the long-lived asset impairment assessment of coal properties included the following, among others:
●
We tested the design and operating effectiveness of internal controls over the identification of impairment indicators,
estimation of fair value, and recognition processes.
●
With the assistance of professionals with specialized skill and knowledge, we tested management’s process for calculating the
asset impairment of coal properties, including evaluating the reasonableness of the valuation methodology and certain
significant assumptions used in the calculations including the discount rate applied to the estimated future cash flows.
●
We evaluated the qualifications of the third-party specialist engaged by the Company based on their credentials and
experience.
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64
●
We evaluated the reasonableness of significant judgments including forecasted revenue and operating expenses. We tested
whether these forecasts were reasonable and consistent with historical performance and industry projections and conditions
found in industry reports, as applicable.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2022.
Tulsa, Oklahoma
March 17, 2025
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65
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Hallador Energy Company
Consolidated Balance Sheets
As of December 31,
(in thousands)
2024
2023
ASSETS
Current assets:
Cash and cash equivalents
$
7,232
$
2,842
Restricted cash
4,921
4,281
Accounts receivable
15,438
19,937
Inventory
36,685
23,075
Parts and supplies
39,104
38,877
Prepaid expenses
1,478
2,262
Assets held-for-sale
—
1,540
Total current assets
104,858
92,814
Property, plant and equipment:
Land and mineral rights
70,307
115,486
Buildings and equipment
429,857
537,131
Mine development
92,458
158,642
Finance lease right-of-use assets
13,034
12,346
Total property, plant and equipment
605,656
823,605
Less - accumulated depreciation, depletion and amortization
(347,952)
(334,971)
Total property, plant and equipment, net
257,704
488,634
Equity method investments
2,607
2,811
Other assets
3,951
5,521
Total assets
$
369,120
$
589,780
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of bank debt, net
$
4,095
$
24,438
Accounts payable and accrued liabilities
44,298
62,908
Current portion of lease financing
6,912
3,933
Contract liabilities - current
97,598
66,316
Total current liabilities
152,903
157,595
Long-term liabilities:
Bank debt, net
37,394
63,453
Convertible notes payable
—
10,000
Convertible notes payable - related party
—
9,000
Long-term lease financing
8,749
8,157
Deferred income taxes
—
9,235
Asset retirement obligations
14,957
14,538
Contract liabilities - long-term
49,121
47,425
Other
1,711
1,789
Total long-term liabilities
111,932
163,597
Total liabilities
264,835
321,192
Commitments and contingencies (Note 22)
Stockholders' equity:
Preferred stock, $.10 par value, 10,000 shares authorized; none issued
—
—
Common stock, $.01 par value, 100,000 shares authorized; 42,621 and 34,052 issued and outstanding, as of
December 31, 2024 and December 31, 2023, respectively
426
341
Additional paid-in capital
189,298
127,548
Retained earnings (deficit)
(85,439)
140,699
Total stockholders’ equity
104,285
268,588
Total liabilities and stockholders’ equity
$
369,120
$
589,780
The accompanying notes are an integral part of these Consolidated Financial Statements
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66
Hallador Energy Company
Consolidated Statements of Operations
For the years ended December 31,
(in thousands, except per share data)
2024
2023
SALES AND OPERATING REVENUES:
Electric sales
$
261,527
$
267,927
Coal sales
137,448
361,926
Other revenues
5,419
5,025
Total sales and operating revenues
404,394
634,878
EXPENSES:
Fuel
49,343
103,388
Other operating and maintenance costs
118,364
199,855
Cost of purchased power
10,888
—
Utilities
15,914
17,730
Labor
116,164
152,417
Depreciation, depletion and amortization
65,626
67,211
Asset retirement obligations accretion
1,628
1,804
Exploration costs
260
904
General and administrative
26,527
26,159
Asset impairment
215,136
—
(Gain) loss on disposal or abandonment of assets, net
(50)
398
Settlement of litigation
2,750
—
Total operating expenses
622,550
569,866
INCOME (LOSS) FROM OPERATIONS
(218,156)
65,012
Interest expense (1)
(13,850)
(13,711)
Loss on extinguishment of debt
(2,790)
(1,491)
Equity method investment (loss)
(746)
(552)
NET INCOME (LOSS) BEFORE INCOME TAXES
(235,542)
49,258
INCOME TAX EXPENSE (BENEFIT):
Current
(169)
(164)
Deferred
(9,235)
4,629
Total income tax expense (benefit)
(9,404)
4,465
NET INCOME (LOSS)
$
(226,138)
$
44,793
NET INCOME (LOSS) PER SHARE:
Basic
$
(5.72)
$
1.35
Diluted
$
(5.72)
$
1.25
WEIGHTED AVERAGE SHARES OUTSTANDING
Basic
39,504
33,133
Diluted
39,504
36,827
(1) Interest Expense:
Interest on bank debt
$
9,286 $
8,636
Other interest
2,817
1,842
Amortization:
Amortization of debt issuance costs
1,747
3,233
Total amortization
1,747
3,233
Total interest expense
$
13,850
$
13,711
The accompanying notes are an integral part of these Consolidated Financial Statements
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67
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
2024
2023
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)
$
(226,138)
$
44,793
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred income tax (benefit)
(9,235)
4,629
Equity method investment (loss)
746
552
Cash distribution - equity method investment
—
625
Depreciation, depletion and amortization
65,626
67,211
Asset impairment
215,136
—
Loss on extinguishment of debt
2,790
1,491
(Gain) loss on disposal or abandonment of assets, net
(50)
398
Amortization of debt issuance costs
1,747
3,233
Asset retirement obligations accretion
1,628
1,804
Cash paid on asset retirement obligation reclamation
(1,407)
(3,384)
Stock-based compensation
4,454
3,554
Amortization of contract asset and contract liabilities
(70,203)
(97,018)
Director fees paid in stock
150
—
Change in current assets and liabilities:
Accounts receivable
4,499
9,952
Inventory
(13,610)
15,548
Parts and supplies
(227)
(10,582)
Prepaid expenses
784
1,186
Accounts payable and accrued liabilities
(14,580)
(18,992)
Contract liabilities
103,181
33,804
Other
643
610
Net cash provided by operating activities
$
65,934
$
59,414
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68
Hallador Energy Company
Consolidated Statements of Cash Flows
For the years ended December 31,
(in thousands)
(continued)
2024
2023
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures
$
(53,367)
$
(75,352)
Proceeds from sale of equipment
4,239
62
Proceeds from held-for-sale assets
3,200
—
Investment in equity method investments
(542)
—
Net cash used in investing activities
(46,470)
(75,290)
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments on bank debt
(147,000)
(59,713)
Borrowings of bank debt
99,500
66,000
Payments on lease financing
(5,633)
—
Proceeds from sale and leaseback arrangement
5,134
11,082
Issuance of related party notes payable
5,000
—
Payments on related party notes payable
(5,000)
—
Debt issuance costs
(673)
(6,013)
ATM offering
34,515
7,318
Taxes paid on vesting of RSUs
(277)
(2,101)
Net cash provided by (used in) financing activities
(14,434)
16,573
Increase in cash, cash equivalents, and restricted cash
5,030
697
Cash, cash equivalents, and restricted cash, beginning of year
7,123
6,426
Cash, cash equivalents, and restricted cash, end of year
$
12,153
$
7,123
CASH, CASH EQUIVALENTS, AND RESTRICTED CASH:
Cash and cash equivalents
$
7,232
$
2,842
Restricted cash
4,921
4,281
$
12,153
$
7,123
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid for interest
$
10,511
$
9,966
SUPPLEMENTAL NON-CASH FLOW INFORMATION:
Change in capital expenditures included in accounts payable and prepaid expense
$
356
$
1,882
The accompanying notes are an integral part of these Consolidated Financial Statements
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69
Hallador Energy Company
Consolidated Statement of Stockholders’ Equity
(in thousands)
Additional
Retained
Total
Common Stock Issued
Paid-in
Earnings
Stockholders’
Shares
Amount
Capital
(Deficit)
Equity
BALANCE, DECEMBER 31, 2022
32,983
$
330
$
118,788
$
95,906 $
215,024
Stock-based compensation
—
—
3,554
—
3,554
Stock issued on vesting of RSUs
473
5
(5)
—
—
Taxes paid on vesting of RSUs
(198)
(2)
(2,099)
—
(2,101)
Stock issued in ATM offering
794
8
7,310
—
7,318
Net income
—
—
—
44,793
44,793
BALANCE, DECEMBER 31, 2023
34,052
$
341
$ 127,548
$
140,699 $
268,588
Stock-based compensation
—
—
4,454
—
4,454
Stock issued on vesting of RSUs
380
4
(4)
—
—
Taxes paid on vesting of RSUs
(159)
(2)
(275)
—
(277)
Stock issued on redemption of convertible notes
3,672
36
22,957
—
22,993
Stock issued in ATM offering
4,655
47
34,468
—
34,515
Stock issued for director fees
21
—
150
—
150
Net loss
—
—
—
(226,138)
(226,138)
BALANCE, DECEMBER 31, 2024
42,621
$
426
$ 189,298
$
(85,439)$
104,285
The accompanying notes are an integral part of these Consolidated Financial Statements
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70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2024 AND 2023
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Consolidation
The consolidated financial statements include the accounts of Hallador Energy Company (hereinafter, “we”, “our” or “us”) and our
wholly owned subsidiaries Hallador Power Company, LLC (“Hallador Power”), Sunrise Coal, LLC (“Sunrise”), and Hourglass Sands,
LLC (“Hourglass”), as well as Hallador Power and Sunrise’s wholly owned subsidiaries. All significant intercompany accounts and
transactions have been eliminated. Hallador Power is engaged in the production of coal-fired electric power generation located in
Sullivan County, Indiana. Sunrise is engaged in the production of steam coal from mines located in western Indiana.
Segment Information
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal
Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses
operating performance measures related to our Electric Operations and our Coal Operations segments.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant
enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of
unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC (“Sunrise Energy”), a private gas
exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.
During the fourth quarter of 2024, we sold our held-for-sale wholly-owned subsidiary Summit Terminal LLC, a logistics transport
facility located on the Ohio River. For further information, see “Note 21 – Assets Held For Sale” below.
The Electric Operations reportable segment includes electric power generation facilities of the Merom Power Plant (“Merom”).
The Coal Operations reportable segment includes our currently operating underground mining complex Oaktown 1 among other mining
complexes and locations which operated throughout the year ended December 31, 2023 and were subsequently idled during the year
ended December 31, 2024.
Reclassifications
Amounts in the prior years consolidated financial statements are reclassified whenever necessary to conform to the current year’s
presentation. Any reclassification adjustments had no impact on prior year total assets, liabilities, net income or shareholders’ equity.
In the fourth quarter of 2024, the Company made certain reclassifications that reduced “other operating and maintenance costs” and
increased “depreciation, depletion and amortization” on the Consolidated Statements of Operations for certain assets with a useful life
of one to three years. The entire adjustment is reflected in the fourth quarter of 2024. Previous interim periods and prior year were not
adjusted as the amounts were not material. The amounts recognized in the fourth quarter of 2024 that are related to the first, second and
third quarters of 2024 were $2.1 million, $2.6 million and $1.7 million, respectively.
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71
Cash and Cash Equivalents
Cash and cash equivalents include investments with maturities when purchased of three months or less. Cash balances at individual
banks may exceed the federally insured limit by the Federal Deposit Insurance Corporation. The Company has not experienced any
material losses in such accounts.
Restricted Cash
Restricted cash represents cash held by third parties primarily for future workers’ compensation claims and MISO escrow payments.
Workers’ compensation is based estimated claim liabilities and MISO escrow payments are based on power purchased or sold related to
power demand and our power purchase agreements (“PPA”).
Accounts Receivable
The timing of revenue recognition, billings and cash collections results in accounts receivable from customers. Customers are invoiced
as power is delivered or as coal is shipped or at periodic intervals in accordance with contractual terms. Coal invoices typically include
customary adjustments for the resolution of price variability, such as coal quality thresholds. Payments are generally received within
thirty days of invoicing. Historically, credit losses have been insignificant. No charges for credit losses were recognized during
the years ended December 31, 2024 or 2023.
Inventory and Parts and Supplies
Inventory and parts and supplies are valued at the lower of cost or net realizable value determined using the first-in first-out method.
Inventory costs include labor, supplies, operating overhead, and other related costs incurred at or on behalf of the mining location or
plant, including depreciation, depletion, and amortization of equipment, buildings, mineral rights, and mine development costs.
Contract Asset - Coal Purchase Agreement
Contract Asset - Coal Purchase Agreement, is the result of a coal purchase agreement with Hoosier whereby we purchased coal from
Hoosier through May 31, 2023, at fixed prices which were below market prices at the date of entry into the agreement. This agreement
was entered into as consideration in our 2022 acquisition of Merom. The asset was amortized to inventory as coal was purchased over
the term of the agreement as the contract was fulfilled. During the years ended December 31, 2023, $19.6 million was amortized, of
which $30.7 million was recognized in operating expenses on the consolidated statements of operations. The Coal Purchase Agreement
term was from October 21, 2022 to May 31, 2023.
Prepaid Expenses
Prepaid expenses include prepaid insurance and other prepaid balances with vendors for various services paid for in advance of use.
Advanced Royalties
Coal leases that require minimum annual or advance payments and are recoverable from future production are generally deferred and
charged to expense as the coal is subsequently produced. Advance royalties are included in other assets.
Plant Equipment and Mining Properties
The values of our Hallador Power property, plant and equipment were initially recorded at relative fair value based on the consideration
paid upon closing of the acquisition of Merom in 2022. Other equipment is recorded at cost. Expenditures that extend the useful lives or
increase the productivity of the assets are capitalized. The cost of maintenance and repairs that do not extend the useful lives or increase
the productivity of the assets are expensed as
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incurred. Most power plant equipment is depreciated over the remaining estimated useful life of the Merom at the time of equipment
acquisition, or seven to nine years.
Mining properties are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period.
Expenditures that extend the useful lives or increase the productivity of the assets are capitalized. The cost of maintenance and repairs
that do not extend the useful lives or increase the productivity of the assets are expensed as incurred. Other than land and most mining
equipment, mining properties are depreciated using the units-of-production method over the estimated recoverable reserves. Most
surface and underground mining equipment is depreciated using estimated useful lives ranging from three to fifteen years.
The Company reviews long-lived assets for impairment whenever events or changes in circumstances, known as triggering events,
indicate that the carrying amount of a long-lived asset or asset group, may not be recoverable. Management considers various factors
when determining if long-lived assets should be evaluated for impairment, including a significant adverse change in the business
climate or industry conditions (such as sustained decreases in commodity prices, volatility in energy costs, and the global economy), a
current period operating or cash flow loss combined with a history of losses, a significant adverse change in the extent or manner in
which an asset is used, or a current expectation that the asset will be sold or otherwise disposed of before the end of its useful life.
During the fourth quarter of 2024, the Company completed a review of its coal mining facilities and future mining plans. The
impairment analysis was based upon our coal mining operating plans, market driven pricing and cost trends. As part of that analysis, the
Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded a non-cash, long-
lived asset impairment charge of $215.1 million in 2024. See “Note 19 – Impairment of Coal Properties” below related to our 2024
impairment. There were no long-lived asset impairments during the year ended December 31, 2023.
Mine Development
Costs of developing new mines, including asset retirement obligation assets, or significantly expanding the capacity of existing mines,
are capitalized and amortized using the units-of-production method over estimated recoverable reserves.
Asset Retirement Obligations (“ARO”) – Reclamation
At the time they are incurred, legal obligations associated with the retirement of long-lived assets are reflected at their estimated fair
value, with a corresponding charge to mine development. Obligations are typically incurred when the Company
commences development of underground and surface mines and include reclamation of support facilities, refuse areas and slurry ponds.
Obligations are reflected at the present value of their future cash flows. The Company reflects accretion of the obligations for the period
from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production
method over estimated recoverable (proven and probable) reserves. The Company uses the credit-adjusted risk-free discount rates
ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates
prepared by its engineers inclusive of market risk premiums. Federal and state laws require that mines be reclaimed in accordance with
specific standards and approved reclamation plans, as outlined in mining permits. Activities include reclamation of pit and support
acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.
The Company reviews its ARO at least annually and reflects revisions for permit changes, changes in estimated reclamation costs and
changes in the estimated timing of such costs. The change in estimate for the year ended December 31, 2023, was a result of a change in
timing and acreage of expected reclamation of Merom. There was no change in estimate for the year ended December 31, 2024. In the
event the Company is not able to perform reclamation, it has surety bonds at December 31, 2024 totaling $30.8 million to cover
ARO. The undiscounted asset retirement obligation was $26.1 million and $26.6 million at December 31, 2024 and 2023, respectively.
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73
The table below (in thousands) reflects the changes to ARO for the periods presented:
Year Ended December 31,
2024
2023
Balance, beginning of year
$
16,688
$
20,834
Accretion
1,628
1,804
Change in estimate
—
(2,566)
Payments
(1,407)
(3,384)
Balance, end of year
16,909
16,688
Less current portion
(1,952)
(2,150)
Long-term balance, end of year
$
14,957
$
14,538
Contract Liabilities
Contract Liabilities include the PPA with Hoosier whereby Hallador Power is selling power to Hoosier through 2025 at fixed prices
which were below market prices at the date the parties entered into the agreement. Hallador Power also agreed to a reduction in future
capacity payments as part of the acquisition consideration. These agreements were entered into as consideration for the acquisition of
Merom in 2022. The agreement was amended August 31, 2023 to extend through 2028. The amendment included additional obligations
to Hoosier of $186.6 million, or $56.00 per MWh, as of December 31, 2024. The power purchase agreement liability is amortized to
electric sales revenue pro-rata over the term of the agreement as the contract is fulfilled. During the years ended December 31, 2024 and
2023, amortization of the power purchase agreement contract liability totaled $47.1 million and $70.5 million, respectively. The Power
Purchase Agreement term is from October 21, 2022 to May 31, 2028. The Capacity Payment Reductions occurred on May 31, 2023 and
November 30, 2023 in the amount of $7.5 million each. The contract liability relating to this contract totaled $43.5 million as of
December 31, 2024.
We also have contract liabilities arising from PPA’s for capacity and physically delivered power entered into whereas the customers
made advance payments to Hallador Power. These contracts that have delivery periods through the Spring shoulder season ending May
31, 2025. The liability will be amortized to electric sales revenue over the remaining term of the agreement as the contract is fulfilled.
The contract liability relating to these contracts totaled $42.0 million as of December 31, 2024.
During the year ended December 31, 2024, the Company entered into a $60.0 million prepaid physically delivered power contract. The
power purchase agreement term is from June 1, 2025 through December 31, 2026. The power purchase agreement liability will
be amortized to electric sales revenue pro-rata over the term of the agreement as the contract is fulfilled. The contract liability,
including $1.2 million of implied interest relating to this contract totaled $61.2 million as of December 31, 2024.
Commitments and Contingencies
From time to time, we are involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the
ordinary course of business. We have concluded that the likelihood is remote that the ultimate resolution of any pending litigation or
pending claims will be material or have a material adverse effect on our business, financial position, results of operations or liquidity.
See “Note 22 – Contingencies” related to our decision to settle certain litigation in February of 2025.
Fuel Costs
Fuel costs in our Electric Operations include coal purchased from Sunrise Coal and third parties to operate Merom. Fuel costs in our
Coal Operations include mainly diesel, as well as natural gas and petroleum to operate our coal mines. These fuel costs are expensed as
the fuel is used. The difference between Sunrise Coal’s cost to produce coal and the contracted sales price to Hallador Power is
eliminated from fuel costs on the Consolidated Statements of Operations.
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Income Taxes
Income taxes are provided based on the liability method of accounting. The provision for income taxes is based on pretax financial
income. Deferred tax assets and liabilities are recognized for the future expected tax consequences of temporary differences between
income tax and financial reporting and principally relate to differences in the tax basis of assets and liabilities and their reported
amounts, using enacted tax rates in effect for the year in which differences are expected to reverse.
Net Income per Share
Basic earnings per share (“EPS”) are computed by dividing net earnings by the weighted average number of common shares
outstanding for the period.
Diluted EPS attributable to common shareholders is computed by adjusting net earnings by the weighted average number of common
shares and potential common shares outstanding (if dilutive) during each period. Potential common shares include shares of restricted
stock units as if the units issued by us were vested and convertible debt. We apply the treasury stock method to account for the dilutive
impact of its restricted stock units and the if converted method for its convertible notes. Anti-dilutive securities are excluded from
diluted EPS. As a result of determining the effect of potentially dilutive securities, in certain periods, diluted net loss per share is the
same as the basic net loss per share for the periods presented.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires us to make estimates and
assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements, and the reported amounts of revenue and expenses during the reporting period. Actual amounts could differ from
those estimates. The most significant estimates included in the preparation of the financial statements relate to: (i) deferred income tax
accounts, (ii) coal reserves, (iii) SMCRA and other state statutes, (iv) depreciation, depletion, and amortization, (v) the lower of cost or
net realizable value for our inventory (vi) estimates used in our impairment analysis, and (vii) estimates used in the calculation of ARO.
Long-term Contracts
Power Operations
As of December 31, 2024, we are committed to supply the following long-term delivered energy and capacity related to Hoosier and
third-party customers:
2025
2026
2027
2028
2029
Annual plant energy generation (in MWh) (in millions)
6.0
6.0
6.0
6.0
6.0
Hoosier PPA delivered energy (in MWh) (in millions)
1.7
1.6
1.3
0.4
-
Percentage of annual plant energy generation
28%
27%
22%
7%
0%
Other customers delivered energy (in MWh) (in millions)
0.6
1.8
0.5
0.7
0.3
Percentage of annual plant energy generation
10%
30%
8%
12%
5%
Plant capacity (in MW)
775
800
800
800
800
Hoosier PPA Capacity (in MW)
97
105
110
46
-
Percentage of annual plant capacity
13%
13%
14%
6%
0%
Other customers capacity (in MW)
68
89
118
120
15
Percentage of annual plant capacity
9%
11%
15%
15%
2%
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For 2024, we derived 89% of our delivered energy and 88% of our capacity sales revenue from three and four customers, respectively,
each of which representing at least 10% of sales revenue. At December 31, 2024, 100% of our accounts receivable were with three
customers.
For 2023, we derived 100% of our electric delivered energy generation from Hoosier and 91% of our capacity sales revenue from three
customers, each representing at least 10% of capacity sales revenue. For the year ended December 31, 2023, 100% of our electric sales
and accounts receivable were with two customers.
Coal Operations
As of December 31, 2024, we are committed to supplying third-party customers 8.4 million tons of coal through 2028. There are no
coal contracts with price reopeners at December 31, 2024. In addition, we are committed to supplying 9.2 million tons of coal to Merom
through 2028. All committed tons to Merom are priced based upon the terms of the intercompany sales transactions.
For 2024, we derived 94% of our third-party coal sales from three customers, each representing at least 10% of coal sales. At
December 31, 2024, 98% of our coal operations accounts receivable was from four customers, each representing more than 10%.
For 2023, we derived 93% of our third-party coal sales from five customers, each representing at least 10% of coal sales. At
December 31, 2023, 85% of our coal operations accounts receivable was from four customers, each representing more than 10%.
Stock-based Compensation
Stock-based compensation for restricted stock units is measured at the grant date based on the fair value of the award and is recognized
as expense over the applicable vesting period of the stock award (generally two to four years) using the straight-line method.
Recent Accounting Pronouncements - Adopted
The Company has adopted Accounting Standards Update ("ASU") 2023-07, Segment Reporting (Topic 280): Improvements to
Reportable Segment Disclosures ("ASU 2023-07"), which is effective retrospectively for the year end December 31, 2024. ASU 2023-
07 primarily enhances disclosures about significant segment expenses regularly provided to the chief operating decision maker
("CODM"), the amount and composition of other segment items, and the title and position of the CODM. The Company updated the
“Segment of Business” footnote below to reflect changes for what the CODM reviews on a regular basis. The Company updated its
prior year information to conform to the current year presentation. See “Note 20 – Segments of Business” for enhanced disclosures
associated with the adoption of ASU 2023-07.
Recent Accounting Pronouncements Not Yet Adopted
In December 2023, the Financial Accounting Standards Board ("FASB") issued ASU 2023-09, Income Taxes (Topic 740):
Improvements to Income Tax Disclosures ("ASU 2023-09"). ASU 2023-09 primarily requires enhanced disclosures to (1) disclose
specific categories in the rate reconciliation, (2) disclose the amount of income taxes paid and expensed disaggregated by federal, state,
and foreign taxes, with further disaggregation by individual jurisdictions if certain criteria are met, and (3) disclose income (loss) from
continuing operations before income tax (benefit) disaggregated between domestic and foreign. ASU 2023-09 is effective for
fiscal years beginning after December 15, 2024, with early adoption permitted. We are currently evaluating the impact of adopting ASU
2023-09, but do not expect it to have a material effect on our consolidated financial statements.
In November 2024, the FASB issued ASU 2024-04, Debt - Debt With Conversion and Other Options (Subtopic 470-20): Induced
Conversion of Convertible Debt Instruments. The objective of the standard is to improve the relevance and consistency in application of
the induced conversion guidance in Subtopic 470-20, Debt with Conversion and Other
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Options. This standard will affect entities that settle convertible debt instruments for which the conversion privileges are changed to
induce conversion. The guidance will be effective for annual reporting periods beginning after December 15, 2025, and interim
reporting periods within those annual reporting periods. The Company is currently evaluating the impact of the new standard on its
financial statements and related disclosures.
In November 2024, the FASB issued ASU 2024-03, Income Statement Reporting-Comprehensive Income-Expense Disaggregation
Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. The standard update improves the disclosures about a
public business entity’s expenses by requiring more detailed information about the types of expenses (including purchases of inventory,
employee compensation, depreciation and amortization) included within income statement expense captions. The guidance will be
effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15,
2027. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The
Company is currently evaluating the impact of adoption of the standard on its financial statement disclosures.
(2) INVENTORY
Inventory is valued at lower of cost or net realizable value (“NRV”). As of December 31, 2024 and 2023, coal inventory includes NRV
adjustments of $0.3 million and $2.0 million, respectively.
(3) OTHER LONG-TERM ASSETS (IN THOUSANDS)
December 31,
2024
2023
Advanced coal royalties
$
3,906
$
5,521
Other
45
—
Total other assets
$
3,951
$
5,521
(4) BANK DEBT
On March 13, 2023, we executed an amendment (“March 13th Amendment”) to our credit agreement with PNC Bank, National
Association (in its capacity as administrative agent, "PNC"). The primary purpose of the March 13th Amendment was to convert
$35.0 million of the outstanding balance on the revolver into a new term loan with a maturity date of March 31, 2024, and extend the
maturity date of the revolver to May 31, 2024. The March 13th Amendment also reduced the total capacity under the revolver to $85.0
million and waived the maximum annual capital expenditure covenant for 2022 and increased the covenant for 2023 to $75.0
million. Subsequent to December 31, 2022, and prior to the effective date of the March 13th Amendment, we had borrowed an
additional $17.0 million under the revolver. Additionally, the March 13th Amendment provided for the transition in interest rates from
the London Interbank Offered Rate (“LIBOR”) to the Secured Overnight Financing Rate (“SOFR”) based pricing with ranges from
SOFR plus 4.00% to SOFR plus 5.00%, depending on our leverage ratio.
On August 2, 2023, we executed an additional amendment (“August 2nd Amendment”) to our credit agreement with PNC, which was
accounted for as a debt extinguishment. The primary purpose of the August 2nd Amendment was to convert $65.0 million of the
outstanding funded debt into a new term loan with a maturity of March 31, 2026, and enter into a revolver of $75.0 million with a
maturity of July 31, 2026. The August 2nd Amendment increased the maximum annual capital expenditure limit to $100.0 million.
Prior to the March 13th Amendment, bank debt was comprised of term debt ($5.5 million as of December 31, 2022) and a $120 million
revolver ($79.7 million borrowed as of December 31, 2022). The term debt amortization was to conclude with the final payment of $5.5
million in March 2023. The revolver was to mature in September 2023. Under the provision of the March 13th Amendment, bank debt
was comprised of term debt ($35.0 million as of March 13, 2023) and an $85.0 million revolver ($40.2 million borrowed as of
March 13, 2023). The term debt required payment of $10.0 million in June 2023 each quarter thereafter in 2023 and $5.0 million by
March 31, 2024. Under the August 2nd Amendment, bank debt was comprised of term debt ($58.5 million borrowed as of December 31,
2023) and a $75.0
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million revolver ($33.0 million borrowed as of December 31, 2023). The term debt requires quarterly payments of $6.5 million
beginning April 2024 through March 2026.
On September 27, 2024, the Company executed the First Amendment (“First Amendment”) to the Fourth Amended and Restated Credit
Agreement, dated as of August 2, 2023 (as amended, the “Credit Agreement”), with PNC which was accounted for as a debt
modification. The primary purpose of the First Amendment was to provide the Company with short-term covenant relief to pursue
additional liquidity. The First Amendment provides for additional flexibility for the Company to enter into prepaid forward power sale
contracts, provided that the Company repays outstanding term loans under the Credit Agreement (“Term Loan”) with proceeds received
from certain eligible power purchase agreements, up to a maximum of $20.0 million. These required prepaid forward power sale Term
Loan repayments, if any, will take the place of the $6.5 million quarterly Term Loan payments. During the fourth quarter of 2024, the
Company entered into a prepaid forward power sales contract in which $20.0 million of the proceeds were used to pay our required $6.5
million quarterly loan payments through the third quarter of 2025 and also reduced our fourth quarter 2025 payment to $6.0 million.
Furthermore, the First Amendment defines certain administrative changes which include, among other things, added requirements
related to reporting, third party financial advisors, and appraisals on coal and power assets.
Bank debt was reduced by $47.5 million and increased by $6.3 million during the years ended December 31, 2024 and 2023,
respectively.
Our debt is recorded at amortized cost, which approximates fair value due to the variable interest rates in the agreement and is
collateralized primarily by our assets.
Liquidity
As of December 31, 2024, we had additional borrowing capacity of $30.6 million under the revolver and total liquidity of $37.8 million.
Our additional borrowing capacity is net of $19.4 million in outstanding letters of credit as of December 31, 2024 that were required to
maintain surety bonds. Liquidity consists of additional borrowing capacity and cash and cash equivalents.
Fees
Unamortized bank fees and other costs incurred in connection with our initial facility totaled $4.3 million. Additional costs incurred
with the First Amendment totaled $0.6 million. These unamortized bank fees were deferred and are being amortized over the term of the
loan.
During 2023 we recognized a loss on extinguishment of debt of $1.5 million for the write-off of unamortized loan fees related to the
August 2nd Amendment to our credit agreement, which was accounted for as a debt extinguishment. The remaining costs were deferred
and are being amortized over the term of the loan. Unamortized bank fees as of December 31, 2024 and 2023, were $2.5 million and
$3.6 million, respectively.
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Bank debt, less debt issuance costs, is presented below (in thousands):
December 31,
2024
2023
Current bank debt
$
6,000
$
26,000
Less unamortized debt issuance cost
(1,905)
(1,562)
Net current portion
$
4,095
$
24,438
Long-term bank debt
$
38,000
$
65,500
Less unamortized debt issuance cost
(606)
(2,047)
Net long-term portion
$
37,394
$
63,453
Total bank debt
$
44,000
$
91,500
Less total unamortized debt issuance cost
(2,511)
(3,609)
Net bank debt
$
41,489
$
87,891
Covenants
The First Amendment, among other things, provided the Company with short-term covenant relief to pursue additional liquidity. The
First Amendment waived the Company’s Leverage Ratio requirement for the third and fourth quarters of 2024, increased the threshold
to 5.50 to 1.00 for the first quarter of 2025, and decreased the threshold back to 2.25 to 1.00 for each fiscal quarter thereafter.
Additionally, the Debt Service Coverage Ratio requirement (1.25 to 1.00) was waived from third quarter of 2024 through the first
quarter of 2025. The First Amendment also added additional financial covenants which include: (i) a maximum First Lien Leverage
Ratio for the first quarter of 2025, calculated as of the end of each fiscal quarter for the trailing twelve months, not to exceed 3.50 to
1.00; (ii) a minimum liquidity requirement of $10.0 million, beginning on the First Amendment execution date and ending when the
second quarter of 2025 compliance certificate is received; and (iii) a minimum quarterly EBITDA requirement, as defined in the First
Amendment, of $5.0 million for the third quarter of 2024 through the first quarter of 2025.
As of December 31, 2024, our liquidity of $37.8 million and quarterly EBITDA of $6.2 million were in compliance with the
requirements of the Credit Agreement.
Interest Rate
The interest rate on the facility ranges from SOFR plus 4.00% to SOFR plus 5.00%, depending on our Leverage Ratio. As of
December 31, 2024, we were paying SOFR plus 5.00% on the outstanding bank debt which equates to an all-in rate of 9.48%.
Future Maturities (in thousands):
2025
$
6,000
2026
38,000
2027
—
Total
$
44,000
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79
(5) ACCOUNTS PAYABLE AND ACCRUED LIABILITIES (IN THOUSANDS)
December 31,
2024
2023
Accounts payable
$
24,291
$
43,636
Accrued property taxes
4,185
2,987
Accrued payroll
3,258
6,575
Workers' compensation reserve
4,321
3,629
Group health insurance
1,700
2,300
Asset retirement obligation - current portion
1,952
2,150
Other
4,591
1,631
Total accounts payable and accrued liabilities
$
44,298
$
62,908
(6) REVENUE
Revenue from Contracts with Customers
We account for a contract with a customer when the parties have approved the contract and are committed to performing their
respective obligations, the rights of each party are identified, payment terms are identified, the contract has commercial substance, and
it is probable substantially all of the consideration will be collected. We recognize revenue when we satisfy a performance obligation by
transferring control of a good or service to a customer.
Electric operations
We concluded that for a Power Purchase Agreement (“PPA”) that is not determined to be a lease or derivative, the definition of a
contract and the criteria in ASC 606, Revenue from Contracts with Customers (“ASC 606”), is met at the time a PPA is executed by the
parties, as this is the point at which enforceable rights and obligations are established. Accordingly, we concluded that a PPA that is not
determined to be a lease or derivative constitutes a valid contract under ASC 606.
We recognize revenue daily, based on an output method of capacity made available as part of any stand-ready obligations for contract
capacity performance obligations and daily, based on an output method of MWh of electricity delivered.
For the delivered energy performance obligation in the PPA with Hoosier, we recognize revenue daily for actual delivered
electricity plus the amortization of the contract liability as a result of the Asset Purchase Agreement with Hoosier. For the delivered
energy to all other customers, we recognize revenue daily for the actual delivered electricity.
Coal operations
Our coal revenue is derived from sales to customers of coal produced at its facilities. Our customers typically purchase coal directly
from our mine sites where the sale occurs and where title, risk of loss, and control pass to the customer at that point. Our customers
arrange for and bear the costs of transporting their coal from our mines to their plants or other specified discharge points. Our customers
are typically domestic utility companies. Our coal sales agreements with our customers are fixed-priced, fixed-volume supply contracts,
or include a pre-determined escalation in price for each year. Price re-opener and index provisions may allow either party to commence
a renegotiation of the contract price at a pre-determined time. Price re-opener provisions may automatically set a new price based on the
prevailing market price or, in some instances, require us to negotiate a new price, sometimes within specified ranges of prices. The
terms of our coal sales agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms
of these contracts vary by customer.
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Coal sales agreements will typically contain coal quality specifications. With coal quality specifications in place, the raw coal sold by us
to the customer at the delivery point must be substantially free of magnetic material and other foreign material impurities and crushed to
a maximum size as set forth in the respective coal sales agreement. Price adjustments are made and billed in the month the coal sale was
recognized based on quality standards that are specified in the coal sales agreement, such as British thermal unit (“Btu”) factor,
moisture, ash, and sulfur content, and can result in either increases or decreases in the value of the coal shipped.
Disaggregation of Revenue
Revenue is disaggregated by revenue source for our electric operations and primary geographic markets for our coal operations, as we
believe this best depicts how the nature, amount, timing, and uncertainty of its revenue and cash flows are affected by economic factors.
Electric operations
December 31,
2024
2023
Delivered energy (including contract liability amortization)
$
203,434
$
211,772
Capacity
58,093
56,155
Total Electric Operations sales
$
261,527
$
267,927
Coal operations
December 31,
2024
2023
Outside third-party Indiana customers
$
59,045
$
144,942
Customers in Florida, North Carolina, Alabama and Georgia
78,403
216,984
Total Coal Operations sales
$
137,448
$
361,926
Performance Obligations
Electric Operations
We concluded that each megawatt hour (“MWh”) of delivered energy is capable of being distinct as a customer could benefit from each
on its own by using/consuming it as a part of its operations. We also concluded that the stand-ready obligation to be available to provide
electricity is capable of being distinct as each unit of capacity provides an economic benefit to the holder and could be sold by the
customer.
In accordance with our Asset Purchase Agreement (“Hoosier APA”) with Hoosier in which Hallador Power shall sell, and Hoosier shall
buy, delivered energy quantities through 2025 at the contract price, which is $34.00 per MWh. We have remaining delivered energy
obligations to Hoosier totaling $59.0 million through 2025 as of December 31, 2024. The agreement was amended August 31, 2023 to
extend through 2028. The amendment included additional obligations to Hoosier of $186.6 million, or $56.00 per MWh, as of
December 31, 2024.
In addition to delivered energy, under the Hoosier APA, Hallador Power shall provide a stand-ready obligation to provide electricity to
MISO, also known as contract capacity. The contract capacity that Hallador Power shall provide to Hoosier is 917 megawatts (“MW”)
for contract year one, and on average 300 MW for contract years two to four. Hoosier shall pay Hallador Power the capacity price of
$5.80 per kilowatt month for the contract capacity. We have remaining capacity obligations to Hoosier through 2025 totaling $18.6
million as of December 31, 2024. The agreement was amended August 31, 2023, to extend through 2028, with additional capacity
obligation to Hoosier of $59.5 million as of December 31, 2024, at a price of $7.02 per kilowatt month for the contract capacity.
During the second quarter of 2024, the Company entered into an 11-month, $45.0 million prepaid physically delivered power
contract in which Hallador will provide a total of 1,302,480 MWh. Since the period between customer payment
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and the transfer of promised services is less than one year, we have elected the practical expedient which allows us to not assess
whether a customer contract has a significant financing component.
During the fourth quarter of 2024, we entered into a 19-month, $60.0 million prepaid physically delivered power contract in which
Hallador will provide a total of 1,918,200 MWh. As the total amount paid up-front by the customer differs from the stand-alone selling
price of the transferred power, the Company concluded the contract contains a significant financing component. The contract liability
associated with the $60.0 million prepayment will be accreted over the agreement term based upon the Company’s incremental
borrowing rate which approximates 10.3%, and the accretion will be separately recognized as interest expense.
The Company also has additional PPA’s with customers for capacity whereas the customers made advance payments to Hallador Power
in the amounts of $35.4 million and $35.3 million during the years ended December 31, 2024 and 2023, respectively. The delivery
periods related to these prepayments are June 1 through May 31. The liability will be amortized to electric sales revenue as the contract
is fulfilled.
Additionally, during the fourth quarter of 2024, we entered into three contracts in the amount of $52.1 million to provide a total of
1,389,600 MWh from December 2024 through December 2025. We have energy and capacity obligations to customers, excluding the
Hoosier APA, through 2029 totaling $230.8 million and $131.3 million, respectively, as of December 31, 2024.
Coal Operations
A performance obligation is a promise in a contract with a customer to provide distinct goods or services. Performance obligations are
the unit of account for purposes of applying the revenue recognition standard and therefore determine when and how revenue is
recognized. In most of our coal contracts, the customer contracts with us to provide coal that meets certain quality criteria. We
consider each ton of coal a separate performance obligation and allocate the transaction price based on the base price per the contract,
increased or decreased for quality adjustments.
We recognize revenue at a point in time as the customer does not have control over the asset at any point during the fulfillment of the
contract. For substantially all of our customers, this is supported by the fact that title and risk of loss transfer to the customer upon
loading of the truck or railcar at the mine. This is also the point at which physical possession of the coal transfers to the customer, as
well as the right to receive substantially all benefits and the risk of loss in ownership of the coal.
We have remaining coal sales performance obligations relating to fixed priced contracts to third-party customers of approximately
$460.4 million, which represent the average fixed prices on our committed contracts as of December 31, 2024. We expect to recognize
approximately 32.7% of this coal sales revenue in 2025, with the remainder recognized through 2028.
The coal tons used to determine the remaining performance obligations are subject to adjustment in instances of force majeure and
exercise of customer options to either take additional tons or reduce tonnage if such option exists in the customer contract.
Contract Balances
Under ASC 606, the timing of when a performance obligation is satisfied can affect the presentation of accounts receivable, contract
assets, and contract liabilities. The main distinction between accounts receivable and contract assets is whether consideration is
conditional on something other than the passage of time. A receivable is an entity’s right to consideration that is unconditional.
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Under the typical payment terms of our contracts with customers, the customer pays us a base price for the coal, increased or decreased
for any quality adjustments, electricity, or capacity. Amounts billed and due are recorded as trade accounts receivable and included in
accounts receivable in our consolidated balance sheets.
December 31,
2024
2023
2022
Accounts receivable from contracts with customers
$
15,438
$
19,937
$
29,889
Contract assets
—
—
19,567
Contract liabilities - current
97,598
66,316
123,599
Contract liabilities - long-term
49,121
47,425
84,096
Total contract liabilities
146,719
113,741
207,695
We received payments related to advanced capacity and advanced physically delivered energy of $160.0 million and $41.2 million for
the years ending December 31, 2024 and 2023, respectively. Of the amount of contract liabilities that we recorded as of the beginning
of the period, we recognized $70.2 million and $123.6 million of electric revenue related to these advance contract liability payments
for the years ended December 31, 2024 and 2023, respectively. We do not currently have any other contracts in place where it would
transfer coal, electricity or capacity in advance of knowing the final price, and thus do not have any other contract assets recorded.
Contract liabilities also arise when consideration is received in advance of performance.
(7) INCOME TAXES
Our income tax is different than the expected amount computed using the applicable federal statutory income tax rate of 21%. The
reasons for and effects of such differences for the years ended December 31st are below (in thousands):
2024
2023
Expected amount
$
(49,464)
$
10,344
State income taxes, net of federal benefit
(9,059)
1,246
Percentage depletion
—
(3,348)
Change in valuation allowance
49,695
(3,681)
Stock-based compensation
121
(844)
Return to provision adjustments
(722)
159
Nondeductible items
175
—
Other
(150)
589
Total income tax expense
$
(9,404)
$
4,465
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The deferred tax assets and liabilities resulting from temporary differences between book and tax basis are comprised of the following
at December 31st (in thousands):
2024
2023
Deferred tax assets:
Net operating loss
$
32,725
$
20,029
Power contracts
10,828
23,302
Compensation
1,955
2,287
Accrued liabilities
423
570
ARO liabilities
2,293
2,798
Lease liabilities
3,938
3,044
Coal properties
26,191
—
Other
5,215
2,016
Total deferred tax assets
83,568
54,046
Valuation allowance
(49,695)
—
Deferred tax assets, net of valuation allowance
33,873
54,046
Deferred tax liabilities:
Coal properties
—
(28,535)
Power properties
(27,960)
(31,126)
Investment partnerships
(531)
(549)
ROU assets
(5,382)
(3,071)
Total deferred tax liabilities
(33,873)
(63,281)
Net deferred tax liability
$
—
$
(9,235)
Our effective tax rate (“ETR”) for 2024 and 2023 was approximately 4% and 9% respectively. The tax rate for the years ended
December 31, 2024 and 2023 are not predictive of future tax rates. Our ETR differs from the statutory rate due to statutory depletion in
excess of tax basis, return to provision adjustments, stock-based compensation and changes in the valuation allowance. The deduction
for statutory depletion does not necessarily change proportionately to changes in income before income taxes.
We recognize deferred tax assets to the extent that we believe that these assets are more likely than not to be realized. In making such a
determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary
differences, projected future taxable income, tax-planning strategies, and results of recent operations. Due to historical cumulative
losses over the prior three years as well as projected losses over the next year, we believe that it is not more likely than not that the
benefit from certain federal and state deferred tax assets will be realized. As such, we have recorded a full valuation allowance as of
December 31, 2024.
The remaining federal NOLs generated in pre-2018 years of $19.5 million can offset 100% of future years’ taxable income. The federal
NOLs generated in post 2017 years of $104.9 million can offset 80% of future years’ taxable income. The pre-2018 federal NOLs will
expire in varying amounts from 2035 to 2037 if they are not utilized. Indiana NOLs, which total $168.0 million, have a 20-year
carryforward period and will expire in the years 2034 to 2044 if they are not utilized.
We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as
well as all open tax years in these jurisdictions, to determine whether the positions will be more likely than not be sustained by the
applicable tax authority. Tax positions not deemed to meet the more-likely-than-not threshold are not recorded as a tax benefit or
expense in the current year. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We
believe that our income tax filing positions and deduction will be sustained on audit and do not anticipate any adjustments that will
result in a material change to its consolidated financial position. While not material, we record any penalties and interest as general and
administrative expense. Tax returns filed with the Internal Revenue Service and state entities generally remain subject to examination
for three years after filing.
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(8) STOCK COMPENSATION PLANS
Restricted Stock Units (RSUs)
The table below shows the number of RSUs available for issuance at December 31, 2024:
Total authorized RSUs in Plan approved by shareholders
4,850,000
Stock issued out of the Plan from vested grants
(3,761,430)
Non-vested grants
(1,034,486)
RSUs available for future issuance
54,084
Non-vested grants at December 31, 2022
1,056,937
Granted – weighted average share price on grant date was $9.30
312,147
Vested
(472,721)
Forfeited
(38,000)
Non-vested grants as of December 31, 2023
858,363
Awarded - weighted average share price on award date was $5.69
599,013
Vested
(380,390)
Forfeited
(42,500)
Non-vested grants as of December 31, 2024
1,034,486
RSU Vesting Schedule
Vesting Year
RSUs Vesting
2025
682,068
2026
176,210
2027
176,208
1,034,486
Shares vested in 2024 had a value of $2.0 million based on the share price of $5.33 on their vesting dates. Under our RSU plan,
participants are allowed to relinquish shares to pay for their required statutory income taxes.
The outstanding RSUs have a value of $8.9 million based on the March 10, 2025 closing stock price of $8.60.
For the years ended December 31, 2024 and 2023, stock-based compensation was $4.5 million and $3.6 million, respectively.
As of December 31, 2024, unrecognized stock compensation expense to be recognized over the remaining 3-year vesting period was
$2.7 million, and we had 54,084 RSUs available for future issuance. RSUs are not allocated earnings and losses as they are considered
non-participating securities. Forfeitures are recognized as they occur.
Stock Options
We have no stock options outstanding.
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85
(9) EMPLOYEE BENEFITS
Our employee benefit expenses for the years ended December 31st are below (in thousands):
2024
2023
Health benefits, including premiums
$
13,796
$
18,483
401(k) matching
1,851
2,910
Deferred bonus plan
553
687
Total
$
16,200
$
22,080
Of the amounts in the above table, $15.2 million and $21.5 million are recorded in “labor” in the consolidated statements of operations
for the years ended December 31, 2024 and 2023, respectively, with the remainder in general and administrative.
Our mine employees are also covered by workers’ compensation and such costs were approximately $4.0 million and $4.9 million for
2024 and 2023, respectively, and are recorded in “labor” in the consolidated statements of operations. Workers’ compensation is a no-
fault system by which individuals who sustain work-related injuries or occupational diseases are compensated. Benefits and coverage
are mandated by each state which includes disability ratings, medical claims, rehabilitation services, and death and survivor benefits.
We are partially self-insured for such claims, however, its operations are protected from these perils through stop-loss insurance
policies. Our maximum annual exposure is limited to $1.0 million per occurrence with a $4.0 million aggregate deductible.
(10) LEASES
We determine if an arrangement is an operating or finance lease at the inception of each contract. If the contract is classified as an
operating lease, we record a right-of-use (“ROU”) asset and corresponding liability reflecting the total remaining present value of fixed
lease payments over the expected term of the lease agreement. The expected term of the lease may include options to extend or
terminate the lease when it is reasonably certain that we will exercise that option. If our lease does not provide an implicit rate in the
contract, we use our incremental borrowing rate when calculating the present value.
We have operating leases for office space with remaining lease terms ranging from one month to approximately eight years. As most of
the leases do not provide an implicit rate, we calculate the ROU assets and lease liabilities using our secured incremental borrowing rate
at the lease commencement date. Imputed interest on our operating leases was $0.3 million as of December 31, 2024. At
December 31, 2024 and 2023, respectively, we had approximately $0.7 million of ROU operating lease assets recorded within buildings
and equipment on the consolidated balance sheets. Operating lease expense associated with ROU assets is recognized on
a monthly basis over the lease term in operating costs on the consolidated statements of operation.
We entered into three finance leases during 2023 and five finance leases during 2024, which are accounted for as failed sale-leaseback
transactions. Finance lease assets are included in finance lease right-of-use assets on the consolidated balance sheets and the associated
finance lease liabilities are reflected within current portion of lease financing and long-term lease financing on the consolidated balance
sheets as applicable. Depreciation on our finance lease assets was $5.2 million and $2.3 million for the years ended December 31, 2024
and 2023, respectively. Interest expense on our finance lease liability was $1.5 million during the year ended December 31, 2024.
Imputed interest expense on our future remaining finance lease liability was $1.7 million for the year ended December 31, 2024. We
had deferred financing fees of $0.2 million and $0.1 million at December 31, 2024 and 2023, respectively, in connection with entry into
the finance leases. These deferred financing fees will be amortized on a straight-line basis over the term of the finance leases.
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Information related to leases was as follows as of December 31st (in thousands):
December 31,
2024
2023
Operating lease information:
Operating cash outflows from operating leases
$
169
$
208
Weighted average remaining lease term in years
8.0
8.5
Weighted average discount rate
9.5 %
9.5 %
Finance lease information:
Financing cash outflows from finance leases
$
5,633
$
—
Proceeds from sale and leaseback arrangement
5,134
11,082
Weighted average remaining lease term in years
2.18
3.00
Weighted average discount rate
9.0 %
8.5 %
We recognized the following costs related to our leases in our consolidated balance sheets:
For the Year
Ended
December 31,
For the Year
Ended
December 31,
2024
2023
(In thousands)
Operating lease assets
Buildings and equipment
$
664
$
712
Operating lease liabilities:
Current operating lease liabilities
Accounts payable and accrued liabilities
$
99
$
58
Non-current operating lease liabilities
Other long-term liabilities
565
654
Total operating lease liability
$
664
$
712
Finance lease assets
Finance lease right-of-use assets
$
13,034
$
12,346
Finance lease liabilities:
Current finance lease liabilities
Current portion of lease financing
$
6,912
$
3,933
Non-current finance lease liabilities
Long-term lease financing
8,749
8,157
Total finance lease liabilities
$
15,661
$
12,090
Future minimum lease payments under non-cancellable leases as of December 31, 2024, were as follows:
Operating Leases
Finance Leases
(In thousands)
2025
$
108
$
8,147
2026
121
7,972
2027
125
1,391
2028
129
—
2029
133
—
Thereafter
361
—
Total minimum lease payments
$
977
$
17,510
Less imputed interest and deferred finance fees
(313)
(1,849)
Total lease liability
$
664
$
15,661
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(11) SELF INSURANCE
We self-insure non-leased underground mining equipment. Such equipment is allocated among four mining units dispersed over
seven miles and seven mining units dispersed over eleven miles, at December 31, 2024 and 2023, respectively. The historical cost of
such equipment was approximately $227.8 million and $262.0 million as of December 31, 2024 and 2023, respectively.
We also self-insure for workers’ compensation claims under a guaranteed cost program. Under this program, we are responsible for the
first $1.0 million per claim up to an aggregate of $4.0 million annually. Restricted cash of $3.4 million and $3.8 million as of
December 31, 2024 and 2023, respectively, represents cash held and controlled by a third party and is restricted for future workers’
compensation claim payments. The Company had $4.3 million and $3.6 million of workers’ compensation reserve as of December 31,
2024 and 2023, respectively in “Accounts payable and accrued liabilities” on the Consolidated Balance Sheets.
(12) NET INCOME (LOSS) PER SHARE
The following table (in thousands, except per share amounts) sets forth the computation of basic earnings per share for the periods
presented:
Year Ended December 31,
2024
2023
Basic earnings per common share:
Net income (loss) - basic
$
(226,138)
$
44,793
Weighted average shares outstanding - basic
39,504
33,133
Basic earnings (loss) per common share
$
(5.72)
$
1.35
The following table (in thousands, except per share amounts) sets forth the computation of diluted net income (loss) per share:
Year Ended December 31,
2024
2023
Diluted earnings per common share:
Net income (loss) - basic
$
(226,138)
$
44,793
Add: Convertible Notes interest expense, net of tax
—
1,201
Net income (loss) - diluted
$
(226,138)
$
45,994
Weighted average shares outstanding - basic
39,504
33,133
Add: Dilutive effects of if converted Convertible Notes
—
3,164
Add: Dilutive effects of Restricted Stock Units
—
530
Weighted average shares outstanding - diluted
39,504
36,827
Diluted net income (loss) per share
$
(5.72)
$
1.25
(13) FAIR VALUE MEASUREMENTS
We account for certain assets and liabilities at fair value. The hierarchy below lists three levels of fair value based on the extent to
which inputs used in measuring fair value are observable in the market. We categorize each of our fair value measurements in one of
these three levels based on the lowest level input that is significant to the fair value measurement in its entirety. These levels are:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or
liabilities. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and
volume to provide pricing information on an ongoing basis. We have no Level 1 instruments.
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Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full
term of the asset or liability. See asset impairment discussion below in Nonrecurring Fair Value Measurements sections below.
Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and
less observable from objective sources (i.e., supported by little or no market activity). ARO liabilities use Level 3 non-recurring fair
value measures as further discussed in “Note 1 – Summary of Significant Accounting Policies”.
Nonrecurring Fair Value Measurements
During the fourth quarter of 2024, the Company completed its review of the coal mining facilities and future mining plans. The
impairment analysis was based upon the coal mining operating plans of the Company, market driven pricing and cost trends. As part of
that analysis, the Company determined the carrying amount of its coal mining long-lived asset group was not recoverable and recorded
a non-cash, long-lived asset impairment charge of $215.1 million in 2024.
The discounted cash flow model was calculated using projected economics for the Coal Operations assets, using the Company’s mining
plan and reserve estimates to be mined and sold at prevailing commodity prices, operating expenses, and production cost levels, which
are classified as Level 3 inputs.
(14) EQUITY METHOD INVESTMENTS
We own a 50% interest in Sunrise Energy, which owns gas reserves and gathering equipment with plans to develop and operate such
reserves. Sunrise Energy also plans to develop and explore for oil, natural gas, and coal-bed methane gas reserves on or near our
underground coal reserves. The carrying value of the investment included in the consolidated balance sheets as of
December 31, 2024 and 2023 was $2.1 million and $2.8 million, respectively.
The Company also owns a 50% interest in Oaktown Gas, LLC. Oaktown Gas, LLC operates an emission abatement project through the
destruction of gases extracted from the Oaktown mines to generate carbon credits and other emissions offset credits. The carrying value
of the investment included in the consolidated balance sheets as of December 31, 2024 was $0.5 million.
(15) CONVERTIBLE NOTES
On July 29, 2022, we issued a $5.0 million senior unsecured convertible note (the “July 29th Note”) to a related party affiliated with an
independent member of our board of directors. The July 29th Note carried an interest rate of 8% per annum with a maturity date of
December 29, 2028. For the period August 18, 2022, through August 17, 2024, the holder had the option to convert the
July 29th Note into shares of the Company’s common stock at a conversion price of $6.254. During the first quarter of 2024, the holders
of the July 29th Note converted them into 799,488 shares of common stock of the Company, and in connection with such early
conversion, we elected to pay interest through August 2025 with 112,570 shares of common stock on the conversion date. We recorded
inducement expense which is reported in loss on extinguishment of debt in the condensed consolidated statements of operations in the
amount of $0.6 million during the three months ended March 31, 2024. As of December 31, 2024, the entire July 29th Note had been
converted to shares of common stock of the Company.
On August 8, 2022, we issued an additional $4.0 million of senior unsecured convertible notes (the “August 8th Notes”) to related
parties affiliated with independent members of our board of directors. The August 8th Notes carried an interest rate of 8% per annum
with a maturity date of December 29, 2028. For the period August 18, 2022, through August 17, 2024, the holder had the option to
convert the Notes into shares of the Company’s common stock at a conversion price of $6.254. Beginning August 8, 2025, we could
elect to redeem the August 8th Notes and the holder was obligated to surrender them at 100% of the outstanding principal balance
together with any accrued unpaid interest. Upon receipt of the redemption notice from the Company, the holder could have elected to
convert the principal balance and accrued interest into the Company’s common stock. During the first quarter of 2024, the holders
converted $3.0 million of the August 8th Notes into 479,693 shares of common stock of the Company, and in connection with such early
conversion, we elected to pay interest through August 2025 with 67,542 shares of common stock on the conversion date. During the
same period, the holders also converted accrued interest into 57,564 shares of the Company’s common stock.
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We recorded inducement expense which is reported in loss on extinguishment of debt during the first quarter of 2024 in the condensed
consolidated statements of operations in the amount of $0.3 million. During the second quarter of 2024, the holder converted
the remaining $1.0 million of August 8th Notes into 159,898 shares of common stock of the Company, and in connection with such
early conversion, we paid accrued interest and additional shares of common stock of 5,099 and 25,003, respectively, on the conversion
date. We recorded inducement expense which is reported in loss on extinguishment of debt during the second quarter of 2024 in the
condensed consolidated statements of operations in the amount of $0.2 million. As of December 31, 2024, the entire
August 8th Note had been converted to shares of common stock of the Company.
On August 12, 2022, we issued an additional $10.0 million senior unsecured convertible note (the “August 12th Note”) to an unrelated
party. The August 12th Note carried an interest rate of 8% per annum with a maturity date of December 31, 2026. For the period
August 18, 2022, through the maturity date, the holder had the option to convert the August 12th Note into shares of the Company’s
common stock at a conversion price of $6.15. Beginning August 12, 2025, we could elect to redeem the August 12th Note and the holder
would have been obligated to surrender at 100% of the outstanding principal balance together with any accrued unpaid interest. Upon
receipt of the redemption notice from the Company, the holder could elect to convert the principal balance and accrued interest into the
Company’s common stock. During the three months ended March 31, 2024, the holder converted accrued interest into 65,041 shares of
the Company’s common stock. During the second quarter of 2024, the holder converted the $10.0 million
August 12th Note into 1,626,016 shares of common stock of the Company, and in connection with such early conversion, we paid
accrued interest and additional shares of common stock of 49,716 and 224,268, respectively, on the conversion date. We recorded
inducement expense which is reported in loss on extinguishment of debt in the condensed consolidated statements of operations in the
amount of $1.7 million during the second quarter of 2024. As of December 31, 2024, the entire August 12th Note had been converted to
shares of common stock of the Company.
The funds received from the issuance of the various notes described above were used to provide additional working capital to the
Company. The conversion price and number of shares of our common stock issuable upon conversion of the above notes are subject to
adjustment from time to time for any subdivision or consolidation of our shares of common stock and other standard dilutive events.
(16) NOTES PAYABLE – RELATED PARTIES
In March 2024, we issued unsecured promissory notes, having a 12-month maturity date and 12% per annum interest rate, to (i) Charles
R. Wesley IV Revocable Trust (in which our director Charles R. Wesley IV has a pecuniary interest) in the principal amount of
$2,000,000, (ii) Lubar Opportunities Fund I, LLC (in which are our director David J. Lubar has a pecuniary interest) in the principal
amount of $2,500,000, and (iii) Hallador Alternative Investment Advisors LLC (in which our director David C. Hardie has a pecuniary
interest) in the principal amount of $500,000. The related party notes were paid off in June 2024 with proceeds from the prepaid
physically delivered power contract mentioned above in “Note 6 – Revenue”.
(17) ORGANIZATIONAL RESTRUCTURING
On February 23, 2024, (the “Effective Date”), we committed to a reorganization effort in the Coal Operations Segment (the
“Reorganization Plan”) that included a workforce reduction of approximately 110 employees, or approximately 12% of the workforce.
The reduction in workforce was communicated to employees on the Effective Date and implemented immediately, subject to certain
administrative procedures. The Reorganization Plan is designed to strengthen our financial and operational efficiency and create
significant operational savings and higher margins in our coal segment. This step will help to advance our transition from a company
primarily focused on coal production to a more resilient and diversified integrated independent power producer (“IPP”). As part of this
initiative, we substantially idled production at our higher cost surface mines, Prosperity Mine, and Freelandville Mine, with minimal
ongoing production. We also focused our seven units of underground equipment on four units of our lowest cost production at our
Oaktown Mine. In connection with the Reorganization Plan, we incurred aggregate expenses of $1.9 million ($1.1 million in the first
quarter of 2024 and $0.8 million in the second quarter of 2024) that were included in “Labor” in the consolidated statements of
operations. These charges related to compensation, tax, professional, and insurance related expenses and are considered one-time
charges paid during 2024. The coal mining properties asset group was
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tested for impairment as result of the organizational restructuring passing the undiscounted recoverability test. See “Note 19 –
Impairment of Coal Properties” for additional changes to the Company’s mining plans that occurred during the fourth quarter of 2024.
(18) AT MARKET AGREEMENT
On December 18, 2023, we entered into an At Market Issuance Sales Agreement (the “Sales Agreement”) with B. Riley Securities, Inc.
(the “Agent”), pursuant to which we may issue and sell, from time to time, shares (the “Shares”) of our common stock, par value $0.01
per share (the “Common Stock”), with aggregate gross proceeds of up to $50.0 million through an “at-the-market” equity offering
program under which the Agent will act as sales agent (the “ATM Program”). Under the Sales Agreement, we or the Agent have the
right, by giving five (5) days’ notice, to terminate the Sales Agreement in our and the Agents sole discretion. The Agent may also
terminate the Agreement, by notice to us, upon the occurrence of certain events described in the Sales Agreement.
During December 2023, we issued 794,000 shares of Common Stock under the ATM Program for net proceeds of $7.3 million. During
the year ended December 31, 2024, we issued 4,654,430 shares of Common Stock under the ATM Program for net proceeds of $34.5
million.
(19) IMPAIRMENT OF COAL PROPERTIES
Annually, the Company reviews its business plans for the next several years, with specific emphasis on the upcoming year. This
business plan review involves updates to its mining plans that take into account many factors, such as changes in market price trends,
cost trends, expected demand trends, its latest engineering studies and current year operational and financial results. During the fourth
quarter of 2024, the Company began its annual business plan review. The Company evaluated core hole samples at several of its mines,
reviewing the quality of the mine seam and density of the coal. Based upon market price trends, the Company believes the required
course of action is to only produce those reserves that will allow it the lowest possible cost, and therefore capture the highest possible
margins. The core hole samples at the Oaktown 2 mine were of a lower quality and density than that of the Oaktown 1 mine. As such, at
the conclusion of the Company’s annual business plan review during the fourth quarter of 2024, it decided to temporarily seal the
Oaktown 2 mine, and to focus coal production at the Oaktown 1 mine, which has lower recovery costs.
As a result of the Company’s decision to temporarily seal the Oaktown 2 mine, the Company determined a triggering event had
occurred. The Company then completed an impairment review to determine if the carrying value of its coal properties were impaired.
The Company compared the net book value of its coal properties to estimated undiscounted future net cash flows. The result of this
undiscounted cash flow test indicated the carrying amount of its coal properties may not be recoverable. As a result, the Company
prepared a discounted cash flow model (Level 3 fair value measurement under the fair value hierarchy) to estimate fair value.
Significant inputs used to determine fair value include estimates of future cash flows from coal sales and minimum payments, an
appropriate discount rate and the useful economic life. The estimated cash flows are the product of a process that began with current
realized pricing as of the measurement date and included an adjustment for risk related to the realization of such future cash flows.
The discounted cash flow model used assumptions regarding the projected economics of the Coal Operations assets, given prevailing
commodity prices and operating expense levels, which are classified as Level 3 inputs. Coal Operations assets include all of our coal
mining properties as these properties are all within the same asset group given the near proximity to one another and their sharing of
personnel and assets used to fulfill customer contracts. The Company utilized an estimated market participant discount rate of 11.5%
and assumed production that is consistent with our current mining plans and reserve estimates that equate to approximately 3.6 million
tons per year until all reserves are produced as part of the analysis.
The result of the discounted cash flow analysis confirmed that fourth quarter of 2024 changes to the mining plans caused the carrying
amount of its coal properties to not be recoverable. As a result, the Company recorded an impairment expense during the fourth quarter
of 2024 of $215.1 million. The Company did not record an impairment during the year ended December 31, 2023.
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91
(20) SEGMENTS OF BUSINESS
Our business is organized based on the services and products we provide in two segments: (i) Electric Operations and (ii) Coal
Operations. The Chief Operating Decision Maker (“CODM”), who is the Company’s Chief Executive Officer, reviews and assesses
operating performance measures related to our Electric Operations and our Coal Operations segments.
Our Electric Operations segment includes the electric power generation facilities of our Merom power plant, which is a two unit, 1080-
megawatt rated coal fired power plant located in Sullivan County, Indiana. Our sales region is in MISO Zone 6, which includes Indiana
and a portion of western Kentucky. Revenues from our Electric Operations segment consist primarily of delivered energy and capacity
revenues. Fuel costs included in our Electric Operations segment include the cost of coal purchased from our Coal Operations segment,
which are based on multi-year contracts which approximate market prices at the time the contracts are entered into.
Our Coal Operations segment includes the Oaktown 1 and 2 underground mining complexes, as well as other currently idled mining
facilities, which produce high-quality bituminous coal from the Illinois Basin. Revenues from our Coal Operations segment consist of
sales of coal to various third-parties and to Merom. Coal sales to our Electric Operations are based on multi-year contracts which
approximate market prices at the time the contracts are entered into. Intercompany coal sales and amounts above actual costs to produce
the coal are eliminated in the consolidated statements of operations.
In addition to these reportable segments, the Company has a “Corporate and Other and Eliminations” category, which is not significant
enough, on a stand-alone basis, to be considered an operating segment. Corporate and Other and Eliminations primarily consist of
unallocated corporate costs and activities, including our equity method investments.
The CODM evaluates segment performance based upon EBITDA margin for each business segment. EBITDA margin is calculated for
each segment as follows:
1.
For our Electric Operations segment, EBITDA margin is comprised of delivered energy revenues less certain significant
segment expenses, which include (i) variable costs, (ii) other operating and maintenance costs, (iii) costs of purchased power,
(iv) utilities, (v) labor and (vi) general and administrative costs. Variable operating costs are comprised of fuel costs and
certain other operating costs, such as limestone and soda ash.
2.
For our Coal Operations segment, EBITDA margin is comprised of coal sales less certain significant segment expenses, which
include (i) fuel, (ii) other operating and maintenance costs, (iii) utilities, (iv) labor and (v) general and administrative costs.
EBITDA margin for each segment is a key measure used by our CODM and provides information about our core operating
performance, significant expenses and ability to generate cash flow. Additionally, EBITDA margin provides investors with the financial
analytical framework upon which our CODM bases financial, operational, compensation and planning decisions and presents a
measurement that investors, rating agencies and debt holders have indicated is useful in assessing us and our results of operations. Our
CODM reviews variable costs, as defined above, in our Electric Operations segment in order to evaluate the efficiency of that segments
operations.
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Presented below are the Electric and Coal Operations key metrics reviewed by the CODM at December 31, 2024 (in thousands):
Electric Operations
Coal Operations
Delivered Energy
$
203,434 Coal Sales
$
202,525
Capacity Revenue
58,093
Electric Sales
$
261,527
Fuel
$
(111,768)
Other Operating Costs (1)
(19)
Total Variable Costs
$
(111,787)
Other Operating and Maintenance Costs (2)
$
(28,622)
Fuel
$
(2,851)
Cost of Purchased Power
(10,888)
Other Operating and Maintenance Costs
(89,283)
Utilities
(2,070)
Utilities
(13,844)
Labor
(30,842)
Labor
(85,322)
Power Margin Without General and Administrative
77,318
Coal Margin Without General and
Administrative
11,225
General and Administrative
(5,311)
General and Administrative
(9,877)
Electric Operations — EBITDA Margin
$
72,007
Coal Operations — EBITDA Margin
$
1,348
(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as
discussed above in (1).
Presented below are the Electric and Coal Operations key metrics reviewed by the CODM at December 31, 2023 (in thousands):
Electric Operations
Coal Operations
Delivered Energy
$
211,772 Coal Sales
$
432,888
Capacity Revenue
56,155
Electric Sales
$
267,927
Fuel
$
(139,496)
Other Operating Costs (1)
(32)
Total Variable Costs
$
(139,528)
Other Operating and Maintenance Costs (2)
$
(33,777)
Fuel
$
(7,089)
Cost of Purchased Power
—
Other Operating and Maintenance Costs
(165,479)
Utilities
(429)
Utilities
(17,301)
Labor
(31,245)
Labor
(121,172)
Power Margin Without General and Administrative
62,948
Coal Margin Without General and
Administrative
121,847
General and Administrative
(4,914)
General and Administrative
(10,287)
Electric Operations — EBITDA Margin
$
58,034
Coal Operations — EBITDA Margin
$
111,560
(1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.
(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as
discussed above in (1).
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93
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues at December 31, 2024
(in thousands):
Corporate and Other
Reconciliation of Revenue:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Delivered Energy
$
203,434 $
— $
— $
203,434
Capacity Revenue
58,093
—
—
58,093
Other Operating Revenue
982
2,756
1,681
5,419
Coal Sales (Third-Party)
—
137,448
—
137,448
Coal Sales (Intercompany)
—
65,077
(65,077)
—
Operating Revenues
$
262,509
$
205,281
$
(63,396)
$
404,394
Presented below are the Electric and Coal Operations revenues reconciled to our consolidated operating revenues at December 31, 2023
(in thousands):
Corporate and Other
Reconciliation of Revenue:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Delivered Energy
$
211,772 $
— $
— $
211,772
Capacity Revenue
56,155
—
—
56,155
Other Operating Revenue
414
2,936
1,675
5,025
Coal Sales (Third-Party)
—
361,926
—
361,926
Coal Sales (Intercompany)
—
70,962
(70,962)
—
Operating Revenues
$
268,341
$
435,824
$
(69,287)
$
634,878
Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at
December 31, 2024 (in thousands):
Corporate and Other
Reconciliation of Income (Loss) before Income Taxes:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Electric Operations — EBITDA Margin
$
72,007 $
—
$
65,276 $
137,283
Coal Operations — EBITDA Margin
—
1,348
(65,077)
(63,729)
Other Operating Revenue
982
2,756
1,681
5,419
Depreciation, Depletion and Amortization
(19,290)
(46,245)
(91)
(65,626)
Asset Impairment
—
(215,136)
—
(215,136)
Asset Retirement Obligations Accretion
(457)
(1,171)
—
(1,628)
Exploration Costs
—
(260)
—
(260)
Gain (loss) on disposal or abandonment of assets, net
—
(1,629)
1,679
50
Interest Expense
(1,875)
(11,033)
(942)
(13,850)
Loss on Extinguishment of Debt
—
—
(2,790)
(2,790)
Equity Method Investment (Loss)
—
—
(746)
(746)
Settlement of litigation
—
(2,750)
—
(2,750)
Corporate — General and Administrative
—
—
(11,339)
(11,339)
Corporate — Other Operating and Maintenance Costs
—
—
(440)
(440)
Income (Loss) before Income Taxes
$
51,367
$
(274,120)
$
(12,789)
$
(235,542)
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Presented below is our reconciliation of EBITDA Margin to the most comparable GAAP account, income (loss) before income taxes at
December 31, 2023 (in thousands):
Corporate and Other
Reconciliation of Income (Loss) before Income Taxes:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Electric Operations — EBITDA Margin
$
58,034 $
—
$
69,778 $
127,812
Coal Operations — EBITDA Margin
—
111,560
(70,961)
40,599
Other Operating Revenue
414
2,936
1,675
5,025
Amortization of Contract Asset
(26,581)
—
—
(26,581)
Depreciation, Depletion and Amortization
(18,739)
(48,365)
(107)
(67,211)
Asset Retirement Obligations Accretion
(576)
(1,228)
—
(1,804)
Exploration Costs
—
(904)
—
(904)
Gain (loss) on disposal or abandonment of assets, net
—
(398)
—
(398)
Interest Expense
(322)
(11,869)
(1,520)
(13,711)
Loss on Extinguishment of Debt
(1,491)
—
(1,491)
Equity Method Investment (Loss)
—
—
(552)
(552)
Corporate — General and Administrative
—
—
(10,958)
(10,958)
Corporate — Other Operating and Maintenance Costs
—
—
(568)
(568)
Income (Loss) before Income Taxes
$
12,230
$
50,241
$
(13,213)
$
49,258
Presented below are our Electric and Coal Operations assets and capital expenditures at December 31, 2024 (in thousands):
Corporate and Other
Other Reconciliations:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Assets
$
220,477 $
144,519 $
4,124 $
369,120
Capital Expenditures
$
18,699
$
34,081
$
587
$
53,367
Presented below are our Electric and Coal Operations assets and capital expenditures at December 31, 2023 (in thousands):
Corporate and Other
Other Reconciliations:
Electric Operations
Coal Operations
and Eliminations
Consolidated
Assets
$
208,331 $
376,387 $
5,062 $
589,780
Capital Expenditures
$
18,831
$
56,521
$
—
$
75,352
(21) ASSETS HELD FOR SALE
During the third quarter of 2024, the Company considered strategic alternatives with respect to its wholly-owned subsidiary Summit.
Summit primarily held property, plant and equipment. On July 29, 2024, the Company entered into a ninety day right of first refusal
(“ROFR”) with a potential buyer of Summit for $3.2 million. As of July 29, 2024, Summit met the held-for-sale criteria, and its assets
were included in "assets held-for-sale" in the current assets section of the consolidated balance sheets. The Company recorded the
Summit assets, once held for sale, at the lower of their carrying value or their estimated fair value less cost to sell. The Company also
did not record depreciation and amortization of $0.1 million ($0.1 million after-tax) on assets held-for-sale and continued to do so while
held-for-sale criteria was met.
Fair value is the amount at which an asset, liability or business could be bought or sold in a current transaction between willing parties
and may be estimated using a number of techniques or may be observable using quoted market prices. The Company used a market
approach consisting of the contractual ROFR sales price, subject to prorations for property taxes and utilities, to determine the fair
value, and subtracted estimated costs to sell from that calculated fair value.
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The sale of Summit did not represent a strategic shift that has or will have a major effect on the Company, and as such, did not qualify
for treatment as a discontinued operation.
The Company sold Summit on December 23, 2024 for $3.2 million. The Company recorded a $1.7 million gain in “(Gain) loss on
disposal or abandonment of assets, net” in its consolidated statements of operations.
(22) CONTINGENCIES
Our Coal Operations subsidiary is party to litigation in which the plaintiffs allege violations of the Fair Labor Standards Act and state
law due to alleged failure to compensate for time "donning" and "doffing" equipment and to account for certain bonuses in the
calculation of overtime rates and pay. In January 2025, we agreed to settle with the plaintiffs such litigation for $2.8 million, which is
recorded in “accounts payable and accrued liabilities” on our consolidated balance sheets at December 31, 2024.
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96
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE.
None.
ITEM 9A. CONTROLS AND PROCEDURES.
Disclosure Controls
We maintain a system of disclosure controls and procedures that are designed for the purposes of ensuring that information required to
be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s
rules and forms, and that such information is accumulated and communicated to our CEO and CFO as appropriate to allow timely
decisions regarding required disclosure.
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our
CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation,
our CEO and CFO concluded that our disclosure controls and procedures are effective for the purposes discussed above.
Management’s Annual Report on Internal Control over Financial Reporting (ICFR)
Our management, including our CEO and CFO, is responsible for establishing and maintaining adequate ICFR. Our ICFR is a process
designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in
accordance with generally accepted accounting principles in the United States. Because of its inherent limitations, ICFR may not
prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of
achieving their control objectives. Management evaluated the effectiveness of our ICFR based on the framework in “Internal Control-
Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in 2013.
Our management evaluated, with the participation of our CEO and CFO, the effectiveness of our ICFR as of December 31, 2024. Based
on that evaluation, our management concluded that our ICFR was effective at December 31, 2024.
Grant Thornton LLP, an independent registered public accounting firm, has made an independent assessment of the effectiveness of our
internal control over financial reporting as of December 31, 2024, as stated in their report that is included herein.
There were no significant changes in our internal control over financial reporting that occurred during the quarter ended December 31,
2024, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
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97
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Hallador Energy Company
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Hallador Energy Company (a Colorado corporation) and subsidiaries (the
“Company”) as of December 31, 2024, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in the 2013 Internal Control
—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the
consolidated financial statements of the Company as of and for the year ended December 31, 2024, and our report dated March 17, 2025
expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over
Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial
reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to
the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit
included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of
records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally
accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or
that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
March 17, 2025
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98
ITEM 9B. OTHER INFORMATION
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.
None.
PART III
Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 14 of Part III of this
Report is incorporated by reference from our definitive proxy statement, which is to be filed pursuant to Regulation 14A within
120 days after the end of our fiscal year ended December 31, 2024.
The Company has adopted a Code of Ethics for Senior Officers that applies to its chief executive officer, chief
financial officer, and other financial executives. A copy of the Company’s Code of Ethics for Senior Officers is
filed as Exhibit 14.1 to this Annual Report on Form 10-K.
The Company’s Insider Trading Policy governing, among other things, the purchase, sale, and/or other
disposition of its securities by directors, officers and employees of the Company is reasonably designed to
promote compliance with insider trading laws, rules and regulations, and Nasdaq listing standards. This policy is
included as Exhibit 19.1 to this Annual Report on Form 10-K.
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99
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
See Item 8 for an index of our financial statements.
Our exhibit index is as follows:
1.1
At Market Issuance Sales Agreement, dated December 18, 2023, between Hallador Energy Company and B. Riley
Securities, Inc. (4)
3.1
Second Restated Articles of Incorporation of Hallador Energy Company effective December 24, 2009 (1)
3.2
By-laws of Hallador Energy Company, effective December 24, 2009 (2)
4.1
Description of Securities (3)
10.1
Fourth Amended and Restated Loan Agreement dated August 2, 2023 (5)
10.2
First Amendment to Fourth Amended and Restated Loan Agreement dated as of September 27, 2024 (6)
10.3
Second Amendment to Fourth Amended and Restated Loan Agreement dated as of October 23, 2024 (7)
10.4
Amended and Restated Hallador Energy Company 2008 Restricted Stock Unit Plan (8)
10.5
Form of Hallador Energy Company Restricted Stock Unit Issuance Agreement (8)
10.6
2022 Executive Officer Compensation Plan++(9)
10.7
2024 Executive Officer Compensation Plan * ++
10.8
Asset and Purchase Agreement dated February 14, 2022 (10)
14.1
Code of Ethics for Senior Executive Officers*
19.1
Insider Trading Policy *
21.1
List of Subsidiaries*
23.1
Consent of Grant Thornton LLP*
23.2
Consent of John T. Boyd Company*
31.1
SOX 302 Certification - President and CEO*
31.2
SOX 302 Certifications - CFO*
32.1
SOX 906 Certification*
95.1
Mine Safety Disclosure*
96.1
Technical Report Summary (Coal Resources and Coal Reserves, Oaktown Mining Complex), dated March 2025*
101.INS
Inline XBRL Instance Document*
101.SCH
Inline XBRL Schema Document*
101.CAL
Inline XBRL Calculation Linkbase Document*
101.LAB
Inline XBRL Labels Linkbase Document*
101.PRE
Inline XBRL Presentation Linkbase Document*
101.DEF
Inline XBRL Definition Linkbase Document*
104*
Cover Page Interactive Data File (embedded within the Inline XBRL and contained in Exhibit 101)
(1)
IBR to Form 8-K dated December 31, 2009
(2)
IBR to Form 10-K/A amendment 1, filed June 12, 2020
(3)
IBR to Form 10-K filed March 9, 2020
(4)
IBR to Form 8-K filed December 18, 2023
(5)
IBR to Form 10-Q filed on August 7, 2023
(6)
IBR to Form 8-K filed on October 3, 2024
(7)
IBR to Form 10-Q filed on November 11, 2024
(8)
IBR to Form DEF 14A dated April 12, 2017
(9)
IRB to Form 10-Q filed November 14, 2022
(10)
IBR to Form 8-K/A filed March 11, 2022
(11)
IBR to Form 10-K filed March 14, 2024
*
Filed herewith.
++ Management Agreements
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100
ITEM 16. FORM 10-K SUMMARY.
As this item is optional, no summary is presented.
Table of Contents
101
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized.
HALLADOR ENERGY COMPANY
Date: March 17, 2025
/s/MARJORIE HARGRAVE
Marjorie Hargrave, CFO (Principal Financial Officer and Principal
Accounting Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates indicated.
/s/DAVID HARDIE
David Hardie
Director
March 17, 2025
/s/BRYAN LAWRENCE
Bryan Lawrence
Director
March 17, 2025
/s/BRENT BILSLAND
Brent Bilsland
Board Chairman, President and CEO
March 17, 2025
/s/DAVID J. LUBAR
David J. Lubar
Director
March 17, 2025
/s/ZARRELL GRAY
Zarrell Gray
Director
March 17, 2025
/s/CHARLES WESLEY, IV
Charles Wesley, IV
Director
March 17, 2025
Exhibit 10.7
HALLADOR ENERGY COMPANY
2024 EXECUTIVE OFFICER PLAN
The following definitions shall apply for purposes of this Hallador Energy
Company 2024 Executive Officer Plan (this “2024 EO Plan”):
“Cause” means, as determined in the Board’s discretion:
(v)
The Covered Person’s willful and continued material failure to perform the
reasonable duties and responsibilities of his or her position after the Corporation has
provided the Covered Person with a written demand for performance that describes the basis
for the Corporation’s belief that the Covered Person has not substantially performed his or
her duties and the Covered Person has not corrected the failure within thirty (30) days of the
written demand;
(vi)
Any act of personal dishonesty taken by the Covered Person in connection
with his or her responsibilities as an employee of the Corporation or its subsidiary and
intended to result in his or her substantial personal enrichment;
(vii)
The Covered Person’s conviction of, or plea of nolo contendere to, a felony
that the Board reasonably believes has had or will have a material detrimental effect on the
Corporation’s reputation or business; or
(viii)
The Covered Person’s breach of any fiduciary duty owed to the
Corporation or a subsidiary of the Corporation by the Covered Person that has a material
detrimental effect on the Corporation’s or such subsidiary’s reputation or business.
“Change of Control” means the first to occur, following the Effective Date, of the
following events:
(iii)
the acquisition by any person or group of related persons (as determined
pursuant to section 13(d)(3) of the Securities Exchange Act of 1934) of beneficial ownership
of securities of the Corporation representing fifty percent (50%) or more of the total number
of votes that may be cast for the election of Board members; or
(iv)
stockholder approval of (A) any agreement for a merger or consolidation in
which the Corporation will not survive as an independent corporation or other entity, or (B)
any sale, exchange or other disposition of all or substantially all of the Corporation’s assets,
including, without limitation, the sale, exchange or other disposition of the equity securities
or assets of Sunrise Coal, LLC or of Hallador Power Company, LLC.
Definitions
1
Definitions
Definitions
2
Notwithstanding anything herein to the contrary, with respect to any amounts that
constitute nonqualified deferred compensation under Code Section 409A and that would
be payable in connection with a Change of Control, to the extent required to avoid
accelerated or additional taxation under such section, no Change of Control will be
deemed to have occurred unless such Change of Control also constitutes a change in the
ownership or effective control of the Corporation or a change in the ownership of a
substantial portion of the Corporation’s assets within the meaning of Code Section
409A(a)(2)(A)(v).
“Closing” means the closing date of a transaction that results in a Change of
Control, as set forth in the definitive agreement governing such transaction.
“Code” means the Internal Revenue Code of 1986, as amended.
“Covered Person” means each of the Corporation’s (i) Chief Executive Officer
(also currently serving as the President, Corporate Secretary and Chairman of the Board
of the Corporation), (ii) the Chief Financial Officer of the Corporation, and (iii) the
President of Hallador Power Company, LLC, a wholly-owned subsidiary of the
Corporation.
“Effective Date” means April 1, 2024, the effective date of this 2024 EO Plan.
“Good Reason” with respect to a Covered Person, means the occurrence of one or
more of the following without the Covered Person’s written consent:
(iv)
A fifteen percent (15%) or more reduction in the Covered Person’s total
annual cash compensation opportunity (base salary and target bonus opportunity
collectively), as compared to the Covered Person’s total annual cash compensation
opportunity immediately prior to the reduction in compensation;
(v)
A change in the Covered Person’s principal work location resulting in a new
one-way commute that is more than fifty (50) miles greater than the Covered Person’s one-
way commute prior to the change in the Covered Person’s principal work location without
allowing alternate accommodation (such as remote work), regardless of whether the
Covered Person receives an offer of relocation benefits; or
(vi)
(A) A material reduction in the Covered Person’s authority, duties and/or
responsibilities, or (B) in connection with a proposed Change of Control, a proposed
material reduction in the Covered Person’s authority, duties and/or responsibility by the
acquiring company as compared to the Executive’s authority, duties and/or responsibilities
in effect immediately prior to the Closing (for example, but not by way of limitation, this
determination will
3
include an analysis of whether the Covered Person will maintain at least the same
level, scope and type of duties and responsibilities with respect to the management, strategy,
operations and business of the combined entity resulting from such transaction, taking the
Corporation, any acquirer and their respective parent corporations, subsidiaries and other
affiliates, together as a whole).
With respect to any termination for Good Reason, the Covered Person shall give
the Corporation written notice, which shall identify with reasonable specificity the
grounds for the Covered Person’s resignation, and provide the Corporation a period of
thirty (30) days from the day such notice is given to cure the alleged grounds for
termination for Good Reason contained in the notice. A termination will not be for Good
Reason if such notice is given by the Covered Person to the Corporation more than ninety
(90) days after the occurrence of the event that the Covered Person alleges is Good
Reason for her or her termination.
Any event or condition shall cease to constitute “Good Reason” if the
Corporation cures the event or condition within the thirty (30) day cure period, or, if the
Corporation fails to cure the event or condition within such thirty (30) day period, the
Covered Person fails to terminate employment within ninety (90) days following the
expiration of the thirty (30) day cure period.
“Payment Date” means the date on which the Corporation pays the Retention
Bonus to the Covered Persons, which shall be on the date of the Closing.
“Release” means a general release, in the form provided by the Corporation, of
any and all claims against the Corporation and all related parties with respect to all
matters arising out of the Covered Person’s employment by the Corporation and its
affiliates and (if applicable) the termination thereof (other than claims for any
entitlements under the terms of this 2024 EO Plan or for vested benefits under any
employee benefit plans or programs of the Corporation made available to employees of
the Corporation and its affiliates generally under which the Covered Person has accrued
and is due a benefit), subject to applicable law.
“RSU Plan” means that certain Amended and Restated 2008 Restricted Stock
Unit Plan as adopted by the Corporation in May 2017, as amended and in effect from
time to time.
“Section 280G” means Section 280G of the Code and the final regulations and
any guidance promulgated thereunder.
“Section 409A” means Section 409A of the Code and the final regulations and
any guidance promulgated thereunder.
4
“Section 4999” means Section 4999 of the Code and the final regulations and any
guidance promulgated thereunder.
Each of the Covered Persons, along with other employees of the Corporation as
determined by the Compensation Committee of the Board, shall be eligible to participate
in this 2024 EO Plan, provided that the Covered Person is employed by the Corporation
on the date this 2024 EO Plan is adopted by the Board, and is not excluded from this
2024 EO Plan as provided below.
Participation in
2024 EO Plan
Each Covered Person who is employed by the Corporation (or a subsidiary) upon
a Change of Control and remains employed by the Corporation through the Closing, shall
receive a retention bonus under this 2024 EO Plan (the “Retention Bonus”) and, provided
that the conditions for payment of any Retention Bonus set forth in this 2024 EO Plan are
satisfied, one-hundred percent (100%) of the Retention Bonus, as specified with respect
to the Covered Person in Schedule 1 attached hereto, shall be paid in a lump-sum
payment on the Payment Date.
Retention Bonus
Eligibility and
Payment Date
If, prior to the date of the Closing of a Change of Control, a Covered Person (i)
voluntarily terminates his or her employment, or (ii) is terminated for Cause, he or she
will not receive a Retention Bonus, and any funds that would have been utilized for that
Covered Person’s Retention Bonus will revert to the Corporation and will not be
reallocated to any other person, including any person that is a Covered Person under this
or a similar compensation plan.
Ineligibility to
Receive
Retention
Bonuses
In the event that, following an announcement by the Corporation of a transaction
that would result in a Change of Control, or upon the occurrence of a Change of Control
as described in clause (ii) of the definition of Change in Control above, but prior to the
Closing relating to such Change of Control, a Covered Person’s employment with the
Corporation is terminated without Cause or the Covered Person terminates his or her
employment with the Corporation for Good Reason, that Covered Person shall be
eligible to receive the Retention Bonus that he or she would otherwise have been entitled
to receive had he or she remained employed with the Corporation through the Closing;
provided, however, that any Retention Bonus payable to the Covered Person shall be
reduced on a dollar for dollar basis, but not below zero, by the amount paid or payable to
the Covered Person upon such termination pursuant to any severance agreement between
the Covered Person and the Corporation.
Termination
Without Cause
or Termination
for Good Reason
5
This 2024 EO Plan shall provide benefits to each Covered Person and his or her
respective heirs, representatives, successors, and assigns, and will be binding on all
successors and assigns of the Corporation and any acquirer of the Corporation.
Benefits to
Covered Persons
and Their
Respective Heirs
Participation in this 2024 EO Plan will not provide any guarantee or promise of
employment or continued service of any Covered Person or any employee of the
Corporation or its subsidiaries with the Corporation or any of its subsidiaries, and the
Corporation shall retain the right, and its subsidiaries shall retain the right, to terminate
the employment of any Covered Person or any other employee of the Corporation or its
subsidiaries, as applicable, at any time.
No Guarantee of
Continued
Service
Notwithstanding anything to the contrary herein, it is a condition to a Covered
Person’s entitlement to receive a Retention Bonus under this 2024 EO Plan that a
Covered Person shall have executed and delivered to the Corporation a written Release
and shall not revoke such Release, such that the Release becomes irrevocable by its
terms on or before the date on which such compensation is due to be paid by the
Corporation. If a Covered Person fails to execute and deliver a Release, or revokes the
Release before it becomes irrevocable, the Covered Person shall have no right to
receive any Retention Bonus hereunder.
Release
The Corporation will withhold from any payments under this 2024 EO Plan
(including to a beneficiary or estate) any amount required to satisfy all applicable
federal, state, local, or foreign income, employment, and other tax withholding
obligations.
Withholding
It is intended that Retention Bonuses under this 2024 EO Plan meet the short-
term deferral exception under Section 409A (accordingly, notwithstanding anything
herein to the contrary, no payments to be made hereunder shall be made later than the
fifteenth (15th) day of the third (3rd) month following the last day of the taxable year
in which the Closing of a Change of Control is effectuated or otherwise in which the
payment right vests) and, if not exempt, the Retention Bonuses payable pursuant to this
2024 EO Plan are intended to comply with Section 409A, to the extent the
requirements of Section 409A are applicable hereto. The provisions of this 2024 EO
Plan shall be construed and administered in a manner consistent with that intention.
Section 409A
6
If payment of any amount under this 2024 EO Plan that is subject to Section
409A at the time specified therein would subject such amount to any additional tax
under Section 409A, the payment of such amount shall be postponed to the earliest
commencement date on which the payment of such amount could be made without
incurring such additional tax. In addition, to the extent that any guidance issued under
Section 409A would result in the Covered Person being subject to the payment of
interest or any additional tax under Section 409A, the Corporation shall, to the extent
reasonably possible and as allowed by applicable treasury regulations, amend this 2024
EO Plan in order to avoid the imposition of any such interest or additional tax under
Section 409A, which amendment shall have the minimum economic effect necessary
and be reasonably determined in good faith by the Corporation.
409A Payment
Adjustments
Notwithstanding the foregoing, the Corporation makes no representations that
the payments and benefits provided under this 2024 EO Plan comply with Section
409A and in no event will the Corporation be liable or be required to reimburse a
Covered Person for all or any portion of any taxes, penalties, interest or other expenses
that may be imposed on or incurred by him or her as a result of this 2024 EO Plan
being subject to, but not compliant with, Section 409A.
No
Representation
Regarding 409A
If a Covered Person is deemed to be a “specified employee” within the meaning
of that term under Code Section 409A(a)(2)(B), then with regard to any payment or the
provisions of any benefit that is required to be delayed pursuant to Code
Section 409A(a)(2)(B)(i), such payment or benefit shall not be made or provided prior
to the earlier of:
(i)
the expiration of the six (6) month period measured from the date of the
Covered Person’s “separation from service” (as such term is defined in Treasury
Regulation Section 1.409A-1(h)); or
(ii)
the date of the Covered Person’s death (the “Delay Period”);
and all payments and benefits delayed pursuant to the foregoing (whether they would
have otherwise been payable in a single sum or in installments in the absence of such
delay) shall be paid to the Covered Person in a lump sum within ten (10) days
following the expiration of the Delay Period.
409A Delay
Payments
No provision of this 2024 EO Plan will require the Corporation, for the purpose
of satisfying any obligations under this 2024 EO Plan, to purchase assets or place any
assets in a trust or other entity to which contributions are made or otherwise to segregate
any assets, nor will the Corporation maintain separate bank accounts, books, records or
other evidence of the existence of a segregated or separately maintained or administered
fund for such purposes.
No Trust Assets
7
Nothing contained in this 2024 EO Plan and no action taken pursuant to the
provisions of this 2024 EO Plan will create or be construed to create a trust of any kind.
No Trust
No property that may be acquired or invested by the Corporation in connection
with this 2024 EO Plan will be deemed security for the obligations to the Covered
Persons hereunder, but will be, and continue for all purposes to be, part of the general
funds of the Corporation, and the Covered Persons will have no rights under this 2024
EO Plan other than as unsecured general creditors of the Corporation.
No Property
Will Constitute
Security
This 2024 EO Plan is intended to be a “bonus program” as defined under U.S.
Department of Labor Regulation Section 2510.3-2(c) and will be construed and
administered in accordance with such intention.
Bonus Program
All questions concerning the construction, validation, and interpretation of this
2024 EO Plan will be governed by the laws of the State of Colorado without regard to its
conflict of laws provisions.
Choice of Law
The Corporation reserves the right to amend or terminate this 2024 EO Plan at
any time; provided, however, that (i) any such amendment or termination shall be made
in writing and approved by resolution of the Compensation Committee or the Board, and
(ii) following the Effective Date, the Corporation may not, without a Covered Person’s
written consent, amend or terminate this 2024 EO Plan in any way that (x) prevents the
Covered Person from becoming eligible for his or her Retention Bonus under this 2024
EO Plan, or (y) reduces the amount of Retention Bonuses payable, or potentially payable
to a Covered Person under this 2024 EO Plan.
Amendment
Under this 2024 EO Plan, effective as of April 1, 2024, the salaries (the “2024 EO
Plan Annual Base Salary”) of the Covered Persons shall be as specified with respect to
each such Covered Person in Schedule 1 attached hereto.
2024 EO Plan
Annual Base
Salaries
If a Change of Control occurs before March 31, 2026, for purposes of calculating
the Retention Bonuses in Schedule 1, the 2024 EO Plan Annual Base Salaries shall be as
set forth immediately above.
Change of
Control Salaries
8
As promptly as practical after the adoption of this 2024 EO Plan, the Covered
Persons shall be granted restricted stock units in accordance with the RSU Plan and
pursuant to award agreements under said RSU Plan approved by the Compensation
Committee as specified with respect to each such Covered Person in Schedule 1 attached
hereto.
Such restricted stock units shall vest in amounts and at times as set forth in
Schedule 1 attached hereto and in accordance with the terms of the RSU Plan and
applicable award agreement with respect thereto.
2024 EO Plan
Restricted Stock
Units
The Covered Persons shall be entitled to annual performance bonuses for each of
the Corporation’s 2024 and 2025 fiscal years, in amounts as the Compensation
Committee shall determine in its discretion with respect to each such Covered Person in
accordance with the 2024 and 2025 Executive Officer Bonus Performance Plans (“EO
Bonus Plans”) as described in Schedule 2 attached hereto, provided that such Covered
Person continues in the service of the Corporation (or its subsidiary) through December
31, 2024 (with respect to the performance bonus for the 2024 fiscal year), or December
31, 2025 (with respect to the performance bonus for the 2025 fiscal year).
2024 and 2025
EO Bonus
Performance
Plans
To the maximum extent allowed by law, the right of each of the Covered Persons
to receive the Retention Bonus due pursuant to this 2024 EO Plan in the event of a
Change of Control shall be subject to that Covered Person having entered into an
agreement with the party that acquires the Corporation upon such Change of Control
whereby that Covered Person shall agree to continue to work for the acquirer or its
affiliate or the Corporation, as applicable, for a period of 3 months following the Closing
of the Change of Control or such lesser period as determined by the acquirer (the “Post
Change of Control Employment Period”); provided, that the foregoing shall not apply to
a Covered Person unless: (a) the acquiror desires to engage that Covered Person to
continue to work for the acquirer (or its affiliate or the Corporation or its affiliate); (b) the
agreement between such Covered Person and the acquiror requires the acquiror to pay the
Covered Person a monthly salary equivalent to or greater than the per month amount of
the Covered Person’s 2024 EO Plan Annual Base Salary for each month during the Post
Change of Control Employment Period; and (c) the agreement between such Covered
Person and the acquiror requires the acquiror to pay such Covered Person a retention
bonus equivalent to one quarter of the Covered Person’s performance bonus for the most
recent completed fiscal year, which payment shall be due and payable within thirty (30)
days after the end of the Post Change of Control Employment Period as long as such
Covered Person continued to work for the acquirer, its affiliate or the Corporation until
the last day of the Post Change of Control Employment Period or the acquirer, its affiliate
or the Corporation terminates such agreement with such Covered Person prior to such
date; and (d) the Covered Person having been employed by the Corporation or a
subsidiary through the Closing of the Change of Control.
Service
Agreements
9
Schedule 1
The Covered Person’s total compensation under the 2024 EO Plan shall be as follows:
Covered Person
Title
2024 EO Plan Annual Base Salary for Period April 1, 2024 through March 31, 2026
Chief Executive
Officer
$675,000 per year
Chief Financial
Officer
$400,000 per year
President (Hallador
Power Company,
LLC)
$450,000 per year
Retention Bonus Amount
Chief Executive
Officer
An amount equal to the sum of:
(1) $1,350,000 in the event the acquiring company following the Closing of a Change of
Control does not engage such Covered Person to continue to work for the acquirer, or
$1,181,250 in the event the acquiring company does engage such Covered Person to continue to
work for the acquirer pursuant to the requirements of the provisions in the 2024 EO Plan titled
“Service Agreements;” plus
(2) an amount equal to the Covered Person’s annualized performance bonus for the prior fiscal
year, pro rated for the period served in the fiscal year in which the Closing occurs through to
the date of the Closing.
Chief Financial
Officer
An amount equal to the sum of:
(1) $800,000 in the event the acquiring company following the Closing of a Change of Control
does not engage such Covered Person to continue to work for the acquirer, or $700,000 in the
event the acquiring company does engage such Covered Person to continue to work for the
acquirer pursuant to the requirements of the provisions in the 2024 EO Plan titled “Service
Agreements;” plus
(2) an amount equal to the Covered Person’s annualized performance bonus for the prior fiscal
year, pro rated for the period served in the fiscal year in which the Closing occurs through to
the date of the Closing.
President (Hallador
Power Company,
LLC)
An amount equal to the sum of:
(1) $900,000 in the event the acquiring company following the Closing of a Change of Control
does not engage such Covered Person to continue to work for the acquirer, or $787,500 in the
event the acquiring company does engage such Covered Person to continue to work for the
acquirer pursuant to the requirements of the provisions in the 2024 EO Plan titled “Service
Agreements;” plus
(2) an amount equal to the Covered Person’s annualized performance bonus for the prior fiscal
year, pro rated for the period served in the fiscal year in which the Closing occurs through to
the date of the Closing.
10
11
Restricted Stock Units
Chief Executive
Officer
A one-time grant of a total of 315,236 restricted stock units, to be granted under the RSU Plan
as promptly as practical after the adoption of this 2024 EO Plan, which shall vest in the amount
of 105,079 restricted stock units on March 31st of each of 2025 and 2026, and 105,078
restricted stock units on March 31, 2027, subject to the Covered Person’s continued Service, as
defined in the RSU Plan, through the applicable vesting date, and shall vest in full subject to the
Covered Person’s continued Service through to the date of a Change in Control, as defined in
the RSU Plan, and otherwise in accordance with the terms of the RSU Plan and the applicable
award agreement.
Chief Financial
Officer
A one-time grant of a total of 70,053 restricted stock units, to be granted under the RSU Plan as
promptly as practical after the adoption of this 2024 EO Plan, which shall vest in the amount of
23,351 restricted stock units on March 31st of each of 2025, 2026 and 2027, subject to the
Covered Person’s continued Service through the applicable vesting date, and shall vest in full
subject to the Covered Person’s continued Service through to the date of a Change in Control,
and otherwise in accordance with the terms of the RSU Plan and the applicable award
agreement.
President (Hallador
Power Company,
LLC)
A one-time grant of a total of 122,592 restricted stock units, to be granted under the RSU Plan
as promptly as practical after the adoption of this 2024 EO Plan, which shall vest in the amount
of 40,864 restricted stock units on March 31st of each of 2025, 2026 and 2027, subject to the
Covered Person’s continued Service through the applicable vesting date, and shall vest in full
subject to the Covered Person’s continued Service through to the date of a Change in Control,
and otherwise in accordance with the terms of the RSU Plan and the applicable award
agreement.
Signing Bonus
Chief Financial
Officer
In addition to the bonuses otherwise described under the 2024 Plan which the Chief Financial
Officer is eligible for in accordance with the terms of the 2024 Plan, the Chief Financial Officer
shall be granted a one-time grant of a total of 17,513 restricted stock units, to be granted under
the RSU Plan as promptly as practical after the Chief Financial Officer becomes an employee of
the Corporation, which shall vest in the amount of 5,838 restricted stock units on March 31st of
each of 2025 and 2026, and 5,837 restricted stock units on March 31, 2027, subject to the
Covered Person’s continued Service through the applicable vesting date, and shall vest in full
subject to the Covered Person’s continued Service through to the date of a Change in Control,
and otherwise in accordance with the terms of the RSU Plan and the applicable award
agreement.
12
Executive Officer Bonus Performance Plan
Performance Goals and Payouts
Chief Executive Officer
The chart below sets forth the applicable goals and payouts for the Chief Executive Officer:
Area
Goals
Base
Points
Threshold
Goal
Target Goal
Maximum
Goal
Payout Does
Not Meet
Threshold
Payout at
Target
Payout at
Maximum
Safety
(Sunrise) Note
1
Severity
Measure
(National
Average)
5
100.00%
89%
78.00%
$0
$23,100
$46,200
Violations
Per
Inspection
Day
(National
Average)
5
0.50
0.42
0.34
$0
$23,100
$46,200
Safety
(Power) Note 2
Incident Rate
5
5.40
4.50
3.60
$0
$23,100
$46,200
Safety
Inspection
Rate
5
1
1.25
1.50
$0
$23,100
$46,200
Financial
Adjusted
EBITDA ($
million)
60
34.3
49.0
63.7
$0
$277,200
$554,400
Discretionary
20
$0
$92,400
$184,800
13
Chief Financial Officer
The chart below sets forth the applicable goals and payouts for the Chief Financial Officer:
Area
Goals
Base
Points
Threshold
Goal
Target Goal
Maximum
Goal
Payout Does
Not Meet
Threshold
Payout at
Target
Payout at
Maximum
Safety
(Sunrise) Note
1
Severity
Measure
(National
Average)
5
100.00%
89%
78.00%
$0
$10,000
$20,000
Violations
Per
Inspection
Day
(National
Average)
5
0.50
0.42
0.34
$0
$10,000
$20,000
Safety
(Power) Note 2
Incident Rate
5
5.40
4.50
3.60
$0
$10,000
$20,000
Safety
Inspection
Rate
5
1
1.25
1.50
$0
$10,000
$20,000
Financial
Adjusted
EBITDA ($
million)
60
34.3
49.0
63.7
$0
$120,000
$240,000
Discretionary
20
$0
$40,000
$80,000
14
President (Hallador Power Company, LLC)
The chart below sets forth the applicable goals and payouts for the President of Hallador Power Company, LLC:
Area
Goals
Base
Points
Threshold
Goal
Target Goal
Maximum
Goal
Payout Does
Not Meet
Threshold
Payout at
Target
Payout at
Maximum
Safety
(Sunrise) Note
1
Severity
Measure
(National
Average)
5
100.00%
89%
78.00%
$0
$15,000
$30,000
Violations
Per
Inspection
Day
(National
Average)
5
0.50
0.42
0.34
$0
$15,000
$30,000
Safety
(Power) Note 2
Incident Rate
5
5.40
4.50
3.60
$0
$15,000
$30,000
Safety
Inspection
Rate
5
1
1.25
1.50
$0
$15,000
$30,000
Financial
Adjusted
EBITDA ($
million)
60
34.3
49.0
63.7
$0
$180,000
$360,000
Discretionary
20
$0
$60,000
$120,000
Note 1:
Safety (Sunrise) is based on Sunrise Coal’s performance percentage relative to the national average for
underground coal mines over the preceding 4 years. For the 2024 Performance Period, safety will be
determined relative to the 2020 – 2023 period. For the 2025 Performance Period, safety will be
determined relative to the 2021 – 2024 period. Actual results for each safety measure will be calculated
by Sunrise Coal management with final results available.
Note 2:
Safety (Power) is based on Hallador Power’s performance percentage relative to the national average for
coal-fired power generating facilities over the preceding 4 years. For the 2024 Performance Period, safety
will be determined relative to the
15
2020 – 2023 period. For the 2025 Performance Period, safety will be determined relative to the 2021 –
2024 period. Actual results for each safety measure will be calculated by Hallador Power management
with final results available.
16
The charts above set forth the Performance Goals for each performance measure for each of the 2024 and
2025 Performance Periods and the associated payouts for the Chief Executive Officer and Chief Financial
Officer of the Corporation and the President of Hallador Power Company, LLC (each, a “Covered Person”).
For the Chief Executive Officer, the target bonus is $462,000 for each of the 2024 and the 2025 Performance
Periods. For the Chief Financial Officer, the target bonus is $200,000 for each of the 2024 and the 2025
Performance Periods. For the President of Hallador Power Company, LLC, the target bonus is $300,000 for
each of the 2024 and the 2025 Performance Periods. A portion of the target bonus is allocated to each
performance measure in proportion to the base points allocated to the performance measure. Performance
against each Performance Goal and the corresponding payout are measured separately. The attained
performance against a Performance Goal shall not affect the performance bonus amount payable with respect
to any other Performance Goal.
No payout is available with respect to a performance measure if performance is at or below the threshold
level.
The payout for performance above the threshold level but below the target level shall be determined by
straight line interpolation between zero and the target payout amount.
The payout for performance above the target level but below the maximum level shall be determined by
straight line interpolation between the target payout amount and the maximum payout amount.
Performance in excess of the maximum Performance Goal does not result in a payout in excess of the
maximum payout amount.
Performance bonus amounts, if any, will be paid in a lump sum net of applicable withholding, after audit
completion, in March 2025 with respect to the 2024 Performance Period and in March 2026 with respect to
the 2025 Performance Period, contingent on the Covered Person’s continued service with the Corporation or
its affiliates through to December 31, 2024, with respect to the 2024 Performance Period, and through to
December 31, 2025, with respect to the 2025 Performance Period.
Example - CEO:
By way of example, if, for the 2024 Performance Period, Severity Measure (National Average) is 99%, the
threshold Performance Goal for Violations per Inspection Day, Incident Rate and Safety Inspection Rate are
not exceeded, and the adjusted EBITDA is $50.0 million, the Chief Executive Officer shall be entitled to a
receive a performance bonus for the 2024 Performance Period calculated as follows:
Severity Measure (National Average): $23,100 * (100 - 99)/(100 - 89) = $2,100
EBITDA: $277,200 + ($277,200 * (50 - 45)/(54 - 45)) = $277,200 + $154,000 = $431,200
TOTAL: $433,300
In addition to the safety and financial performance goals described in the above chart: (i) the Chief Executive
Officer may also be entitled to receive a discretionary bonus amount for each of
17
the 2024 Performance Period and 2025 Performance Period, as determined by the Board or the Committee,
as applicable, of up to $184,800; (ii) the Chief Financial Officer may also be entitled to receive a
discretionary bonus amount for each of the 2024 Performance Period and 2025 Performance Period, as
determined by the Board or the Committee, as applicable, of up to $80,000; and (iii) the President of
Hallador Power Company, LLC may also be entitled to receive a discretionary bonus amount for each of the
2024 Performance Period and 2025 Performance Period, as determined by the Board or the Committee, as
applicable, of up to $120,000.
1
EXHIBIT 14.1
CODE OF CONDUCT AND ETHICS
1. Introduction. This Code of Conduct and Ethics (the Code) covers a wide range of business practices and
procedures. It does not cover every issue that may arise, but it sets out basic principles to guide all
employees, officers, and directors of the company, its subsidiaries and affiliates (the Company). All of
our employees, officers, and directors must conduct themselves accordingly and seek to avoid even the
appearance of improper behavior. The Code should also be provided to and followed by the Company’s
agents and representatives.
If a law, rule, or court order conflicts with a policy in this Code, you must comply with the law, rule, or
court order. If you have any questions about these conflicts, you should immediately ask your supervisor
or Human Resources how to handle the situation. Employees, officers, and directors are responsible for
understanding the legal and policy requirements that apply to their jobs and report any suspected
violations of law, this Code, or Company policy to their supervisor or Human Resources. You may report
any concerns or potential violations to your supervisor, Human Resources, or the legal/compliance
department.
Acting with integrity and doing the right thing are driving forces behind the Company’s success. From
the very beginning, our Company has been committed to conducting its business in an ethical manner -
doing right by our employees, customers, vendors, suppliers, communities and stockholders. The
Company requires its employees, officers, and directors to conduct themselves and the Company's
business in the most ethical manner possible. We share the responsibility for protecting and advancing
the Company's reputation, and ethics and values must drive our business strategies and activities. This
Code provides you with the guidelines for meeting your ethical and legal obligations at the Company.
2. Compliance with Laws, Rules, and Regulations. Obeying the law, both in letter and in spirit, is the
foundation on which this Company’s ethical standards are built. All employees, officers, and directors
must respect and obey the laws, rules, and regulations of all relevant jurisdictions, including but not
limited to, the cities, counties, states, and countries in which we operate. Although employees, officers,
and directors are not expected to know the details of each of these laws, rules and regulations, it is
important to know enough to determine when to seek advice from supervisors, managers or other
appropriate personnel. If you are uncertain about any law, rule, or regulation, you should contact your
supervisor, Human Resources, or the legal or compliance department.
2
3. Conflicts of Interest. A conflict of interest exists when a person’s private interest interferes in any way,
or even appears to interfere, with the interests of the Company. A conflict situation can arise when an
employee, officer or director takes actions or has interests that may make it difficult to objectively and
effectively perform his or her Company work. It is immaterial whether the employee was originally
aware of the conflict. An employee that discovers a conflict during or after-the-fact must report it and
discontinue the arrangement or activity.
Conflicts of interest may also arise when an employee, officer or director (or a member of his or her
family) receives improper personal benefits due to his or her position in the Company. Loans to, or
guarantees of obligations to, employees, officers, and directors and their family members by the
Company may create conflicts of interest.
It is a conflict of interest for a Company employee, officer, or director to work for a competitor,
customer, or supplier. You should avoid any direct or indirect business connection with our customers,
suppliers or competitors; except as required on our behalf. Such work and/or activities shall include, but
is not limited to, directly or indirectly competing with Company in any way, or acting as an officer,
director, employee, consultant, stockholder, volunteer, lender, or agent of any business enterprise of the
same nature as, or which is in direct competition with, the business in which Company is now engaged or
in which Company becomes engaged during the term of your employment with Company, as may be
determined by Company in its sole discretion.
Conflicts of interest are prohibited as a matter of Company policy, except as approved by Marjorie
Hargrave, our Chief Financial Officer. Conflicts of interest may not always be clear-cut, so if you have a
question, you should consult with your supervisor or Human Resources. Any employee, officer, or
director who becomes aware of a conflict or potential conflict must report it immediately to a supervisor
or Human Resources.
Nothing in this Code is intended to interfere with your rights under federal and state laws, including the
National Labor Relations Act (NLRA), nor will the Company construe this Code in a way that limits such
rights. Employees have the right to engage in or refrain from activities protected by the NLRA.
4. Confidentiality. Employees, officers, and directors must maintain the confidentiality of proprietary
information entrusted to them by the Company or its customers or suppliers, except when disclosure is
authorized in writing by the chief financial officer or required by laws or regulations. Proprietary
information includes all non-public information of the Company and intellectual property such as trade
secrets, patents, trademarks and copyrights, as well as business, marketing and service plans, engineering
and manufacturing ideas, designs, databases, records, and any unpublished financial data and reports.
Disclosing such information might be of use to competitors or harmful to the Company or its customers
or suppliers if disclosed. This includes information that suppliers and customers have entrusted to us.
3
Information that has been made public by the Company, such as press releases, news articles, or
advertisements, is not considered confidential and does not require protection.
It is the responsibility of each of us to use discretion in handling Company information so that we do not
inadvertently reveal confidential information to competitors, vendors, suppliers, friends and/or family
members. If you are unsure about whether certain information is confidential, presume that it is. The
obligation to preserve proprietary information continues even after employment ends.
5. Insider Trading. All non-public information about the Company should be considered confidential
information. Employees, officers, and directors who have access to confidential information about the
Company or any other entity are not permitted to use or share that information for trading purposes or for
any other purpose except to conduct Company business as described in the Company’s Insider Trading
Policy. To use non-public information for personal financial benefit or to “tip” others who might make an
investment decision based on this information is unethical and illegal. If you have any questions, please
consult with the Company’s legal department or your personal legal counsel when appropriate.
6. Corporate Opportunities. Employees, officers, and directors are prohibited from taking opportunities
that are discovered through the use of corporate property or information for themselves without the
consent of the Board. No employee, officer, or director may use corporate property or information for
personal gain and no employee, officer, or director may compete directly or indirectly with the Company.
Employees, officers, and directors owe a duty to the Company to advance the Company’s interests when
the opportunity to do so arises.
7. Competition and Fair Dealing. We seek to fairly and honestly outperform our competition. We seek
competitive advantages through superior work effort—never through unethical or illegal business
practices. Stealing proprietary information, possessing trade secret information that was obtained without
the owner’s consent, or inducing such disclosures by past or present employees of other companies is
prohibited and potentially illegal. Each employee, officer and director should endeavor to respect the
rights of and deal fairly with the Company’s customers, suppliers, competitors and employees. No
employee, officer or director should take unfair advantage of anyone through manipulation, concealment,
abuse of privileged information, misrepresentation of material facts, or any other illegal trade practice.
No employee, officer or director is permitted to engage in price fixing, bid rigging, allocation of markets
or customers, or similar illegal activities. The Company will fully cooperate with law enforcement and
other agencies to pursue anyone engaged in illegal activities to protect the Company’s good name.
4
The purpose of business entertainment and gifts in a commercial setting is to create goodwill and sound
working relationships, not to gain unfair advantage with customers or suppliers and against competitors.
No gift or entertainment should ever be offered, given, requested, provided or accepted by any Company
employee, officer or director, family member of an employee, officer or director, or agent unless it (1) is
not a cash gift; (2) is consistent with customary business practices; (3) is reasonable in fair market value
under the given circumstances; (4) cannot be construed as a bribe or payoff; and (5) does not violate any
laws, regulations or applicable policies of the other party’s organization. Please discuss with your
supervisor, Human Resources, Marjorie Hargrave or the legal department any gifts or proposed gifts if
you are not certain whether they are appropriate or legal.
8. Antitrust. Antitrust laws in the United States and other countries are intended to preserve a free and
competitive marketplace. The Company requires full compliance with these laws. Employees, officers,
and directors must not discuss with competitors how the Company prices, markets, services or otherwise
competes. Employees, officers, and directors must not share confidential business information with our
competitors and must not engage in any conduct that could unreasonably restrict our competitors' access
to the market. Antitrust laws are complex and can be difficult to understand. Employees, officers, and
directors should seek advice from the legal or compliance department when dealing with antitrust issues.
9. Political Contributions. Except as approved in advance by the Chief Executive Officer or Chief
Financial Officer, the Company prohibits political contributions (directly or through trade associations)
by the Company. This includes (1) any contributions of Company funds or other assets for political
purposes, (2) encouraging individual employees to make any such contribution, or (3) reimbursing an
employee for any contribution. Individual employees are free to make personal political contributions as
they see fit or to participate in the Company’s Political Action Committee.
10. Payments to Government Personnel. From time to time, the Company’s business obligates it to interact
with officials and employees of (1) foreign government; (2) U.S. federal, state, and local governments;
and (3) U.S. and foreign political parties.
The Foreign Corrupt Practices Act (the FCPA) prohibits the making of a payment and/or the promising or
offering of anything of value to any foreign government official, government agency, political party, or
political candidate (collectively, Government Personnel) in exchange for a business favor or when
otherwise intended to influence the action taken by any such individual or agency or to gain or retain any
competitive or improper business advantage. It is very important to know that the prohibitions of the
FCPA apply to actions taken by all employees and by all outside parties engaged directly or indirectly by
the Company (e.g., consultants, professional advisers, etc.). While the FCPA does, in certain limited
circumstances, allow nominal “facilitating payments” to be made, given the complexity of the FCPA and
the severe penalties associated with its violation, all employees and outside parties engaged by the
company must comply with the Company’s FCPA policy and contact the legal department with any
questions concerning the Company’s and their obligations under the FCPA or concerning any transaction
which may be in violation of the FCPA; any other federal, state, local, or foreign law or regulation; or
this Code.
5
No employee of the Company may retain a consultant, agent, or other outside party which will have
contact with any foreign or U.S. Government Personnel until the employee, the legal department and the
Chief Financial Officer have reasonably concluded that such retained party understands and will fully
abide by the FCPA, the Company’s FCPA policy, and this Code.
In addition, the U.S. government has a number of laws and regulations regarding business gratuities,
which may be accepted by U.S. Government Personnel. The promise, offer, or delivery to an official or
employee of the U.S. government of a gift, favor, or other gratuity in violation of these rules would not
only violate Company policy but could also be deemed a civil or criminal offense. State and local
governments, as well as foreign governments, often have similar rules.
11. Discrimination, Retaliation, and Harassment. The diversity of the Company’s employees is a
tremendous asset. We are firmly committed to providing equal opportunity in all aspects of employment
and will not tolerate any illegal discrimination or harassment based on race, color, religion, sex, national
origin, age, disability, or any other protected class under applicable federal, state, and local laws.
Employees must comply with all anti-discrimination, anti-retaliation, and anti-harassment laws whether
local, state or federal.
If any employee, officer, or director believes he or she has been harassed by anyone at the Company, he
or she should immediately report the incident to his or her supervisor or Human Resources. Similarly,
supervisors and managers who learn of any such incident should immediately report it to Human
Resources. Human Resources will promptly and thoroughly investigate any complaints and take
appropriate action.
12. Health and Safety. The Company strives to provide each employee, officer and director, as well as
customers, vendors, or other visitors, with a safe and healthy work environment. Each employee, officer,
and director has the responsibility for maintaining a safe and healthy workplace for all employees,
officers, and directors by following environmental, safety, and health rules and practices and by reporting
accidents, injuries and unsafe equipment, practices or conditions.
All Company locations must remain in compliance with the Occupational Safety and Health Act (OSH
Act), the Mine Safety and Health Act (MSH Act) and other regulatory requirements. Safety issues and
violations of regulatory requirements will be promptly addressed. In addition to meeting our obligations,
the Company will take proactive initiatives to make safety a top priority. Employees, officers, and
directors are charged with the responsibility for maintaining safe practices and conditions in everything
they do and report anything that threatens anyone’s safety.
Employees, officers, and directors are expected to perform their Company related work in a safe manner,
free of the influences of alcohol, illegal drugs or controlled substances. The use of illegal drugs in the
workplace will not be tolerated.
6
13. Environmental. The Company expects its employees, officers, and directors to follow all applicable
environmental laws and regulations. If you are uncertain about your responsibility or obligation, you
should check with your supervisor or the legal or compliance department for guidance. You should
immediately report to management any emergency situations involving any types of potential
environmental harm to persons or property.
14. Record-Keeping, Financial Controls and Disclosures. The Company requires honest, accurate and
timely recording and reporting of information to make responsible business decisions.
All business expense accounts must be documented and recorded accurately in a timely manner. If you
are not sure whether a certain expense is legitimate, ask your controller. Policy guidelines are available
from your controller.
All of the Company’s books, records, accounts and financial statements must be maintained in detail;
must appropriately reflect the Company’s transactions; must be made promptly without false or
misleading information; must be promptly disclosed in accordance with any applicable laws or
regulations; and must conform both to applicable legal requirements and to the Company’s system of
internal controls. Any employee who becomes aware of any inadvertent or unauthorized disclosure of
information discussed in this Section must notify the legal or compliance department immediately.
If any employee, officer, or director has concerns or complaints regarding accounting or auditing matters
of the Company, then he or she is encouraged to submit those concerns by one of the methods described
in the “Compliance Procedures” section below.
Business records and communications often become public and we should avoid exaggeration,
derogatory remarks, guesswork or inappropriate characterizations of people and companies that may be
misunderstood. This applies equally to e-mail, internal memos and formal reports. Records should always
be retained or destroyed according to the Company’s record retention policies. In accordance with those
policies, in the event of litigation or governmental investigation, please consult with the legal or
compliance department.
15. Protection and Proper Use of Company Assets. All employees, officers, and directors should protect
the Company’s assets and ensure their efficient use. Theft, carelessness, and waste have a direct impact
on the Company’s profitability. All Company assets are to be used for legitimate or authorized Company
purposes. Any suspected incident of fraud or theft, including theft of time, should be immediately
reported for investigation. Unless approved by [insert party to approve use], Company assets should not
be used for non-Company business.
The obligation of employees, officers, and directors to protect the Company’s assets includes the
Company’s proprietary information. Proprietary information includes intellectual property such as trade
secrets, patents, trademarks and copyrights, as well as business, marketing and service plans, engineering
and manufacturing ideas, designs, databases, records, and any unpublished financial data and reports.
Nothing in this Code is intended to interfere with your rights under federal and state laws, including the
National Labor Relations Act, nor will the Company construe this Code in a way that limits such rights.
7
Employees have the right to engage in or refrain from activities protected by the National Labor
Relations Act.
Unauthorized use or distribution of this information is a violation of Company policy. It could also be
illegal and result in civil or criminal penalties.
16. Trade Issues. From time to time, the United States, foreign governments, and the United Nations have
imposed boycotts and trading sanctions against various governments and regions, which must be obeyed.
Advice regarding the current status of these matters must be obtained from the legal department.
17. Waivers of the Code of Business Conduct and Ethics. Any waiver of this Code for employees,
executive officers or directors may be made only by the Board and will be promptly disclosed as required
by law or regulation.
18. Reporting Any Illegal or Unethical Behavior. Employees are encouraged to talk to supervisors or other
appropriate personnel such as the legal or compliance department or Human Resources about observed
behavior that they believe may be illegal or a violation of this Code or Company policy or when in doubt
about the best course of action in a particular situation. The Company will immediately and thoroughly
investigate all such concerns and take appropriate action. The Company will not allow retaliation for
reports made in good faith by employees of misconduct by others. Employees are expected to cooperate
in internal investigations of misconduct.
19. Improper Influence on Conduct of Auditors. It is prohibited to directly or indirectly take any action to
coerce, manipulate, mislead or fraudulently influence the Company’s independent auditors for rendering
the financial statements of the Company materially misleading. Prohibited actions include, but are not
limited to, those actions taken to coerce, manipulate, mislead or fraudulently influence an auditor (1) to
issue or reissue a report on the Company’s financial statements that is not warranted in the circumstances
(due to material violations of generally accepted accounting principles, generally accepted auditing
standards, or other professional or regulatory standards); (2) not to perform an audit, review or other
procedures required by generally accepted auditing standards or other professional standards; or (3) not
to communicate matters to the Company’s Audit Committee.
20. Compliance Procedures. All employees, officers, and directors have the responsibility to report
observed or suspected violations of law, this Code and any activity that might constitute financial fraud
or financial misconduct. We must all work to ensure prompt and consistent action against violations.
However, not all situations are clear-cut. Since we cannot anticipate every situation that will arise, it is
important that we have a way to approach a new question or problem. These are the steps to keep in
mind:
(a)
Make Sure You Have All the Facts. To reach the right solutions, we must be as fully informed as
possible.
8
(b)
Ask Yourself: What Specifically Am I Being Asked to Do? Does It Seem Unethical or
Improper? This will enable you to focus on the specific question you are faced with and the
alternatives you have. Use your judgment and common sense; if something seems unethical or
improper, it probably is.
(c)
Discuss the Problem with Your Supervisor, Human Resources, or, for Compliance Issues, with
the Legal Department. This is the basic guidance for all situations. In many cases, your supervisor
will be more knowledgeable about the question and will appreciate being brought into the decision-
making process. Remember that it is your supervisor’s responsibility to help solve problems. If you
are uncomfortable discussing the problem with your supervisor, you can talk to Human Resources.
If your question relates to any compliance issues addressed in this Code, you can talk to the
Company’s legal or compliance department.
(d)
Seek Help from Company Resources. In a case where it may not be appropriate to discuss an
issue with your supervisor or local management, call 303-746-7036 which will put you in direct
contact with the legal department at Company headquarters. If you prefer to write, address your
concerns to the legal department or the Audit Committee of the Board. Anonymous reports can be
made through the internet at https://www.whistleblowerservices.com/hpco or by phone at 866-
229-6923.
(e)
You May Report Violations in Confidence and without Fear of Retaliation. If your situation
requires that your identity be kept secret, your anonymity will be protected. The Company does not
permit retaliation of any kind against employees, officers or directors for good faith reports of
suspected violations.
(f)
Always Ask First, Act Later. If you are unsure of what to do in any situation, seek guidance
before you act.
(g)
All Employees, Officers, and Directors Are Subject to the Company’s Code, Which Describes
Procedures for the Internal Reporting of Violations of the Code. All employees, officers, and
directors must comply with those reporting requirements and promote compliance with them by
others. Failure to adhere to this Code by any employee, officer, or director will result in
disciplinary action up to and including termination.
‘Adopted March 11, 2025
Exhibit 19.1
HALLADOR ENERGY COMPANY
Insider Trading Policy
Updated March 11, 2025
As a public company, Hallador Energy Company (“Hallador”) is subject to various federal and state laws and
regulations governing trading in its securities. It is our policy, (hereinafter referred to as the “Policy”), and that of our
subsidiaries, to comply fully, and to assist our employees in complying fully, with these laws and regulations.
Who is subject to this Policy?
All directors, officers, employees, consultants, customers, suppliers and any other person who may come into
possession of material, nonpublic information about Hallador Energy and its subsidiaries are subject to this Policy. In
addition, special trading restrictions apply to all directors, executive officers, and additional employees designated by
the CFO from time to time (collectively, “Covered Persons”).
Family members who reside with you (including a spouse, a child, a child away at college, stepchildren, grandchildren,
parents, stepparents, grandparents, siblings, in-laws and domestic partners), or anyone else who lives in your
household, and any family members who do not live in your household but whose transactions in Hallador securities
are directed by you or are subject to your influence or control (such as parents or children who consult with you before
they trade in Hallador securities) (collectively, “Family Members”).
This Policy does not, however, apply to personal securities transactions of Family Members where the
purchase or sale decision is made solely by an independent third party and not controlled by, influenced by or
related to you or your Family Members.
Entities that you influence or control, including any corporations, partnerships, trusts, and custodial accounts,
(collectively, “Controlled Entities”).
You are responsible for the compliance with this Policy, and therefore should make your Family Members and
Controlled Entities aware of the need to confer with you before they trade in Hallador securities. Who is the
Administrator of the Policy? The Chief Financial Officer (CFO) or another employee designated by the CFO shall be
responsible for the administration of this Policy. All determinations and interpretations of this Policy shall be final and
not subject to further review. Hallador’ s CFO, Marjie Hargrave, can be reached at 303-917-0777 or by email at
mhargrave@HalladorEnergy.com.
What is Insider Trading?
Insider trading restrictions prohibit trading in the securities of a company on the basis of material, nonpublic
information gained through involvement with the company or providing that information to others outside the
company. The prohibition against such trading generally prohibits:
●
Trading in Hallador securities while in possession of material, nonpublic information about Hallador and its
subsidiaries and affiliates.
●
Passing (or “tipping”) material, nonpublic information about Hallador or its subsidiaries and affiliates to
others, including family and friends.
●
Trading in the securities of another company based on material, nonpublic information about that company
learned in the course of working for Hallador or its subsidiaries and affiliates.
●
Participating in transactions related to Hallador securities that are short-term or speculative in nature.
Actions prohibited while in possession of material, nonpublic information include, but are not limited to:
●
Buying and selling of Hallador securities (except when trading under an approved 10b5-1 plan, see below).
●
Selling Hallador securities acquired upon exercise of a stock option or engaging in a “cashless” exercise of an
option through a broker. (Hallador does not have any issued stock options.)
What is Materiality?
It is not possible to define all categories of material information. Information should be considered material if there is a
reasonable likelihood that an investor would consider it to be an important factor when making an investment decision.
In this regard, there are various categories of information (positive and negative) that are particularly sensitive and, as a
general rule, should always be considered material.
Examples of such information include, but are not limited to:
●
Financial results
●
Changes in earnings estimates or unusual gains or losses in major operations
●
Projections of future earnings or losses
●
Changes its dividend policy
●
Material impairment, write-off or restructuring
●
Stock splits
●
New equity or debt offerings
●
Extraordinary borrowings
●
Changes in debt ratings
●
Impending bankruptcy or financial liquidity problems
●
Pending or proposed plans or agreements, even if preliminary in nature, involving mergers, acquisitions,
divestitures, recapitalizations, strategic alliances, licensing agreements, or purchases or sales of significant
assets
●
The disposition or acquisition of significant assets
●
Gain or loss of a substantial customer or vendor
●
Termination or reduction of business relationship with a significant customer
●
Material sales contracts
●
Significant litigation exposure due to actual or threatened litigation, or developments regarding government
agency investigations
●
Major changes in Executive Management
The determination of whether information is material is subjective and made based on the facts and circumstances of
each particular situation. Either positive or negative information may be material. When in doubt about whether
particular nonpublic information is material, you should presume it is material. The CFO shall make the final
determination as to the materiality of nonpublic information. When in doubt, Insiders should presume information to
be material and consult the CFO before initiating transactions in Hallador securities.
When can information be considered “Public"?
Insider trading prohibitions come into play when you possess information that is both material and nonpublic.
Normally, information is considered to be “public” if it has been widely disseminated to the general public through
press releases, news tickers, widely available publication or newspaper, or in a Form 8-K, 10-Q or 10-K filed with the
Securities and Exchange Commission (“SEC”).
If you are aware of material, nonpublic information, you may not trade until the information has been disclosed to the
public, and the investing public has had time to fully absorb it. You are required to wait two full trading days after the
information has been released to the public before treating the information as public and trading in Hallador securities.
Therefore, if an announcement is made before the markets open on a Monday, you may trade in Hallador securities
starting at the open of trading on Wednesday of that week, because two full trading days would have elapsed by then
(all of Monday and Tuesday). If the announcement is made after the close of the trading markets on Monday, you may
not trade until the open of trading on Thursday.
Hallador stock trades on the NASDAQ under the symbol: HNRG. For purposes of this Policy, a “trading day” shall be
a day in which the NASDAQ is open for trading.
As with questions of materiality, if you are not sure whether information is considered public, you should either consult
with the CFO or assume that the information is nonpublic and treat it as confidential.
Tipping is prohibited!
You are required to maintain the confidentiality of Hallador’s material nonpublic information until it is publicly
disclosed and generally known or available to the public. Such information may not be disclosed, or “tipped,” to others
such as Controlled Entities, Family Members or other relatives, or business or social acquaintances. Similarly, you may
not recommend trades or assist in the trading of Hallador securities by another individual on the basis of material,
nonpublic information.
Do not discuss material nonpublic information where it may be overheard, such as in restaurants, elevators, restrooms,
and other public places. Remember that cellular phone conversations are often overheard and that voice mail and e-
mail messages may be retrieved by persons other than their intended recipients.
This Policy applies to material, nonpublic information of Hallador’s business partners.
Employees who, in the course of their work for Hallador come into possession of material, nonpublic information
about any of our business partners (customer, vendor or supplier) are required to treat such material nonpublic
information as if it was about Hallador, and are prohibited from trading in securities of that company until the
information is publicly disclosed and generally known or available to the public.
This Policy remains applicable after employment or services terminate with Hallador.
This Policy continues to apply to transactions in Hallador securities even after the termination of employment or
contractual or other business relationship. Persons in possession of material nonpublic information when their
employment or other business relationship has been terminated may not trade in Hallador securities until that
information has become public or is no longer material.
What is the “pre-clearance” policy?
Covered Persons must obtain pre-clearance of any planned transactions in Hallador securities from the CFO to confirm
that the Covered Person is not in possession or aware of any material, non-public information. In addition, the
Controlled Entities, Family Members, and other persons living in the household of each Covered Person must obtain
pre-clearance of any such transactions.
If a proposed transaction is not approved under the pre-clearance policy, the Covered Person must refrain from
engaging in the transaction and should not inform or “tip” any other individual within or outside of Hallador of the
material nonpublic information.
Once Covered Person has received pre-clearance for the planned transaction, it is effective for one week, unless the
Covered Person becomes aware of any material nonpublic information during that time, in which case the pre-
clearance expires immediately.
Failure to obtain pre-clearance before making a transaction of company stock is a violation of this Policy and will
increase risks of being liable for insider trading.
The Covered Person should notify the CFO or his designate immediately upon completion the transaction and request
that their broker immediately provide the information about the trades to the CFO such that any required Section 16
filing may be made on a timely basis.
Additionally, except for the exercise of options that does not involve the sale of Hallador securities or transactions
pursuant to a valid 10b5-1 Plan, no Covered Persons shall purchase or sell any security of Hallador during the period
beginning on 15th day of the month following the last day of any calendar quarter and ending two full trading days
after the public release of the disclosure of Hallador’s financial results in an earnings release, Form 10-K or Form 10-Q
for such fiscal quarter.
Approval by the CFO of any transaction does not constitute legal advice, nor is it a guarantee that a transaction will not
be subject to challenge by third parties.
When does the trading window open and close?
Covered Persons may purchase or sell Hallador securities during the trading window associated with the quarterly
earnings releases. The quarterly trading window shall open following the conclusion of the second trading day after the
earnings call and will end no later than the 15th day of the month after the completion of the fiscal quarter. For
example: Earnings Call on Monday after market close; trading window opens at the open of trading on Thursday; and
trading window closes on the fifteenth day of the month after the completion of the fiscal quarter. During these open
trading windows, Covered Persons are still required to obtain pre-clearance of the transaction from the CFO.
There are no guarantees that material, nonpublic information won’t develop at any time during the trading window and
cause it to close early. If an event occurs that causes the CFO to close the trading window early, Covered Persons will
be notified by e-mail of the closure.
If Covered Persons are aware of material, nonpublic information, they must not trade, even during the trading
windows.
When are Blackout Periods?
From time-to-time, and on a case-by-case basis, the CFO may declare blackout periods, as deemed appropriate in the
CFO’s discretion, to help protect Hallador from insider trading on the basis of material, nonpublic information.
Covered Persons subject to a blackout period are prohibited from trading in Hallador securities for the duration of the
blackout period. The CFO will notify Covered Persons at the beginning of the blackout period, and again when it
concludes.
Is trading under Rule 10b5-1 allowed?
Pursuant to SEC Rule 10b5-1, Covered Persons may adopt a written trading plan. Any such plan must be approved by
the CFO. The trading plan must be entered into during an open trading window
and when the Covered Person is not in possession of material, nonpublic information. The preferred period for entering
into a trading plan is generally the ten trading days immediately following the second full trading day after the
quarterly earnings have been released. The plan must either specify the amount, price and timing of transactions in
advance or delegate authority to an independent third party. Once the trading plan is adopted, the Covered Person must
not exercise any influence over the transaction.
Transactions Pursuant to 10b5-1 Plans and Pre-Clearance of 10b5-1 Plans
Notwithstanding the trading preclearance requirement stated above in the “What is the ‘pre-clearance’ policy” section,
a Covered Person shall not be required to preclear a transaction in Hallador securities if such transaction is executed
pursuant to a valid contract, instruction or plan that provides an affirmative defense (a 10b5-1 Plan) pursuant to Rule
10b5-1 under the 1934 Act and such transaction is lawful under any applicable state securities laws and complies with
the Rule 10b5-1 requirements set forth on Appendix A .
However, a 10b5-1 Plan cannot be entered into or adopted by a Covered Person when the Covered Person is in
possession of material, non-public information related to the security, whether the issuer of such security is Hallador’s
or any other company. To provide assistance in preventing inadvertent violations of applicable securities laws and to
avoid the appearance of impropriety in connection with the adoption of a 10b5-1 Plan, the adoption of any 10b5-1 Plan
providing for transactions in the securities of Hallador (including without limitation, acquisitions and dispositions of
Hallador common stock, the exercise of options and the sale of Hallador common stock issued upon exercise of
options) must comply with Rule 10b5-1 requirements attached as Appendix A and be precleared by the CFO to confirm
the absence of material non-public information at the time of such adoption. The CFO will not otherwise pass upon the
conformity of the 10b5-1 Plan or its execution to the requirements of Rule 10b5-1 or any applicable state law, which
shall be solely the responsibility of the Covered Person. In addition, any proposed amendment to, alteration of or
deviation from an established 10b5-1 Plan will be treated as the adoption of a new 10b5-1 Plan, which must be
precleared by the CFO. In connection with this preclearance, the Covered Person shall provide the CFO with a copy of
the 10b5-1 Plan proposed to be entered into or adopted by the Covered Person, which must comply with the Rule
10b5-1 requirements attached as Appendix A. If after consultation with the CFO it is determined that Hallador and/or
such Covered Person is in possession of material, non-public information, the Covered Person may not enter into,
amend, modify or adopt the 10b5-1 Plan at such time.
Short-term or speculative transactions are restricted!
Covered Persons, and any Covered Person’s Controlled Entities or Family Members, may not engage in short-term or
speculative transactions in Hallador securities as there is heightened legal risk or the appearance of improper or
inappropriate conduct. Such transactions include but are not limited to:
●
Short-term trading – Covered Persons who purchase Hallador securities in the open market may not sell any
Hallador securities of the same class during the six months following the purchase (or vice versa).
●
Short sales – Covered Persons may not sell Hallador securities they do not own.
●
Margin accounts and pledges – Covered Persons may not margin or pledge Hallador securities (including
due to that fact that the sales of the securities can occur when the Covered Person is aware of Material
Nonpublic Information).
●
Standing and limit orders outside of an approved trading plan – Standing and limit orders are discouraged
since there is no control over the timing of purchases or sales resulting from instructions to the broker. The
broker may execute the order when the Covered Person is aware of material nonpublic information. If a
Covered Person must use a standing or limit order, a “pre-clearance” must be obtained and the order
should be limited to a seven (7) day duration.
o
If the CFO issues a Trading Window Blackout during the seven (7) day pre-clearance approval period,
it is the responsibility of the Covered Person to cancel the standing and limit orders to maintain
compliance with the Policy.
●
Hedging: Covered Persons may not purchase financial instruments that are designed hedge or offset any
decrease in the market value of Hallador’s equity securities, whether granted as compensation or held directly
or indirectly by the Covered Person. Financial instruments include prepaid variable forward contracts, equity
swaps, collars and exchange funds, but the term is not limited to these instruments.
Are there restrictions on gifting or charitable donations of Hallador securities?
Covered Persons must comply with the trading windows and blackout periods for gifting and charitable contributions
and obtain a “pre-clearance” from the CFO for such transactions and immediately provide the details of any such gift
or charitable contribution once completed to ensure timely Section 16 reporting.
What if I am a Section 16 filer?
Persons who are subject to Section 16 of the Securities and Exchange Act of 1934, as amended (“Section 16”), are
required to report acquisitions and dispositions of Hallador securities within two business days after any transaction.
Such persons may be required to disgorge any profits realized from a short-swing transaction, which is any purchase
and sale, or sale and purchase, of Hallador’s equity securities within a period of less than six months, whether or not
such person possessed any material, non-public information at the time of the transaction.
All persons subject to Section 16 must obtain pre-clearance from the CFO two business days prior to conducting any
transaction in order to confirm that compliance with Section 16 is maintained and request that their broker immediately
provide the information about the trades to the CFO such that any required Section 16 filing may be made on a timely
basis.
Transactions by Family Members and Controlled Entities of persons subject to Section 16 must be reported on the
Form 4 of such person. When in doubt about the reporting of a transaction, please contact the CFO.
Are there consequences for violating this Policy?
Each person covered by the Policy is responsible for making sure that he or she complies with the Policy, and ensuring
compliance with the Policy by his or her Controlled Entities and Family Members. Due to the severity and potentially
significant adverse consequences of an insider trading violation, persons who violate the Policy may be subject to
disciplinary action by the company, which may include termination or other appropriate action. Disciplinary action
may also result due to violations of the Policy by a person’s Covered Entities or Family Members.
Under applicable U.S. law, individuals who trade on inside information (or tip information to others who trade) can be
liable for sanctions that include:
●
a civil penalty of up to three times the profit gained or loss avoided;
●
a criminal fine (no matter how small the profit) of up to $5 million; and
●
a prison term of up to 20 years.
In addition, employers (as well as possibly any supervisory person) that fail to take appropriate steps to prevent insider
trading can be subject to penalties including:
●
a civil penalty of the greater of (a) $1,978,690, and (b) three times the profit gained or loss avoided by the
person as a result of the violation; and
●
a criminal fine of up to $25 million.
Under very limited circumstances, the CFO may provide a waiver of the provisions of this Policy.
Acknowledgment
The undersigned does hereby acknowledge receipt of Hallador Energy Company’s Insider Trading Policy. The
undersigned has read and understands (or has had explained) such Policy and agrees to be governed by such Policy at
all times in connection with the purchase and sale of securities and the confidentiality of nonpublic information.
Signature
Print Name
Date:
APPENDIX A
10b5-1 Plan Requirements
Covered Persons are permitted to effect transactions in the company’s securities pursuant to approved 10b5-1 Plans. In
order to qualify as an approved “10b5-1 Plan” for purposes of this policy, the trading plan must meet all of the
following requirements:
1.
The 10b5-1 Plan must be established in writing, signed and dated by the person establishing the plan, approved
and signed by the company (with respect to the issuer certificate thereto), and filed with Office of the Chief
Legal Officer.
2.
The 10b5-1 Plan must be in a form that meets the requirements of Rule 10b5-1 and include certifications from
the person establishing the plan that:
●
he, she or it was not aware of any material non-public information about the company or its securities
when he, she or it established the 10b5-1 Plan; and
●
the 10b5-1 Plan is entered into in good faith and not as part of a plan or scheme to evade the
prohibitions of Rule 10b5 under the Exchange Act.
3.
The 10b5-1 Plan may not be established during any closed trading window to which the person establishing
the plan is subject.
4.
For any 10b5-1 Plan adopted by any “officer” or “director” (as defined under Rule 10b5-1), trading under such
10b5-1 Plan may not commence until the later of: (a) ninety (90) days after the adoption of the 10b5-1 Plan or
(b) two business days following the public disclosure of the company’s financial results for the fiscal quarter
during which the 10b5-1 Plan was adopted (but, in any event, this required cooling-off period is subject to a
maximum of 120 days after adoption of the 10b5-1 Plan).
5.
Subject to the exceptions enumerated in Rule 10b5-1, Covered Persons may not have more than one operative
10b5-1 Plan at a time.
6.
Each person establishing a 10b5-1 Plan must act in good faith with respect to the 10b5-1 Plan at all times
during which it remains outstanding.
7.
Any changes or modifications to an existing 10b5-1 Plan with regard to the amount, price, or timing of the
purchase or sale of securities underlying the 10b5-1 Plan, or a modification or change to a written formula or
algorithm, or computer program that affects the amount, price, or timing of the purchase or sale of such
securities, will be deemed to be a termination of the original 10b5-1 Plan and the adoption of a new 10b5-1
Plan, which must comply with the same requirements above, including the cooling-off period set forth in
paragraph 4 of this Appendix A.
8.
Any form of 10b5-1 Plan must be reviewed and approved by the Office of the Chief Legal Officer prior to
entry into the 10b5-1 Plan. The Office of the Chief Legal Officer shall be notified in advance of any proposed
amendments to the 10b5-1 Plan or the termination of the 10b5-1 Plan.
Exhibit 21.1
List of Subsidiaries
Edwardsport Construction Company, LLC
Gibson County Logistics, LLC
Hallador Renewables, LLC
Hallador Sands, LLC
Hallador Power Company
Hourglass Sands, LLC
HR Beam One, LLC
Oaktown Fuels Mine No. 1, LLC
Oaktown Fuels Mine No. 2, LLC
Oaktown Gas, LLC
Phoenix 820, LLC
Phoenix 500, LLC
Prosperity Mine, LLC
SFI Coal Sales, LLC
Sunrise Administrative Services, LLC
Sunrise Coal LLC
Sunrise Energy, LLC
Sunrise Land Holdings, LLC
Sycamore Coal, Inc.
Exhibit 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our reports dated March 17, 2025, with respect to the consolidated financial statements and internal control over
financial reporting included in the Annual Report of Hallador Energy Company on Form 10-K for the year ended December 31,
2024. We consent to the incorporation by reference of said reports in the Registration Statements of Hallador Energy Company on
Forms S-3 (File No. 333-273325 and File No. 333-273327) and Forms S-8 (File No. 333-261930, File No. 333-163431 and File
No. 333-171778).
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
March 17, 2025
Chairman
James W. Boyd
President and CEO
John T. Boyd II
Managing Director and COO
Ronald L. Lewis
Vice Presidents
Robert J. Farmer
Jisheng (Jason) Han
John L. Weiss
Michael F. Wick
William P. Wolf
Managing Director - Australia
Jacques G. Steenekamp
Managing Director - China
Rongjie (Jeff) Li
Managing Director – South America
Carlos F. Barrera
Pittsburgh
4000 Town Center Boulevard, Suite 300
Canonsburg, PA 15317
(724) 873-4400
(724) 873-4401 Fax
jtboydp@jtboyd.com
Denver
(303) 293-8988
jtboydd@jtboyd.com
Brisbane
61 7 3232-5000
jtboydau@jtboyd.com
Beijing
86 10 6500-5854
jtboydcn@jtboyd.com
Bogota
+57-3115382113
jtboydcol@jtboyd.com
www.jtboyd.com
Exhibit 23.2
John T. Boyd Company
Mining and Geological Consultants
March 7, 2025
File: 3467.008
Subject:
CONSENT OF JOHN T. BOYD COMPANY
TO BE NAMED IN REGISTRATION
STATEMENT
Ladies and Gentlemen:
The undersigned hereby consents to the references to our firm in the form and context in which
they appear in this Annual Report on Form 10-K for the year ended December 31, 2024 (as may be
amended, the “Annual Report”). We hereby further consent to (i) the use in the Annual Report of
information relating to our Technical Report Summary (Coal Resources and Coal Reserves,
Oaktown Mining Complex), dated March 2025 (the “Report”), providing an update of estimated coal
reserves at the Oaktown Mining Complex as of December 31, 2024 and (ii) the incorporation by
reference of the Report in the Registration Statements on Form S-3 (Nos. 333-273325 and 333-
273327) and the Registration Statements on Form S-8 (Forms S-8 (Nos. 333-163431, 333-171778
and 333-261930) of Hallador Energy Company, including any amendment thereto, any related
prospectus and any related prospectus supplement of such information.
Respectfully submitted,
JOHN T. BOYD COMPANY
By:
Ronald Lewis
Managing Director and COO
Q:\ENG_WP\3467.008 Sunrise - FY2024\WP\Sunrise - JTB Consent for 2024 10-K.doc
Exhibit 31.1
CERTIFICATION
I, Brent K. Bilsland, certify that:
1. I have reviewed this annual report on Form 10-K of Hallador Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered
by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal
control over financial reporting.
March 17, 2025
/s/BRENT K. BILSLAND
Brent K. Bilsland, Chairman, President and CEO
Exhibit 31.2
CERTIFICATION
I, Marjorie Hargrave, certify that:
1. I have reviewed this annual report on Form 10-K of Hallador Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered
by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and
15d-15(f)) for the registrant and have:
a)
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by
others within those entities, particularly during the period in which this report is being prepared;
b)
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with generally accepted accounting principles;
c)
Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)
Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most
recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably
likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function):
a)
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
b)
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal
control over financial reporting.
March 17, 2025
/s/MARJORIE HARGRAVE
Marjorie Hargrave - CFO
Exhibit 32.1
CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with this Annual Report (the "Report"), of Hallador Energy Company (the "Company"), on Form 10-K for the period
ended December 31, 2024 as filed with the Securities and Exchange Commission on the date hereof the undersigned, in the
capacities and date indicated below, each hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002, that to his knowledge:
(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15
U.S.C. 78m or 78o(d)); and
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
March 17, 2025
By:
/s/BRENT K. BILSLAND
Brent K. Bilsland, Chairman, President and CEO
March 17, 2025
By:
/s/MARJORIE HARGRAVE
Marjorie Hargrave, CFO
EXHIBIT 95.1
Our principles at Sunrise Coal LLC are safety, honesty, and compliance. We firmly believe that these values compose a dedicated
workforce and with that, come high production. The core to this is our strong training programs that include accident prevention,
workplace inspection and examination, emergency response and compliance. We work with the Federal and State regulatory
agencies to help eliminate safety and health hazards from our workplace and increase safety and compliance awareness
throughout the mining industry.
We are regulated by the Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act of 1977
(“Mine Act”). MSHA inspects our mines on a regular basis and issues various citations and orders when it believes a violation has
occurred under the Mine Act. We present information below regarding certain violations which MSHA has issued with respect to
our mines. While assessing this information please consider that the number and cost of violations will vary depending on the
MSHA inspector and can be contested and appealed, and in that process, are often reduced in severity and amount, and are
sometimes dismissed.
The disclosures listed below are provided pursuant to the Dodd-Frank Act. We believe that the following disclosures comply with
the requirements of the Dodd-Frank Act; however, it is possible that future SEC rule making may require disclosures to be filed in
a different format than the following.
The table that follows outlines required disclosures and citations/orders issued to us by MSHA during 2024. The citations and
orders outlined below may differ from MSHA`s data retrieval system due to timing, special assessed citations, and other factors.
Definitions:
Section 104(a) Significant and Substantial Citations “S&S”: An alleged violation of a mining safety or health standard or regulation
where there exists a reasonable likelihood that the hazard outlined will result in an injury or illness of a serious nature.
Section 104(b) Orders: Failure to abate a 104(a) citation within the period of time prescribed by MSHA. The result of which is an
order of immediate withdraw of non-essential persons from the affected area until MSHA determines the violation has been
corrected.
Section 104(d) Citations and Orders: An alleged unwarrantable failure to comply with mandatory health and safety standards.
Section 107(a) Orders: An order of withdrawal for situations where MSHA has determined that an imminent danger exists.
Section 110(b)(2) Violations: An alleged flagrant violation issued by MSHA under section 110(b)(2) of the Mine Act.
Pattern or Potential Pattern of Violations: A pattern of violations of mandatory health or safety standards that are of such a nature
as could have significantly and substantially contributed to the cause and effect of coal mine health or safety hazards under
section 104(e) of the Mine Act or a potential to have such a pattern.
Contest of Citations, Orders, or Proposed Penalties: A contest proceeding may be filed with the Commission by the operator or
miners/miner’s representative to challenge the issuance or penalty of a citation or order issued by MSHA.
MSHA Federal Mine ID#`s:
(12-02465 – Carlisle Preparation Plant) (12-02394 – Oaktown Fuels No. 1) (12-02418 – Oaktown Fuels No. 2) (12-02462 –
Oaktown Fuels Preparation Plant) (12-02249 – Prosperity Mine)
(12-02339 Freelandville East, Center Pit Mine)
Exhibit 96.1
TECHNICAL REPORT SUMMARY
COAL RESOURCES AND COAL RESERVES OAKTOWN
MINING COMPLEX
Indiana and Illinois
Prepared For
SUNRISE COAL, LLC
By
John T. Boyd Company
Mining and Geological Consultants
Pittsburgh, Pennsylvania, USA
Report No. 3467.008
MARCH 2025
JOHN T. BOYD COMPANY
TABLE OF CONTENTS
LETTER OF TRANSMITTAL
TABLE OF CONTENTS
GLOSSARY AND ABBREVIATIONS
1-2
Page
1.0
EXECUTIVE SUMMARY
1-1
1.1
Introduction
1-1
1.2
Property Description
1-1
1.3
Geology
1-3
1.4
Exploration
1-3
1.5
Coal Resources/Reserves
1-4
1.6
Operations
1-5
1.6.1
Mining
1-5
1.6.2
Processing
1-5
1.6.3
Other Infrastructure
1-6
1.7
Financial Analysis
1-6
1.7.1
Market Analysis
1-6
1.7.2
Capital and Operating Costs
1-7
1.7.3
Economic Analysis
1-7
1.8
Regulation and Liabilities
1-8
1.9
Conclusions
1-8
2.0
INTRODUCTION
2-1
2.1
Registrant and Purpose
2-1
2.2
Terms of Reference
2-1
2.3
Expert Qualifications
2-2
2.4
Principal Sources of Information
2-3
2.4.1
Site Visits
2-4
2.4.2
Reliance on Information Provided by the Registrant
2-4
2.5
Effective Date
2-4
2.6
Units of Measure
2-5
3.0
PROPERTY OVERVIEW
3-1
3.1
Description and Location
3-1
3.2
History
3-3
3.3
Property Control
3-3
3.3.1
Coal Ownership
3-4
3.3.2
Surface Ownership
3-4
JOHN T. BOYD COMPANY
1-3
3.4
Adjacent Properties
3-4
3.5
Regulation and Liabilities
3-5
3.6
Accessibility, Local Resources, and Infrastructure
3-6
3.7
Physiography
3-6
3.8
Climate
3-7
4.0
GEOLOGY
4-1
4.1
Regional Geology
4-1
4.2
Local Stratigraphy
4-2
4.2.1
McLeansboro Group
4-2
4.2.2
Carbondale Group
4-3
4.2.3
Racoon Creek Group
4-3
4.3
Coal Seam Geology
4-3
4.3.1
Lithology
4-3
4.3.2
Structure
4-5
4.3.3
Coal Quality
4-5
5.0
EXPLORATION DATA
5-1
5.1
Background
5-1
5.2
Procedures
5-1
5.2.1
Drilling
5-1
5.2.2
Coal Quality Sampling
5-2
5.2.3
Coal Washability Testing
5-4
5.2.4
Other Exploration Methods
5-4
5.3
Results
5-4
5.4
Data Verification
5-6
6.0
COAL RESOURCES AND RESERVES
6-1
6.1
Applicable Standards and Definitions
6-1
6.2
Coal Resources
6-2
6.2.1
Methodology
6-2
6.2.2
Criteria
6-3
6.2.3
Classification
6-3
6.2.4
Coal Resource Estimate
6-4
6.3
Coal Reserves
6-4
6.3.1
Methodology
6-4
6.3.2
Parameters and Assumptions
6-5
6.3.3
Classification
6-7
6.3.4
Coal Reserve Estimate
6-7
6.3.5
Validation
6-14
6.3.6
Reconciliation with Previous Coal Reserve Estimate
6-14
JOHN T. BOYD COMPANY
1-4
7.0
MINING OPERATIONS
7-1
7.1
Mining Method Description
7-1
7.2
Mine Equipment and Staffing
7-5
7.2.1
Mine Equipment
7-5
7.2.2
Staffing
7-6
7.3
Mine Production
7-7
7.3.1
Historical Mine Production
7-7
7.3.2
Forecasted Production
7-8
7.3.3
Mining Recovery and Dilution Factors
7-10
7.3.4
Expected Mine Life
7-10
7.4
Other Mining Considerations
7-11
7.4.1
Mine Design
7-11
7.4.2
Mining Risk
7-12
8.0
PROCESSING OPERATIONS
8-1
8.1
Overview
8-1
8.2
Historical Operation
8-2
8.3
Future Operations
8-2
8.4
Conclusion
8-5
9.0
MINE INFRASTRUCTURE
9-1
9.1
Mine Surface Facilities
9-1
9.2
Oaktown Complex Refuse Facility
9-2
10.0
MARKET ANALYSIS
10-1
10.1
Indiana Coal Industry Background
10-1
10.1.1 Coal Reserves
10-1
10.1.2 Coal Quality
10-2
10.1.3 Transportation
10-3
10.1.4 Production Evolution
10-4
10.1.5 Mining Methods
10-4
10.1.6 Coal Demand by Market
10-5
10.2
Sunrise Coal
10-7
10.2.1 Product Specifications
10-7
10.2.2 Primary Markets
10-7
10.2.3 Market Outlook
10-9
10.2.4 Future Sales
10-9
10.2.5 Price Forecast
10-9
11.0
CAPITAL AND OPERATING COSTS
11-1
11.1
Historical Financial Performance
11-1
11.2
Estimated Costs
11-3
11.2.1 Forecasted Production
11-4
11.2.2 Projected Operating Costs
11-5
11.2.3 Projected Capital Expenditures
11-5
12.0
ECONOMIC ANALYSIS
12-1
JOHN T. BOYD COMPANY
1-5
12.1
Approach
12-1
12.2
Assumptions and Limitations
12-2
12.3
Financial Model Results
12-3
12.4
Sensitivity Analysis
12-5
13.0
PERMITTING AND COMPLIANCE
13-1
13.1
Permitting Requirements and Status
13-1
13.2
Environmental Studies
13-3
13.3
Waste Disposal and Water Management
13-3
13.4
Compliance
13-3
13.5
Plans, Negotiations, or Agreements
13-4
13.6
Mine Closure
13-4
13.7
Local Procurement and Hiring
13-4
14.0
INTERPRETATION AND CONCLUSIONS
14-1
14.1
Findings
14-1
14.2
Significant Risks and Uncertainties
14-1
JOHN T. BOYD COMPANY
List of Tables
10.2
Quality Specifications for Indiana Coal Shipped to Domestic
10.7
Coal Quality Specifications for Sunrise Coal Shipped to Domestic
1-6
1.1
Coal Reserves Summary
1-4
3.1
Monthly Average Climate Data, Vincennes, Indiana
3-7
5.1
Indiana V Seam Thickness (feet) Statistics
5-4
5.2
Descriptive Statistics, Indiana V Seam Coal Quality
5-6
6.1
Coal Resource Classification Criteria
6-4
6.2
Estimated Coal Reserves by Mine as of 31 December 2024
6-9
6.3
Coal Reserves Summary
6-10
6.4
Coal Reserves Product Quality Summary
6-11
7.1
Projected Number of Operating CM Sections
7-5
7.2
Summary of Production Unit Equipment
7-5
7.3
Historical Employment
7-6
7.4
Historical Mine Production
7-7
7.5
Life-of-Mine Plan Coal Production Summary
7-9
7.6
Life-of-Mine Plan Coal Quality Summary
7-9
7.7
Mine Life Projection
7-11
10.1
Historical Indiana Production by County
10-1
Utilities in 2024
10-2
10.3
Indiana Coal Quality by County of Origin
10-2
10.4
Historical Indiana Coal Production and Mine Count
10-4
10.5
Distribution of Indiana Coal Shipments by Market Sector
10-6
10.6
Historical Indiana Coal Deliveries to Utility Market by Destination State
10-6
Utilities in 2024
10-7
10.8
Historical Sunrise Coal Deliveries to Utility Market by Destination State
10-8
10.9
Coal Price Forecast
10-11
11.1
Historical Financials
11-1
11.2
Estimate of Cash Operating Costs and Capital Expenditures
11-6
12.1
Annual Production and Cash Flow Forecast
12-4
12.2
Financial Results
12-3
12.3
DCF-NPV Results
12-3
12.4
After-Tax NPV12 Sensitivity Analysis
12-5
13.1
Summary of Current Permits
13-2
JOHN T. BOYD COMPANY
List of Figures
8.2
Generic Flowsheet, Dense Medium Cyclone/Spiral/Flotation, Oaktown
1-7
1.1
General Location Map
1-2
3.1
Map Showing General Layout and Mineral Control
3-2
4.1
Generalized Stratigraphic Chart, Southwestern Indiana
4-2
4.2
Map Showing Indiana V Seam Isopachs
4-4
5.1
Map Showing Drill Hole Locations Indiana V Seam
5-5
6.1
Relationship Between Coal Resources and Coal Reserves
6-2
6.2
Map Showing Product Yield Isopleths, Indiana V Seam
6-6
6.3
Map Showing Reserve Classification, Indiana V Seam
6-8
6.4
Map Showing Product Ash Isopleths, Indiana V Seam
6-12
6.5
Map Showing Product Sulfur Isopleths, Indiana V Seam
6-13
6.6
Reconciliation with Previous Coal Reserves Estimate
6-14
7.1
Room-and-Pillar Mining Method
7-1
7.2
Historic Mining Productivity Levels
7-8
8.1
Aerial Map Showing Oaktown Complex Preparation Plant Facilities
8-3
Complex Preparation Plant Facility
8-4
10.1
Indiana Coal Production by Mining Method
10-5
10.2
Future Coal Sales by Order Type
10-9
11.1
Historical Operating Costs by Mine
11-2
11.2
Oaktown Mining Complex Projected Saleable Production
11-4
JOHN T. BOYD COMPANY
1.0
EXECUTIVE SUMMARY
1.1
Introduction
Sunrise’s Oaktown Mining Complex is a mining complex that includes two underground room-and-pillar
(R&P) mines—the active Oaktown Fuels No. 1 Mine and the idled Oaktown Fuels No. 2 Mine, respectively
—and the Oaktown Complex Coal Preparation Plant (CPP). BOYD was retained by Sunrise to complete an
independent technical assessment of coal resource and coal reserve estimates for the Oaktown Mining
Complex.
BOYD’s findings as a result of the audit of Oaktown Mining Complex’s coal resource and coal reserve
estimates are based on our detailed examination of the supporting geologic, technical, and economic
information obtained from: (1) Sunrise files, (2) discussions with Sunrise personnel, (3) records on file with
regulatory agencies, (4) public sources, and (5) nonconfidential BOYD files.
This technical report identifies and summarizes the results of our audit of the Oaktown Mining Complex coal
reserves and independent assessment of the economic viability of extracts of the Oaktown Mining Complex
coal reserves over the life of the mine and satisfies the requirements for Sunrise’s disclosure of coal reserves
set forth in Subpart 1300 and Item 601(b)(96) of the SEC's Regulation S-K (S-K 1300). This is the second
technical report summary for the Oaktown Mining Complex. BOYD is a qualified person as defined in
Regulation S-K 1300.
Weights and measurements are expressed in U.S. customary units. Unless noted, the effective date of the
information, including estimates of coal reserves, is December 31, 2024.
1.2
Property Description
The Oaktown Mining Complex is an active underground coal mining and processing operation located in
Knox and Sullivan counties, Indiana, and Lawrence County, Illinois. The general location of the Oaktown
Mining Complex is provided in Figure 1.1, following this page. The project lies in a well-developed region
with a robust infrastructure.
1-1
JOHN T. BOYD COMPANY
Figure 1.1
1-2
JOHN T. BOYD COMPANY
Located within the ILB coal-producing region of the midwestern U.S., the Oaktown Mining Complex is one
of the largest underground R&P coal mining complexes in North America.
The Oaktown Mining Complex mines coal exclusively from the Indiana V Seam (Illinois No. 5 Springfield
Seam). Within the Oaktown Mining Complex mine plan boundaries, Sunrise currently maintains the right to
mine and remove approximately 95% of the Indiana V Seam through lease agreements. Several small adverse
(uncontrolled) tracts exist within the proposed life-of-mine (LOM) plan; however, Sunrise has demonstrated
success in acquiring these as required during the ordinary course of business. BOYD is not aware of any
encumbrances, litigation, or orders that would hinder the continued development of the property.
The Indiana V Seam has been extensively mined in the ILB region and is one of two predominant coal seams
of economic interest. Sunrise has demonstrated a history of successfully mining the Indiana V Seam at the
Oaktown Mining Complex, with initial mining at the complex dating to 2009.
1.3
Geology
The Oaktown Mining Complex is situated in the Carbondale Group (Formation) of the Pennsylvania System.
Near-surface geology of this area primarily consists of the overlying Quarternary System. Coal seams mined
in this region are generally classified as medium- to high-sulfur content and moderate ash thermal coal
products.
The Indiana V Seam is the only coal seam of economic interest on the property. Structurally, the Indiana V
Seam consists of a singular and relatively consistent horizon averaging between 4 ft to 8 ft thick containing
little in-seam parting. The Indiana V Seam globally dips in the general westerly direction and experiences
localized areas where the seam elevations vary. Pronounced gradients can occur periodically in the form of
rolls in the seam. Depths for the Indiana V Seam range from approximately 300 ft to 450 ft below ground
surface within the Oaktown Mining Complex area.
The Indiana V Seam coal bed is characterized as high sulfur and moderate ash coal that is used for steam
purposes.
1.4
Exploration
The Indiana V Seam has been extensively explored and mined in the region, with drilling records dating prior
to the inception of the Oaktown Mining Complex. Sunrise provided data for 1,935 drill holes that have
intercepted the Indiana V Seam and have been complied for defining the
1-3
JOHN T. BOYD COMPANY
lateral extent, thickness, and qualities (both raw and clean) of the Indiana V Seam in the immediate Oaktown
Mining Complex project area.
BOYD’s audit indicates that in general: (1) Sunrise has performed extensive drilling and sampling work on
the subject property, (2) the work completed has been done by competent personnel, and (3) the amount of
data available combined with wide-spread knowledge of the Indiana V Seam, is sufficient to confirm the
thickness, lateral extents, and quality characteristics of the Indiana V Seam.
1.5
Coal Resources/Reserves
Sunrise’s estimated underground mineable coal reserves for the Oaktown Mining Complex total 34.4 million
recoverable (clean) product tons remaining as of December 31, 2024. The coal reserves controlled by Sunrise
are summarized in Table 1.1.
1-4
JOHN T. BOYD COMPANY
It is BOYD’s opinion that extraction of the reported coal reserves is technically achievable and economically
viable after the consideration of potentially material modifying factors. Periodic amendments to existing
mining permits to add additional acreage (reserve tonnage) in order to sustain coal production is common
practice. We are not aware of any issues that would impact or prevent the present “Not Permitted” reserves to
be permitted as future mining needs dictate. We are also not aware of any prohibition against the proposed
mining and processing activities.
There are no reportable coal resources excluding those converted to coal reserves for the Oaktown Mining
Complex.
1.6
Operations
1.6.1
Mining
The Oaktown Mining Complex is comprised of the Oaktown Fuels No. 1 and Oaktown Fuels No. 2
underground mines. Each mine utilizes R&P mining (employing continuous miners [CMs]) for primary
production. This mining method is highly productive and commercially demonstrated; it has been one of the
primary approaches to mining the Indiana V Seam for decades. Oaktown Mining Complex has utilized this
mining method since the inception of each operation. To date, Oaktown Mining Complex has produced a
combined 58.3 million tons of clean coal. The complex is configured to operate up to six CM sections, with
an annual production target of approximately 6 million product tons. The Oaktown Mining Complex is
generally considered an industry leader in terms of mining productivity and mining costs when compared to
other R&P underground operations.
It is BOYD’s opinion that the forecasted production levels for the Oaktown Mining Complex operations are
reasonable, logical, and consistent with typical R&P mining practices in the Indiana V Seam and historical
practices utilized by Sunrise. The Oaktown Mining Complex LOM plans developed by BOYD show a
relatively stable production output until individual production sections are retired corresponding to reserve
exhaustion. In the aggregate, the Oaktown Mining Complex LOM plan projects the complex will produce
approximately 57.1 million tons of run-of-mine (ROM) coal (34.4 million saleable tons after processing)
during the next 11 years (through 2035).
1.6.2
Processing
The Oaktown Complex CPP serves as the coal washing facility for the Oaktown Mining Complex’s two R&P
mines. The plant was commissioned in 2009 to wash coal produced by the Oaktown Fuels No. 1 Mine. The
Oaktown Complex CPP has a current processing capacity of 1,600 raw tons-per-hour (TPH).
1-5
JOHN T. BOYD COMPANY
The beneficiation process utilized at the Oaktown Mining Complex has a proven performance record and has
remained relatively unchanged for decades. The plant’s ability to blend raw coal production from the two
underground mines into a singular plant feed allows for both more consistent plant operation and the ability to
achieve differing clean coal qualities for various customer specifications.
1.6.3
Other Infrastructure
The Oaktown Mining Complex underground mines and CPP are supported by several surface infrastructure
sites. Major surface infrastructure includes ancillary buildings, high-voltage power distribution stations, ROM
coal conveyor belts, CPP refuse facilities, underground access and ventilation structures, and truck/rail
loading systems.
Product coal from the Oaktown Mining Complex is transported to its customer base via rail, truck, or a
combination of both. The Oaktown Complex CPP is served by both the CSX Railroad and Indiana Railroad
(INRD) via a rail spur and rail loop that connects the complex with the mainline rail just north of Oaktown,
Indiana. Additionally, the Oaktown Complex CPP can facilitate the loading of trucks for direct transport to
select customers, or to Sunrise’s transload facility in Princeton, Indiana serviced by the Norfolk Southern
(NS) Railroad.
The Oaktown Complex refuse facility serves as the disposal location for all waste rock (coarse coal refuse)
and portions of the fine coal slurry (fine coal refuse) produced during the processing of coal. The majority of
the fine coal slurry is transported overland via a network of pumps and pipelines for underground disposal
within mined-out void areas of the Oaktown Fuels No. 1 and No. 2 mines.
1.7
Financial Analysis
1.7.1
Market Analysis
The Oaktown Mining Complex’s product is thermal coal that is directed into the U.S. coal-fired generation
market. Historically, this market accounts for all of the Oaktown Mining Complex annual sales.
Coal use among domestic power generators has fallen out of favor in several of the individual states of the
U.S. and is being replaced by natural gas and renewable forms of generation. However, several states are
positioned to remain largely reliant upon coal for power generation, such as Indiana. Sunrise anticipates its
geographical location, reputation for sustained production, and well-capitalized infrastructure well position
the complex to continue supplying coal into the Indiana market and other domestic coal markets when
opportunities present.
1-6
JOHN T. BOYD COMPANY
1.7.2
Capital and Operating Costs
The ILB is widely recognized as being ideally suited for commercial scale mining through R&P mining
methods. The region’s Indiana V Seam is conducive to efficient, low-cost production R&P operations. In
terms of total dollars expended per year, cash operating costs for R&P mines contain a mixture of variable
and fixed costs. Unit costs, therefore, will vary mostly due to changes in production and less so with regard to
general inflation and major mine site changes.
During the historical review period of 2020 through 2024, total cash operating costs per saleable ton for the
Oaktown Mining Complex were within the range of $30 to $47 per saleable ton. Cash operating costs for the
complex were approximately $8.45 per ton higher in 2024 than 2023, primarily due to significant increases in
direct labor and direct operating costs due to one-time reduction in workforce expenses.
While each of the individual mines may have realized higher or lower operating costs annually, their
operation in parallel aids in the complex’s ability to minimize short-term periods of individual mine coal
production decreases and/or increases in operating costs.
The Oaktown Mining Complex is regarded as being well-capitalized comparatively to industry peers.
Continual capital expenditures have been ongoing by Sunrise in recent years to support mine infrastructure
expansions, maintenance of production equipment, refuse placement, etc. Notwithstanding the significant
capital expenditures of 2022 and 2023 for major equipment rebuilds, Oaktown Mining Complex’s aggregate
capital expenditure level was relatively consistent and generally within the range of $4.00 to $5.00 per clean
ton.
BOYD found Sunrise’s forecasted operating and capital costs to be indicative of the complex’s historical
performance and in general agreement with BOYD’s independent LOM forecasts.
1.7.3
Economic Analysis
The results of our indicative economic analysis for Oaktown Mining Complex over the 11-year period (2025
to 2035) shows an after-tax net present value (NPV) of $70.7 million for the expected case at a 12% discount
rate. The coal sales price estimated over the life of the reserves averages approximately $48.72 (ranging from
$47.25 to $51.47).
The NPV estimate was made for purposes of confirming the economic viability of the reported coal reserves
and not for purposes of valuing Sunrise or its assets. Internal rate-of-return (IRR) and project payback were
not calculated, as there was no initial investment considered in the financial model.
1-7
JOHN T. BOYD COMPANY
While BOYD concludes that the stated coal reserves are economically viable under reasonable financial
assumptions and market price expectations, we note that the project is sensitive to fluctuations in coal sales
prices and/or operating costs and is marginal or uneconomic under some scenarios.
1.8
Regulation and Liabilities
Multiple permits are required by federal and state law for underground mining, coal preparation and related
facilities, and other incidental activities. Sunrise reports that all necessary permits to support current
operations are in place or pending approval. New permits or permit revisions may be necessary from time to
time to facilitate future operations. Given sufficient time and planning, Sunrise should be able to secure new
permits, as required, to maintain its planned operations within the context of the current regulations.
Permits generally require that Sunrise post a performance bond in an amount established by the regulator
program to: (1) provide assurance that any disturbance or liability created during mining operation is properly
mitigated, and (2) assure that all regulation requirements of the permit are fully satisfied. Sunrise reports
holding surety bonds to cover its current obligations relating to mining and reclamation, road repair, etc.
Those obligations currently equate to $6.7 million.
1.9
Conclusions
It is BOYD’s overall conclusion that Sunrise’s estimates of coal reserves, as reported herein: (1) were
prepared in conformance with accepted industry standards and practices, and (2) are reasonably and
appropriately supported by technical evaluations, which consider all relevant modifying factors. We do not
believe there is other relevant data or information material to the Oaktown Mining Complex that would render
this technical report summary misleading. Our conclusions represent only informed professional judgment.
Given the operating history and status of evolution, residual uncertainty for this project is considered minor
under the current and foreseeable operating environment. A general assessment of risk is presented in the
relevant sections of this report.
The ability of Sunrise, or any mine operator, to recover all of the reported coal reserves is dependent on
numerous factors that are beyond the control of, and cannot be anticipated by, BOYD. These factors include
mining and geologic conditions, the capabilities of management and employees, the securing of required
approvals and permits in a timely manner, future coal prices, etc. Unforeseen changes in regulations could
also impact performance. Opinions presented
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JOHN T. BOYD COMPANY
in this report apply to the site conditions and features as they existed at the time of BOYD’s investigations
and those reasonably foreseeable.
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JOHN T. BOYD COMPANY
2.0
INTRODUCTION
2.1
Registrant and Purpose
This technical report summary was prepared for Hallador Energy (Hallador) in support of their disclosure of
their subsidiary, Sunrise’s, coal resources and coal reserves for the Oaktown Mining Complex.
Hallador is a US-based energy solutions company headquartered in Terre Haute, Indiana, and is listed on the
National Association of Securities Dealers Automated Quotations (NASDAQ:HNRG) stock exchange. A large
portion of Hallador’s business focuses upon coal mining through their subsidiary Sunrise. Sunrise is actively
engaged in the production and export of thermal coal from mines located in the ILB. The company also owns
and operates the Princeton Rail Loop, which is located near Princeton, Indiana on the NS Railroad. Additional
information regarding Hallador (and Sunrise) can be found on their website at www.halladorenergy.com.
2.2
Terms of Reference
Sunrise retained BOYD to complete an independent technical assessment of mineral resource and mineral
reserve estimates and supporting information for the Oaktown Mining Complex. Our objective was to obtain
reasonable assurance that the coal resource and coal reserve statements for Oaktown Mining Complex are free
from material misstatement.
The results of our third-party study, presented in report form herein, were prepared in accordance with the
disclosure requirements set forth in Subpart 1300 and Item 601(b)(96) of the SEC’s Regulation S-K. The
purpose of this report is: (1) to summarize available information for the subject mining properties, (2) to
provide the conclusions of our technical assessment, (3) to provide a statement of coal resources and/or coal
reserves for the Oaktown Mining Complex, and (4) provide our conclusion of the economic viability of the
Oaktown Mining Complex’s coal reserves. This is the second technical report summary filed by Sunrise for
the Oaktown Mining Complex.
BOYD’s findings are based on our detailed examination of the supporting geologic and other scientific,
technical, and economic information provided by Sunrise, as well as our assessment of the methodology and
practices applied by Sunrise in formulating the estimates of coal resources and coal reserves disclosed in this
report. We did not independently estimate coal resources or coal reserves from first principles.
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JOHN T. BOYD COMPANY
We used standard engineering and geoscience methods, or a combination of methods, that we considered to
be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of mining property
evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore,
our conclusions necessarily represent only informed professional judgment.
The ability of Sunrise, or any mine operator, to recover all of the estimated coal reserves presented in this
report is dependent on numerous factors that are beyond the control of, and cannot be anticipated by, BOYD.
These factors include mining and geologic conditions, the capabilities of management and employees, the
securing of required approvals and permits in a timely manner, future coal prices, etc. Unforeseen changes in
regulations could also impact performance. Opinions presented in this report apply to the site conditions and
features as they existed at the time of BOYD’s investigations and those reasonably foreseeable.
This report is intended for use by Sunrise subject to the terms and conditions of its professional services
agreement with BOYD. The agreement permits Sunrise to file this report as a technical report summary with
the SEC pursuant to Subpart 1300 and Item 601(b)(96) of Regulation S-K. Except for the purposes legislated
under U.S. securities law, any other uses of our reliance on this report by any third party is at that party’s sole
risk. The responsibility for this disclosure remains with Sunrise. The user of this document should ensure that
this is the most recent disclosure of coal resources and coal reserves for the subject property as it is no longer
valid if more recent estimates have been issued.
2.3
Expert Qualifications
BOYD is an independent consulting firm specializing in mining-related engineering and financial consulting
services. Since 1943, BOYD has completed over 4,000 projects in the United States and more than 60 other
countries. Our full-time staff comprises mining experts in: civil, environmental, geotechnical, and mining
engineering; geology; mineral economics; and market analysis. Our extensive experience in coal
resources/reserve estimation and our knowledge of the subject coal properties, provides BOYD an informed
basis on which to opine on the reasonableness of the estimates provided by Sunrise. An overview of BOYD
can be found on our website at www.jtboyd.com.
The individuals primarily responsible for this independent technical assessment and the preparation of this
report are by virtue of their education, experience, and professional association considered qualified persons
as defined in Subpart 1300 of Regulation S-K.
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JOHN T. BOYD COMPANY
Neither BOYD nor its staff employed in the preparation of this report have any beneficial interest in
Sunrise, and are not insiders, associates, or affiliates of Sunrise. The results of our audit were not
dependent upon any prior agreements concerning the conclusions to be reached, nor were there
any undisclosed understandings concerning any future business dealings between Sunrise and
BOYD. This report was prepared in return for fees based upon agreed commercial rates, and the
payment for our services was not contingent upon our opinions regarding the project or approval of
our work by Sunrise and its representatives.
2.4
Principal Sources of Information
Information used in this assignment was obtained from: (1) Sunrise files, (2) discussions with Sunrise
personnel, (3) records on file with regulatory agencies, (4) public sources, and (5) nonconfidential BOYD
files.
The following information was provided by Sunrise:
●
Year-end reserve statements and reports for 2024.
●
Exploration records (e.g., drilling logs, lab sheets).
●
Geologic databases of lithology and coal quality.
●
Computerized geologic models.
●
Mapping data, with:
-
Mineral tenure boundaries.
-
Permit boundaries.
-
Limits of previous mining.
●
LOM plans and supporting documentation.
●
Financial forecasting models.
●
Historical information, including:
-
Production reports and reconciliation statements.
-
Financial statements.
-
Product sales and pricing.
Information from sources external to BOYD and/or Sunrise are referenced accordingly.
The data and work papers used in the preparation of this report are on file in our offices.
2.4.1
Site Visits
A personal inspection of the Oaktown Fuels No. 1 and No. 2 mines was made by two of BOYD’s senior
mining engineers—qualified persons and co-authors of this report—on December 2, 2021.
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JOHN T. BOYD COMPANY
The site visit included: (1) observation of both mine’s active underground workings, belt lines, outby areas,
and portal (mine access) locations; (2) a tour of the mine site’s surface infrastructure; and (3) a tour of the
Oaktown Complex CPP, truck and rail loadout, and refuse disposal facility. BOYD’s representatives were
accompanied by senior Sunrise management personnel who openly and cooperatively answered questions
regarding, but not limited to: site geology, mining conditions and operations, equipment usage, labor
relations, operating and capital costs, current coal washing operations, and coal marketing.
2.4.2
Reliance on Information Provided by the Registrant
In the preparation of this report we have relied, without independent verification, upon information furnished
by Sunrise with respect to: property interests; exploration results; current and historical production from such
properties; current and historical costs of operation and production; and agreements relating to current and
future operations and sale of production.
BOYD exercised due care in reviewing the information provided by Sunrise within the scope of our expertise
and experience (which is in technical and financial mining issues) and concluded the data are valid and
appropriate considering the status of the subject properties and the purpose for which this report was
prepared. BOYD is not qualified to provide findings of a legal or accounting nature. We have no reason to
believe that any material facts have been withheld, or that further analysis may reveal additional material
information. However, the accuracy of the results and conclusions of this report are reliant on the accuracy of
the information provided by Sunrise.
While we are not responsible for any material omissions in the information provided for use in this report, we
do not disclaim responsibility for the disclosure of information contained herein which is within the realm of
our expertise.
2.5
Effective Date
The effective (i.e., “as of”) date of this report is December 31, 2024. The estimates of coal resources and coal
reserves and supporting information presented in this report are effective as of December 31, 2024.
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JOHN T. BOYD COMPANY
2.6
Units of Measure
The U.S. customary measurement system has been used throughout this report. Tons are short tons of 2,000
pounds-mass. Unless otherwise stated, currency is expressed in U.S. Dollars ($). Historic prices and costs are
presented in nominal (unadjusted) dollars. Future dollar values are expressed on a constant (unescalated) basis
as of the effective date of this report.
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JOHN T. BOYD COMPANY
3.0
PROPERTY OVERVIEW
3.1
Description and Location
The Oaktown Mining Complex is a coal mining and processing operation located in Knox and Sullivan
counties, Indiana, and Crawford and Lawrence counties, Illinois. Comprising almost 118 square miles within
the ILB coal-producing region of the midwestern U.S., the Oaktown Mining Complex is one of the largest
underground R&P coal mining complexes in North America. The Oaktown Mining Complex operations
currently consist of the active Oaktown Fuels No. 1 underground mine, the recently idled Oaktown Fuels No.
2 underground mine, and related coal processing facilities and other infrastructure.
While each of the two mines have a unique Mine Safety and Health Administration (MSHA) mine
identification number and has a separate direct management team, the Oaktown Mining Complex is
commercially operated as a single entity. All mine output is delivered by belt conveyors to a central coal
processing facility, the Oaktown Complex CPP, that is rated at 1,600 raw TPH and reports to MSHA under its
own identification number. The ROM coal is segregated by mine, and refined analysis and processing systems
are utilized to meet customer specifications. Plant reject-material reports to the coarse and fine refuse disposal
facilities or is placed into abandoned mine void areas through slurry (fine refuse) injection. Saleable output is
shipped to a diverse customer base via truck or rail facilitated by the rail load-out on a dedicated rail spur
serviced by CSX and INRD.
The Oaktown Mining Complex is located approximately 44 miles south of Terre Haute, Indiana near the town
of Oaktown, Indiana. The city of Vincennes, Indiana lies about 14 miles to the southwest. The project area is
essentially bisected by U.S. Route 41.
Geographically, the Oaktown Complex CPP is located at approximately 38°51’24.7” N latitude and
87°25’30.9” W longitude. Figures 1.1 (page 1-2) and 3.1, following this page, illustrate the location and
general layout of the Oaktown Mining Complex.
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JOHN T. BOYD COMPANY
Figure 3.1
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JOHN T. BOYD COMPANY
3.2
History
Vectren Fuels was the original developer of the property. Construction of the Oaktown Fuels No. 1 Mine
slope, surface mine infrastructure, and CPP began in 2008. Following development of the slope, commercial
coal production began in 2009. Processing of the Oaktown Fuels No. 1 Mine coals was facilitated by the then
800 raw feed TPH capacity CPP. Development of Oaktown Fuels No. 2 Mine followed shortly after, with
commercial coal production beginning in 2013. The commercial production status of Oaktown Fuels No. 2
Mine coincided with the expansion of the CPP’s 800 TPH capacity to its present 1,600 TPH capacity.
Sunrise’s involvement with the Oaktown Mining Complex dates to 2014 with the acquisition of Oaktown
Fuels No. 1 and No. 2 mines from Vectren Fuels. Sunrise steadily increased annual production from the
Oaktown Mining Complex—averaging between 6 to 7 million product tons annually between 2017 and 2023.
The mine workings have substantially grown since 2014, and both mines have installed new shafts (mine
accesses) for employee ingress/egress from the active production faces. The new Oaktown Fuels No. 1 Mine
portal location is approximately 4.5 miles southeast of the town of Oaktown, Indiana while the new Oaktown
Fuels No. 2 Mine portal location is approximately 1.5 miles northwest of the village of Russellville, Illinois.
The Oaktown Fuels No. 2 Mine was idled in February 2024 as part of a restructuring to strengthen financial
and operational efficiency.
There are no significant Indiana V Seam mining activities known to have occurred within the Oaktown
Mining Complex boundarys preceding Vectren Fuel’s and Sunrise’s involvement.
3.3
Property Control
Within the Oaktown Mining Complex area and immediate vicinity, Sunrise controls approximately 59,000
acres of mineral rights. This control exists as a complex collection of leases that apply to thousands of
individual tracts. Each of which range from less than an acre to several hundred acres in size. Ownership of
the surface rights and the mineral rights is often severed for the properties and the estates are often fractional,
in which mineral rights are split between several owners. Sunrise and its predecessors have acquired the
necessary rights to support development and operations through purchase or lease agreements with
predominantly private owners or entities.
BOYD has not independently verified ownership of the Oaktown Mining Complex area and the underlying
property agreements. Ownership data provided to BOYD, including maps and summaries of lease
agreements, have been accepted as being true and accurate for the purpose of this report.
3.3.1
Coal Ownership
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JOHN T. BOYD COMPANY
Sunrise currently controls approximately 95% of the coal within projected mine plan boundaries through lease
agreements with the balance currently reported as adverse. Reportedly, lease terms generally extend until all
the coal is removed from the subject tract. Where applicable, royalty rates are typically based upon a
percentage of the gross sales price of the coal. No material amounts of mineral within the Oaktown Mining
Complex mine plan boundaries is owned in fee.
Adverse (uncontrolled) tracts within the project limits are common; however, it is generally reasonable to
assume that such tracts can be acquired or leased in the ordinary course of business as has been demonstrated
historically by Sunrise. It is BOYD’s opinion that adverse coal control does not pose a material risk to the
estimate of coal reserves reported herein.
3.3.2
Surface Ownership
As part of the Oaktown Mining Complex, Sunrise controls surface rights through fee simple ownership for
over 1,700 permitted acres. Upon those acres resides the surface facilities for mine accesses, processing,
storing, shipping, and refuse disposal facilities (i.e., refuse impoundment site and fine refuse injection sites).
Sunrise reports it controls adequate surface rights to sustain current mining operations in the near term.
Additional surface property will likely be required during the life of the mine for the placement of additional
infrastructure. It is generally reasonable to assume the required property can be acquired or leased in the
ordinary course of business; as such, we do not believe there is any undue risk associated with surface
ownership to the estimated reserves reported herein.
3.4
Adjacent Properties
As illustrated in Figures 1.1 and 3.1, there are no other operating mines or mines/properties controlled by
Sunrise adjacent to the Oaktown Mining Complex. As shown, some existence of Indiana V Seam mining has
taken place near the Oaktown Mining Complex to the northeast. Sunrise’s mine plans include sufficient
barrier zones to mitigate any risk associated with prior mining activities of the adjacent properties.
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JOHN T. BOYD COMPANY
3.5
Regulation and Liabilities
Mining and related activities on the Oaktown Mining Complex properties are regulated by both federal and
state laws. The relevant federal laws include:
●
Clean Air Act of 1970/1977.
●
Clean Air Act Amendments of 1990.
●
Clean Water Act of 1977.
●
Surface Mining Control and Reclamation Act of 1977.
●
Resource Conservation and Recovery Act of 1976.
In Indiana and Illinois, responsibility for enforcing these acts, with the aid of numerous state laws and
legislative rules, lies with Illinois’s Environmental Protection Agency (IL-EPA) and Indiana’s Department of
Natural Resources (IN-DNR).
As mandated by these laws and regulations, numerous permits are required for underground mining, coal
preparation and related facilities, and other incidental activities. Sunrise reports that necessary permits are in
place or applied for to support current operations. New permits or permit revisions may be necessary from
time to time to facilitate future operations. Given sufficient time and planning, Sunrise should be able to
secure new permits, as required, to maintain its planned operations within the context of the current
regulations.
Permits generally require that the permittee post a performance bond in an amount established by the
regulator program to: (1) provide assurance that any disturbance or liability created during mining operation
is properly mitigated, and (2) assure that all regulations requirements of the permit are fully satisfied. Sunrise
reports holding surety bonds to cover its current obligations relating to mining and reclamation, road repair,
etc. Those obligations currently equate to $6.7 million.
Regular inspection of the mines and related facilities are conducted by MSHA for health and safety
compliance. On finding any violation of a health or safety standard, an inspector will issue a citation that
specifies the standard violated and evaluates the gravity of the violation by several factors, including
likelihood of injury. Any infraction that is reasonably likely to result in a serious injury or illness or is caused
by the operator's unwarrantable failure to comply with regulatory requirements will carry additional fines and
could result in temporary closure. Typically, the civil penalties for regular assessments are not considered
material.
BOYD is not aware of any prohibition of mining and processing activities for the Oaktown Mining Complex.
However, the reported coal reserves may be materially impacted by: Sunrise’s failure to comply with permit
conditions and rules; delays in obtaining required government or
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JOHN T. BOYD COMPANY
other regulatory approvals or permits; Sunrise’s inability to obtain such required approvals or permits; or
changes in governmental regulations.
3.6
Accessibility, Local Resources, and Infrastructure
The Oaktown Mining Complex lies within a rural but well-developed region of southwestern Indiana and
southeastern Illinois, with an extensive history related not only to coal mining, processing, and transportation,
but also many other industries and services. A reported 1.4 million people live within 75 miles of the
Oaktown Mining Complex, according to the U.S. Census of 2020.
General access to the Oaktown Mining Complex is via a well-developed network of primary and secondary
roads serviced by state and local governments. These roads offer direct access to the mine and processing
facilities and are generally open year-round.
Coal produced at the Oaktown Mining Complex is transported primarily by rail, truck, or a combination of
both. A rail load-out facility and dedicated rail spur loop facilitate transportation of the coal on the INRD and
CSX railroads. Additionally, Oaktown Mining Complex can facilitate the loading of trucks for direct transport
to select customers, or to Sunrise’s transload facility in Princeton, Indiana serviced by the NS Railroad.
Several regional airports are located near the Oaktown Mining Complex and the Indianapolis International
Airport is located approximately 100 miles northeast of the complex.
Sources of electrical power, water, supplies, and materials are readily available. Electrical power is provided
to the mines and facilities by regional utility companies. Water is supplied by public water services, surface
impoundments, or water wells.
3.7
Physiography
The Oaktown Mining Complex lies within the Southern Hills and Lowland areas of the Southwest Indiana
region. This region is characterized by relatively flat topography possessing gentle gradients associated with
drainages. Surface elevations within the Oaktown Mining Complex area range from approximately 410 ft to
590 ft above mean sea-level. The region possesses a network of overlying tributaries and waterways flowing
to the Wabash River; all of which overlay the complex area.
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JOHN T. BOYD COMPANY
Land cover within the area consists predominantly of mixed crop/pastureland and forest dotted with medium-
to low-density (rural) residential areas.
3.8
Climate
Climate in and around the Oaktown Mining Complex is typical of southwestern Indiana, with four distinct
seasons: cold winters; hot and humid summers; and mild falls and springs.
Over the course of the year, the temperature typically varies from 24°F to 87°F and is rarely below 7°F or
above 94°F. The hot season lasts from late-May to late-September, with an average daily high temperature
above 78°F. The hottest month of the year is July, with an average high of 87°F and low of 68°F. The cold
season lasts from early-December to late-February, with an average daily high temperature below 49°F. The
coldest month of the year is January, with an average low of 25°F and high of 40°F.
The area experiences on average 46 in. of rain and 9 in. of snowfall per year. Adverse weather conditions
seldom limit the Oaktown Mining Complex coal mining, processing, and loading operations; however,
extreme weather conditions may temporarily impact operations.
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JOHN T. BOYD COMPANY
4.0
GEOLOGY
4.1
Regional Geology
The Oaktown Mining Complex is located within the eastern portion of the ILB region, a sedimentary basin
which coal-bearing areas cover approximately 50,000 square miles across the majority of Illinois,
southwestern Indiana and portions of western Kentucky. The coal bearing members of the ILB consist of
Pennsylvanian rocks, formed approximately 290 – 330 million years ago. The Indiana VI (Herrin) and Indiana
V (Springfield) seams are accredited with the vast majority of the economically mineable coals within the
ILB.
The ILB has informally been subdivided into eight mining regions—Northern Illinois, Western Illinois, West-
central Illinois, East-central Illinois, Southwestern Illinois, Southeastern Illinois, Southwestern Indiana, and
Western Kentucky. The majority of current coal mining from the ILB occurs within the West-central Illinois,
Southeastern Illinois, Southwestern Illinois, Southwestern Indiana, and Western Kentucky regions. The
Oaktown Mining Complex is located within the Southwestern Indiana region of the ILB.
There are three predominant structural features within the ILB which include the DuQuoin monocline, La
Salle anticlinal belt, and the Cottage Grove-Rough Creek fault system. The features surround the Fairfield
Basin area which contain the deepest extents of the ILB. The DuQuoin monocline on the west, the La Salle
anticlinal belt on the north, and the Cottage Grove-Rough Creek fault system on the south, all flank the
Fairfield Basin. In general, the Illinois and Indiana portions of the ILB dip gently towards the interior,
Fairfield Basin. The Southwestern Indiana mining region, in which the Oaktown Mining Complex is located,
experiences localized rolling of the coal seams but predominately dips in a westerly direction.
The Carbondale Formation is the primary coal-bearing formation containing the majority of the ILB
economically mineable bituminous coals. The Indiana VI (Herrin) and Indiana V (Springfield) seams that are
heavily exploited within the ILB, are typically between 2 ft and 6 ft in thickness. Coal in the region is
classified as high-volatile bituminous with rank increasing to the south. Sulfur content is generally related to
the overlying strata of the coals within the ILB. Generally, coals possess sulfur contents ranging from 3% to
5% and heating values above 11,000 Btu/lb.
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JOHN T. BOYD COMPANY
4.2
Local Stratigraphy
Pennsylvanian sedimentary strata comprise the uppermost stratigraphic units of bedrock in and around the
Oaktown Mining Complex. These units primarily include bedrock of, in descending stratigraphic order, the
McLeansboro, Carbondale, and Racoon Creek Group.
The strata of the Pennsylvanian system are predominantly clastic and contain subordinate amounts of coal and
limestone. The Indiana V (Springfield) coal seam resides within the Carbondale Group, specifically the
Petersburg formation. The stratigraphic relationship between these groups is presented in Figure 4.1 as
follows.
4.2.1
McLeansboro Group
The McLeansboro Group ranges in thickness of approximately 150 to 750 ft; beginning with the Mattoon
Formation. The uppermost Mattoon Formation is predominately formed of sandstone and/or conglomerate
type rocks. The remaining Bond, Patoka, and Shelburn formations, in descending stratigraphic order, are
characterized by sequences of shale, mudstone, and siltstone with interspersed limestones. The predominant
limestones of presence are the Livingston, Carthage, Vigo, and West Franklin. There are no bituminous coal
beds present possessing economic value.
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JOHN T. BOYD COMPANY
4.2.2
Carbondale Group
The Carbondale Group extends from the Indiana VII (Danville) coal seam to the base of the Indiana III
(Seelyville) coal seam. The unit is divided into the Dugger, Petersburg, and Linton formations. The
Carbondale Group is a sedimentary sequence of non-marine rocks (sandstone, siltstone, mudstone, shale,
limestone, and coal) ranging in thickness from approximately 300 ft to 450 ft. Regionally, the Carbondale
Group contains several commercial coal beds, including the Indiana VII (Danville), Indiana VI (Herrin),
Indiana V (Springfield) and others; however, within the vicinity of the Oaktown Mining Complex, only the
Indiana V Seam is of economic interest. The Indiana V coal seam possesses moderate continuity (instances of
sandstone paleochannel erosion) and ideal mining thickness (4 ft to 8 ft).
4.2.3
Raccoon Creek Group
The Raccoon Group includes all strata below the base of the Indiana III (Seelyville) coal bed. It is made up
of Staunton, Brazil, and Mansfield formations. The Raccoon Group reaches a maximum thickness of about
1,000 ft in southwestern Indiana. Strata of the group are very similar to those of the overlying Carbondale
Group, except that the Raccoon Creek Group contains coal beds of little or no commercial value.
4.3
Coal Seam Geology
The Indiana V Seam is the only coal seam of economic interest within the Oaktown Mining Complex. The
Indiana V Seam is fairly uniform in depositional nature (typically 4 ft to 8 ft thickness) and continuity
throughout much of the project’s surrounding area.
4.3.1
Lithology
The Indiana V Seam coal bed is relatively consistent containing a singular interval of coal within minimal in-
seam partings. Mining methods employed at the Oaktown Mining Complex generally extract the entirety of
the coal seam with minimal out-of-seam (OSD) dilution.
The coal thickness across the Oaktown Mining Complex area is generally between the 4.0 ft to 8.0 ft range,
averaging 4.8 ft over the extents of mine plan areas. Isolated pockets of both thinner and thicker coal do exist,
and extreme but generally isolated occurrences may range from less than a foot to above 12 ft thick. Figure
4.2, following this page, provides a map of the Indiana V Seam thickness. The locations of thinner coal
occurrences are generally well-defined by the extensive exploration performed in and around the study area,
and mine plans have been developed to avoid these low coal occurrences.
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JOHN T. BOYD COMPANY
Figure 4.2
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JOHN T. BOYD COMPANY
The immediate roof overlying the Indiana V Seam coal bed generally consists of interbedded shales and
sandy shales. Occasional instances of sandstone roof can occur within the project area, where paleochannel
sandstone fill has scoured and replaced part or all the normal roof strata. The most prominent existence of
paleochannel sandstone fill resides within the sandstone channel that divides the Oaktown Fuels No. 1 and
No. 2 mines mineable reserves. Other, less prominent, localized paleochannelization eroding of the typical
roof strata and possibly portions of the Indiana V Seam are likely to be found within the Oaktown Mining
Complex mineable reserves. Areas of the deposit with sandstone channels in close proximity to the Indiana V
Seam commonly exhibit discontinuities and rolls in the coal bed. Poor roof conditions are also common along
margins of the channels, where the roof type transitions between the sandstone roof and normal shale roof.
Sunrise has implemented various programs to identify and mitigate, where possible, problems associated with
poor roof conditions.
The immediate floor beneath the Indiana V Seam coal bed consists of an interval of underclay. The underclay
provides a generally competent floor, however poor floor conditions can develop when the underclay is
exposed to water.
4.3.2
Structure
The Indiana V Seam coal bed is located at depths ranging from approximately 150 ft to over 600 ft below
ground surface, averaging 350 ft within the Oaktown Mining Complex area. Seam structure shows a general
seam dip of less than 2 degrees in a westerly direction. There are not any major structural faulting or tectonic
features known to occur in the deposit. Small-displacement faults and compaction-related faults may be
present, but are not expected to materially affect mine plans.
The structural setting for the deposit is generally considered to be simple in terms of geological complexity.
Some areas exhibit evidence of localized channelization; as such, isolated areas of the deposit may be
considered moderate in geological complexity.
Having been widely studied and extensively mined, the Indiana V Seam is well-known and widely-accepted
to be a uniform deposit.
4.3.3
Coal Quality
Overall, the Indiana V Seam coal bed is a high-sulfur moderate ash coal that is used for steam purposes.
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JOHN T. BOYD COMPANY
5.0
EXPLORATION DATA
5.1
Background
The Indiana V Seam has been the subject of extensive exploration drilling and sampling by Sunrise and other
parties, over a timespan of decades. Records from exploration drilling comprise the primary data used in the
evaluation of coal resources on the property. A database compiling the results of 1,935 drill holes—covering
Oaktown Mining Complex and surrounding area Indiana V Seam—along with electronic copies of original
drilling and sampling logs for a representative sample (approximately 42%), was provided for our review.
Additionally, discussions were held between BOYD and Sunrise concerning their standard exploration and
sampling methodologies. Topics covered standard procedures ranging from site safety and mapping, to how to
select proper drilling equipment, recording accurate and detailed geological logs, performing coal sampling,
supervising geophysical logging, and plugging drill holes once work was complete. Sunrise’s provided
explanation of exploration standards highlight their focus on obtaining the highest accuracy of data possible
from the various exploration campaigns they completed.
Due to archival storage of some physical records of drill holes and detailed information on the drilling and
sampling methodologies utilized, some documents were not provided for our review. While this limits the
ability to provide a completely transparent and detailed overview of the work completed in developing the
Oaktown Mining Complex, Sunrise has also demonstrated that they have been very thorough in exploring and
sampling, and the complex has been able to consistently and economically mine coal from this deposit for
more than a decade.
5.2
Procedures
5.2.1
Drilling
Drill holes on the subject property were completed using various drilling procedures based on specific goals
and data needs at various stages of planning and developing the Oaktown Mining Complex. Some drill holes
were rotary drilled for purposes of completing geophysical logging, while others were completed using
continuous core drilling methods to provide more detailed geologic records and sampling opportunities.
Sunrise technical staff were able to summarize the standard types of equipment and procedures they generally
utilized in exploration work completed on the property. This information, combined with information BOYD
was able to gather from our review of drilling records are as follows:
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●
Frequently used drilling equipment that is utilized during exploration is typical of the ILB region.
Typical drilling equipment that Sunrise uses for exploration, depending on the goal of a specific
drilling and sampling program, may consist of one or both of:
-
Continuous NQ-sized (3.0 in. outside diameter) diamond core rigs.
-
Water rotary with 4.875 in. diameter barrels.
●
Presently, core logging activities are completed in the field. Reportedly, current practices for
Sunrise are for cored intervals to be photographed, with special attention paid to the coal
interval. Cored coal is initially photographed in its entirety.
●
Select intervals of coal roof rock and floor rock are photographed and then boxed for archival
purposes.
●
Geophysical logging has been performed for some drill holes, while others may or may not have
been completed/recorded. Sunrise has noted that geophysical logging is currently completed on
all holes drilled.
Due to the large extent of historic exploration work, any recent drilling is generally for infilling areas with
lower geologic assurance or for establishing confidence of sandstone channel locations. In such instances,
nearby drill hole records are referenced prior to commencing any new drill holes, to show the anticipated
depth to the coal horizons.
Geophysical logs obtained from newly drilled holes are correlated by Sunrise geologists by aligning known
“marker beds”, and then checking coal seam depths, elevations, and thicknesses to ensure seam continuity.
These data are formatted and then imported into Sunrise’s geologic modeling programs.
BOYD’s review of the methodologies and procedures indicate the data obtained and utilized by Sunrise for
the Oaktown Mining Complex project area were carefully and professionally collected, prepared, and
documented, conforming with general industry standards, and are appropriate for use of evaluating and
estimating coal resources and reserves.
5.2.2
Coal Quality Sampling
The Oaktown Mining Complex coal quality testing was performed on a large number of coal samples
obtained from the Indiana V Seam, in and around the project area. The relatively dense core drilling coverage,
combined with channel samples being taken regularly from underground development areas, provides a
thorough understanding of the clean coal product that could be produced from the Oaktown Mining Complex.
All coal intercepts of Oaktown Mining Complex exploration were geologically logged, photographed, and
sampled in the field by competent geologists. Sampling methodologies consist of first pushing the cored
intervals of coal out of the core barrel, directly into a clean single-row
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wooden core box. Prior to removing coal core from the drilling barrel, the core box is lined with durable
plastic sheeting, which helps retain moisture content and minimize coal core oxidation. Once the coal core is
fully extruded from the core barrel, it is then inspected, photographed, and logged by the on-site geologist,
and cardboard inserts are installed in the wooden core box to maintain coal core integrity.
Upon completing detailed recording (geologic logging and photographing) of the coal interval, coal cores are
split into the desired intervals to be analyzed and bagged. An order sheet is placed inside the sample bag,
which specifies drill hole information, split information, and testing to be completed on the bagged sample.
Sample bags are then zip tied closed, labeled, and then double bagged to eliminate incidental core loss due to
potential damage during transportation to the testing lab.
Sunrise maintains all control of coal core samples, up to the point that samples are handed over to the lab
performing testing. Once logging and sampling are complete, the sampled coal core intervals are transported
to the selected lab that will perform the required analyses. Typically, washability analysis is performed on the
majority of drillhole samples with select drillholes being expanded to include full proximate or other analyses
(i.e., ultimate, ash content, etc.). The lab manager signs off on the return analysis sheet, indicating that testing
results are accurate and that the sample provided was sufficient for testing purposes.
Past programs utilized various accredited coal testing laboratories, again depending on what testing needed to
be completed on the coal core at a given time. All analytical work was conducted to International
Organization of Standardization (ISO) or American Society for Testing and Materials (ASTM) standards, and
various available laboratory sample sheets were provided for review with drilling log data.
Available testing sheets were reviewed by BOYD during our drill hole data audit, and our review of the
discussed field and sampling procedures noted above indicated that the general description and sampling
work were conducted to appropriate standards. Based on the stated standards and laboratory used, BOYD
considers the sample preparation and analytical procedures were adequate for the coal quality results for
inclusion in geological modelling and coal resource estimation.
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5.2.3
Coal Washability Testing
Coal washability tests (proximate analysis) were conducted at various specific gravities, generally ranging
from 1.45 specific gravity float (SGF) through 1.55 SGF. Estimated coal reserves for the Oaktown Mining
Complex are currently reported using 1.55 SGF testing results over the entire Oaktown Mining Complex
project area. Proximate analysis test results were completed on 723 drill core samples, which were used in
estimating quantity and quality of the remaining Oaktown Mining Complex coal reserves.
Although it was noted that Sunrise generally does not perform any randomized sample verification in order to
conduct quality control testing of individual coal analyses, Sunrise will typically perform channel sampling
and quality analyses throughout mine workings. The channel sample data are then utilized to update quality
models.
5.2.4
Other Exploration Methods
Numerous coal samples and surveyed coal thickness measurements have been collected throughout the mine
workings. There is no known ore reported via other methods of exploration (such as airborne or ground
geophysical surveys) completed for the project area.
5.3
Results
A total of 1,962 drill holes and in-mine samples are in and around the Oaktown Mining Complex area. The
distribution of these drill holes is shown on Figure 5.1. Lithologic and coal quality data from these holes were
used only for geologic modeling and coal resource assessment for the property.
General descriptive statistics for the Indiana V Seam thickness are provided in Table 5.1 below.
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Figure 5.1
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As shown, the thickness of the seam can range from less than a foot to over 12 ft across the Oaktown Mining
Complex area. Average thickness of the Indiana V Seam for the project area is approximately 5.2 ft for the
Oaktown Fuels No. 1 Mine area and 4.8 ft for the Oaktown Fuels No. 2 Mine area.
The results of the coal quality analyses from 723 samples are summarized in Table 5.2.
Raw and clean (washed) coal quality data demonstrate the consistency of the Indiana V Seam as a high-sulfur,
moderate ash coal.
5.4
Data Verification
For purposes of this report, BOYD did not verify historic drill hole data by conducting independent drilling in
areas already explored. It is customary in preparing coal resource and reserve estimates to accept basic
drilling and coal quality data as provided by the client subject to the reported results being judged
representative and reasonable.
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BOYD’s efforts to judge the appropriateness and reasonability of the source exploration data included
reviewing a representative sample of drilling logs and coal quality test results for holes located in unmined
portions of the Oaktown Mining Complex area. These records were compared with their corresponding
database records for transcription errors, noting the vast majority of the information being consistent.
Lithologic and coal quality data points were compared via visual and statistical inspection with geologic
mapping.
BOYD’s review indicates that in general, Sunrise has performed extensive drilling and sampling work on the
subject property, the work completed has been done so by competent personnel, and the amount of data
available from exploration and mining operations, combined with wide-spread knowledge of the Indiana V
Seam, is sufficient to confirm seam uniformity and continuity throughout the Oaktown Mining Complex
deposit.
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6.0
COAL RESOURCES AND RESERVES
6.1
Applicable Standards and Definitions
Unless noted, coal resource and coal reserve estimates disclosed herein are done so in accordance with the
standards and definitions provided by S-K 1300. It should be noted that BOYD considers the terms “mineral”
and “coal” to be generally interchangeable within the relevant sections of S-K 1300.
Estimates of coal resources and reserves are always subject to a degree of uncertainty. The level of confidence
that can be applied to a particular estimate is a function of, among other things: the amount, quality, and
completeness of exploration data; the geological complexity of the deposit; and economic, legal, social, and
environmental factors associated with mining the resource/reserve. By assignment, BOYD used the
definitions provided in S-K 1300 to describe the varying degree of certainty associated with the estimates
reported herein.
The definition of mineral (coal) resource provided by S-K 1300 is:
Mineral resource is a concentration or occurrence of material of economic interest in or on the
Earth's crust in such form, grade or quality, and quantity that there are reasonable prospects for
economic extraction. A mineral resource is a reasonable estimate of mineralization, taking into
account relevant factors such as cut-off grade, likely mining dimensions, location or continuity, that,
with the assumed and justifiable technical and economic conditions, is likely to, in whole or in part,
become economically extractable. It is not merely an inventory of all mineralization drilled or
sampled.
Estimates of coal resources are subdivided to reflect different levels of geological confidence into measured
(highest geologic assurance), indicated, and inferred (lowest geologic assurance). See Glossary of
Abbreviations and Definitions.
The definition of mineral (coal) reserve provided by S-K 1300 is:
Mineral reserve is an estimate of tonnage and grade or quality of indicated and measured mineral
resources that, in the opinion of the qualified person, can be the basis of an economically viable
project. More specifically, it is the economically mineable part of a measured or indicated mineral
resource, which includes diluting materials and allowances for losses that may occur when the
material is mined or extracted.
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Estimates of coal reserves are subdivided to reflect geologic confidence, and potential uncertainties in the
modifying factors, into proven (highest assurance) and probable. See Glossary of Abbreviations and
Definitions.
Figure 6.1 shows the relationship between coal resources and coal reserves.
In this report, the term “coal reserves” represents the tonnage and coal quality of product coal that will be
available for sale after beneficiation of the ROM coal.
6.2
Coal Resources
6.2.1
Methodology
Based on provided information, Sunrise’s coal resources (and coal reserves) estimation and modeling
techniques consists of:
1.
Interpreted and correlated coal seam intercepts are compiled and validated. Seam thickness is
aggregated and coal qualities are composited, based on assumed mining methods, for each
data point.
2.
Boundaries of the respective resource classification regions are developed using the data
points.
3.
ROM coal thickness and coal qualities for each data point are derived from the application of
dilution parameters.
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4.
Clean product qualities for each data point are derived from coal washability analysis and plant
efficiency factors.
5.
The approved LOM design is subdivided into small mining blocks and sequenced using mine
planning software.
6.
In-place, ROM, and clean product estimates of coal volume and qualities for each mining block
are estimated within the mine planning software by linear least squares interpolation of the data
points developed in Steps 1 and 2.
7.
The mining blocks (and associated volumetric data) are further subdivided by resource
classification and property tract polygons.
8.
Relevant and periodic summaries are prepared by Sunrise to support planning and coal
resource/reserve reporting.
6.2.2
Criteria
Development of the coal resource estimate for the Oaktown Mining Complex assumes mining using standard
underground R&P methods and equipment, which have been utilized successfully at the Oaktown Mining
Complex for over a decade.
Within the area of study, the Indiana V Seam exhibits consistent and well-characterized clean (i.e., washed)
coal qualities which are within existing marketable limits for ILB coal products. BOYD did not discover any
areas within the property where clean coal quality was deficient relative to Sunrise’s historical coal sales and
current sales contract specifications for high-sulfur thermal coal. As such, no reductions have been made to
the coal resources due to coal quality.
A minimum mineable seam thickness of 4 ft was used to limit the coal resources of the Indiana V Seam. This
cut-off is a function of the employed mining techniques and equipment. Mining heights less than 4 ft result in
operational difficulties and increase OSD, thereby reducing productivity and increasing costs.
There were not any other cut-offs applied.
6.2.3
Classification
Geologic assuredness is established by the availability of both structural (thickness and elevation) and quality
information for the Indiana V Seam. Classification is generally based on the concentration or spacing of
exploration data, which can be used to
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demonstrate the geologic continuity of the deposit. Table 6.1 provides the general criteria employed in the
classification of the coal resources.
Extrapolation or projection of resources in any category beyond any data point does not
exceed half the point spacing distance.
BOYD reviewed the classification criteria employed by Sunrise with regards to data density, data quality,
geological continuity and/or complexity, and estimation quality. The Indiana V Seam is well-known and of
low complexity. We believe these criteria appropriately reflect the interpreted geology and the estimation
constraints of the deposit. Coal resources in the Oaktown Mining Complex area are well-defined throughout
nearly all areas of the mine plan. Observed drill hole spacing averages approximately 1,995 ft and generally
ranges between 440 ft and 8,000 ft.
6.2.4
Coal Resource Estimate
There are no reportable coal resources excluding those converted to coal reserves for the Oaktown Mining
Complex. Quantities of coal controlled by Sunrise within the defined boundaries of the Oaktown Mining
Complex which are not reported as coal reserves, are not considered to have potential economic viability; as
such, they are not reportable as coal resources.
6.3
Coal Reserves
6.3.1
Methodology
Estimates of coal reserves are derived contemporaneously with estimates of coal resources for the LOM plans
through the application of appropriate modifying factors. Economic viability of the coal reserves is
subsequently confirmed via a LOM financial forecast.
The coal reserve estimates have been prepared using generally accepted industry methodology to provide
reasonable assurance that the coal reserves are economic and recoverable at the time of evaluation.
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6.3.2
Parameters and Assumptions
The following parameters and assumptions were relied upon to determine the coal reserves:
●
The underground operation is mined using R&P methods.
●
The mine plans were developed to address anticipated geologic, geotechnical, and hydrogeologic
conditions.
●
Mining and processing parameters are revised periodically, to assure that the conversion of in-place coal
to saleable product are: (1) in reasonable conformity with present and recent historical operational
performance, and (2) reflective of expected mining and processing operations.
Mining recovery, which is dependent on numerous factors associated with R&P mining, historically ranges
between 40 and 50% (averaging 44.4%) for the Indiana V Seam. Within the Oaktown Mining Complex’s
LOM plan areas, the estimated average mining recovery is 48% for the Oaktown Fuels No. 1 Mine and 45%
for the Oaktown Fuels No. 2 Mine. Theses recoveries are considered reasonable.
Clean coal estimates are based on coal washability data. These estimates have been conservatively adjusted
downward to reflect practical yields achieved by the preparation plant. Salient coal preparation factors used to
estimate the coal reserves include:
●
Product yields are derated by 8 percentage points to account for preparation plant efficiency.
●
The average product yield for the coal reserves is 80% before accounting for OSD or approximately
60.4% after the inclusion of OSD.
●
Sulfur content within clean coal estimates is adjusted upward by approximately 15% above washability
data (consistent with historical clean coal processing results).
●
Product moisture was estimated at 13.0% (as-received basis).
Figure 6.2, on the following page, depicts the estimated unadjusted (i.e., excluding OSD and plant preparation
efficiencies) product yield for the Indiana V Seam across the Oaktown Mining Complex deposit.
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Figure 6.2
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The Indiana V Seam across the Oaktown Mining Complex property exhibits clean coal quality which is
consistent with Sunrise’s historical production and current sales contract specifications. Furthermore, the
projected coal quality over the life of the coal reserves is consistent with coals produced by other ILB
operators (please refer to Chapter 10 for further information). As such, BOYD does foresee any quality
deviations that would adversely affect the marketability of future coal production from the Oaktown Mining
Complex.
The economic viability of the stated coal reserves is demonstrated by the production and financial projections
presented in Chapters 10 through 12 of this report. The forecasted sales prices (FOB CPP) used in the
estimation of coal reserves for the Oaktown Mining Complex vary by year, ranging from $47.25 to $51.47
and averaging $48.72 per clean ton (refer to Section 10.2.5 for further details).
6.3.3
Classification
Proven and probable coal reserves are derived from measured and indicated coal resources, respectively, in
accordance with S-K 1300. BOYD is satisfied that the stated coal reserve classification reflects the outcome
of technical and economic studies. Figure 6.3, on the following page, illustrates the reserve classification of
the Indiana V Seam within the Oaktown Mining Complex.
6.3.4
Coal Reserve Estimate
Sunrise’s estimated underground mineable coal reserves for the Oaktown Mining Complex total 34.4 million
recoverable (clean) product tons remaining as of December 31, 2024. The coal reserves reported in Table 6.2
(page 6-9) are based on the approved LOM plan which, in BOYD’s opinion, is technically achievable and
economically viable after the consideration of all material modifying factors.
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Figure 6.3
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Coal reserves for the Oaktown Mining Complex are summarized by mine in Table 6.3, below.
The reported coal reserves include only coal that is controlled by the company under lease
agreement as of December 31, 2024. It should be noted that the Oaktown Mining Complex’s
permitted underground mining area includes approximately 1.9 million product tons which are
currently uncontrolled (i.e., owned by other parties). Sunrise anticipates gaining control of the
mineral rights to this uncontrolled coal in due time and adjusting its mine plans accordingly. BOYD
is not aware of any encumbrances, litigation, or orders that would hinder the continued
development of the property.
At the time of reporting, approximately 33.8 million product tons, or 98% of the reported reserves, are
permitted for mining by appropriate federal and state regulatory authorities. The remaining 681 thousand
product tons are not permitted. It is typical for mining permits to be periodically amended as mining
progresses to add acreage (tonnage) in order to sustain coal production. It is reasonable to expect that all
necessary permits to recover the coal will be successfully obtained in advance of mining.
The coal reserves of the Oaktown Mining Complex are well-explored and defined. It is our conclusion that
nearly 92% of the stated reserves can be classified in the proven reliability category (the highest level of
assurance) with the remainder classified as probable. Given the uniformity of the Indiana V Seam in and
around the Oaktown Mining Complex, it is reasonable to assume that further exploration and testing will
confirm the occurrence of coal reserves, resulting in an increase in the percentage of coal reported in the
proven category.
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Table 6.4, below, summarizes the washed coal quality for each mine of the Oaktown Mining Complex. The
reported coal reserves generally consist of high-sulfur moderate ash coal that may be used for steam purposes.
Figures 6.4 and 6.5, respectively, illustrate the product ash and product sulfur content over the Oaktown
Mining Complex area. As shown, there are slight increases in both ash and sulfur content from southeast to
northwest across the property.
The Oaktown Mining Complex is an established underground coal mining and processing complex with a
consistent operating history. BOYD has assessed that sufficient studies have been undertaken to enable the
coal resources to be converted to coal reserves based on current operating methods and practices. Changes in
the factors and assumptions employed in these studies may materially affect the coal reserve estimate.
The extent to which the coal reserves may be affected by any known geological, operational, environmental,
permitting, legal, title, variation, socio-economic, marketing, political, or other relevant issues has been
reviewed as warranted. It is BOYD’s opinion that Sunrise has appropriately mitigated, or has the operational
acumen to mitigate, the risks associated with these factors. BOYD is not aware of any additional risks that
could materially affect the development of the reserves.
Based on our audit review, we have a high degree of confidence that the estimates shown in this report
accurately represent the available coal reserves controlled by Sunrise, as of December 31, 2024.
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Figure 6.4
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Figure 6.5
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6.3.5
Validation
BOYD independently estimated coal reserves for the Oaktown Mining Complex mine plan from geologic
data and models provided by Sunrise. Based on our review of
Sunrise’s well-documented geologic modeling and estimation techniques and the results of our data validation
efforts (described earlier), we are of the opinion that Sunrises’ modeling procedures are reasonable and
appropriate. We consider the LOM plan and economic forecast sufficiently detailed to support the estimate of
coal reserves reported herein. Furthermore, it is BOYD’s opinion that there is a high degree of assurance
associated with the stated coal reserves due to the current amount of exploration and sampling, mine planning,
and economic analyses that have been completed on the Indiana V Seam within the Oaktown Mining
Complex area.
6.3.6
Reconciliation with Previous Estimates
Figure 6.6, below, illustrates the comparison of Sunrise’s coal reserve estimates as of December 31, 2024,
with those reported of December 31, 2023.
Figure 6.6
Reconciliation with Previous Coal Reserves Estimate
The net decrease in reserves reflects: (1) reevaluation of the life-of-mine plans for both underground
operations, including substantial revisions to the Oaktown Fuels No.2 Mine; and (2) depletion through
ordinary mining operations and inventory sales.
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7.0
MINING OPERATIONS
7.1
Mining Method Description
Coal is produced by the Oaktown Fuels No. 1 and No. 2 underground mines using the R&P mining method.
R&P mining is a partial extraction technique that recovers a portion of a coal seam. An illustration of a typical
R&P mining operation is provided in Figure 7.1.
Figure 7.1
Room-and-Pillar Mining Method
Source: Pennsylvania State University (Arch Coal, Inc.).
R&P mining utilizes the systematic development of interconnected underground entries or openings with
rectangular roadways that are driven in the coal seam and are typically supported by roof bolts installed in the
immediate roof. The parallel mine entries are connected by crosscuts which result in a series of mine openings
separated by solid coal pillars that support the main roof. R&P mining systems, which generally utilize CMs,
can be used for coal production (like the underground mines of the Oaktown Mining Complex) or as a
development technique to support longwall (LW) production. This flexible mining system is widely used
across the U.S. coal industry, at large and small mines with varying seam thicknesses and mining conditions.
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A typical R&P production section will include one or two CM units, one to three roof bolting machines, and
between two and three coal haulage machines (most commonly either ram cars [RC] or shuttle cars [SC]) per
CM. The main piece of equipment is the CM, which is a heavy, steel framed machine (often over 40 tons)
mounted on cat tracks, that operates on AC power. Key components of a CM include:
●
Electric and hydraulic motors that power the CM’s operation.
●
A tram mechanism that propels the machine.
●
A horizontally mounted, cylindrical cutting head used to cut the coal seam.
●
A pair of gathering arms that pick-up/clear away the mined material.
●
An internal conveyor system used to load the mined product into a haulage vehicle.
Although there have been ongoing advances in CM equipment technology, the basic R&P mining process has
been utilized for decades and has remained largely unchanged over that time. The CM is used to extract the
coal seam by mining a rectangular opening or “cut”. The cut typically ranges from 18 ft to 20 ft in width and
extends the height1 of the coal seam plus some increment of extraneous non-coal roof and floor material
extracted during the mining process (known as OSD). The depth that the CM cuts into the coal seam (i.e., the
cut length) is dependent upon mining conditions, regulations, operating practices, etc. but is generally in the
range of 15 ft to 40 ft. Shorter cuts are taken in areas where there are difficult roof conditions.
A critical element of R&P mining is the interaction between the CM, the roof-bolting machine and supporting
haulage units. Known as “place-changing”, the following steps will typically occur during mining cycle:
1.
The CM penetrates the cut. As the coal and associated OSD are extracted, the CM unit loads the broken
material into one of the haulage vehicles/RC.
2.
Once fully loaded, the RC carries the product from the CM to a “feeder,” where the coal is discharged
from the car and gradually metered onto a conveyor belt for transport out of the mine. The empty RC then
trams back to the CM to be reloaded. While this is taking place, the second RC is subsequently loaded. If
additional RCs are utilized, these units follow in sequence. This operating pattern continues until the coal
volume within the cut is fully extracted.
3.
The CM then backs out of the cut and trams to the next location where the mining process is continued.
4.
After a cut is completed, the exposed roof in the cut (just completed by the CM) must be supported. A
roof bolting machine trams into the freshly mined area, drills holes into the roof and installs roof bolts—
steel rods that strengthen the integrity of the roof. The principle of
1 In instances where a CM is operating in thick seam conditions (i.e., the coal thickness is greater than 8 ft), the
height of the cut may be less than the full thickness of the seam.
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JOHN T. BOYD COMPANY
roof bolting is to physically tie together the weaker individual layers of roof strata to create a single
“laminated” unit of rock that is stronger than the unsupported strata.
Place-change mining is an efficient form of R&P mining, although the process will routinely incur delays
during a production shift (perhaps 5 to 20 minutes per occurrence, depending upon site-specific
considerations). Where roof conditions permit (and approval is granted by regulatory agencies), mine
operators will employ "deep cut" mining plans to reduce the impact of place-changing delays. Longer cuts
(usually 30 ft to 40 ft in length) enable the CM to spend a greater portion of available shift time in cutting and
loading activities.
Place-changing CM equipment has steadily evolved over the years via technological breakthroughs to become
sophisticated, productive, and durable. Today’s state-of-the-art CM units are equipped with efficient motors,
computer diagnostics, solid-state electronics, advanced remote-control systems, and scrubbing mechanisms
(which preserve underground air quality by capturing a significant percentage of respirable dust that is
generated by the breaking/grinding of coal and rock during the mining process). Ever-improving
technological gains have resulted in dramatic improvements in productivity, machine availability, employee
safety, and unit operating costs over the past four decades.
An R&P mine may operate a single production section, or multiple sections (like the mines of the Oaktown
Mining Complex). This is dependent upon the size of the reserve, supporting infrastructure, capitalization,
markets, etc. A variation of the traditional R&P place-changing method is the “super-section”. Under this
system, the CM production section is equipped with two CM machines, two sets of haulage vehicles, and
multiple roof bolters. Under this variation, each “super-section” essentially operates two production units per
belt dumping point enhancing the productive output of the mine section. This variation of traditional R&P
mining is employed at both Oaktown Fuels No. 1 and No. 2 mines.
R&P extraction may be performed as either “first mining” or “secondary extraction”. First or “advance-only”
mining is where a system of entries or openings are driven/advanced and the remaining coal pillars are left
intact. Under this system, after a section has reached its intended advance distance, the section equipment is
recovered and relocated to a new area, leaving the developed pillars untouched (i.e., no secondary mining of
the pillars occurs). Reasons for employing this type of R&P mining may include equipment specifications,
geological conditions, subsidence restrictions, operator preferences, etc.
Secondary extraction or “retreat mining” is the process whereby, after the mine workings have reached the
end of the advance stage of mining, the direction of mining is reversed (i.e., the mine operator retreats
towards the mouth of the production section, employing a prescribed series of
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JOHN T. BOYD COMPANY
cuts to sequentially recover coal from the pillars). Retreat mining systems can be complex and may include
partial or full pillar extraction (which allows the roof to systematically collapse and subsequently results in
subsidence of the overlying surface).
Reserve recovery (extraction ratio) varies at R&P mines. Generally, 40% to 50% extraction of the in-place
coal is typical, with extraction ratios ranging from 30% to 70%. Retreat mining may or may not offer higher
extraction ratios than advance only mining; actual recoveries are dependent upon pillar dimensions and a
variety of operational considerations.
Historically, the Oaktown Fuels No. 1 Mine has employed three or four super-sections in its mining
operations, and Oaktown Fuels No. 2 Mine has employed two or three super-sections. Some secondary
extraction whereby small portions (or “fender cuts”) of some pillars are removed has been utilized at both
operations and will likely be utilized in future operations. Sunrise has no plans for full pillar extraction
secondary mining in its LOM plan.
R&P mining has been one of the predominant approaches to mining the Indiana V Seam (within which
Oaktown Mining Complex operates) for decades. Mining in the Oaktown Fuels No. 1 Mine, which first began
production in 2009 and is the oldest of the Oaktown Mining Complex’s two operations, is largely identical to
the practices used at the Oaktown Fuels No. 2 Mine. In terms of mining methodology, the application of R&P
mining techniques at the Oaktown Fuels No. 1 and No. 2 mines is viewed as a prudent operating decision
based on: (1) the extent of the complex’s overall coal reserve base, (2) Sunrise’s targeted annual production
levels, (3) the mines’ historic and expected mining conditions and seam orientation, and (4) the successful
application of R&P technology at nearby historical and active mining operations. The use of R&P mining at
the Oaktown Mining Complex is further justified based on Sunrise’s experience operating R&P mines and
their reputation for having refined the technical, operational, and financial elements of this mining technique
for site specific conditions over the years.
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7.2
Mine Equipment and Staffing
7.2.1
Mine Equipment
The equipment utilized at the two Oaktown Mining Complex underground R&P mines is nearly identical to
one another. This allows for synergies between the operations, including the sharing of equipment and critical
spare parts. Additionally, mining equipment utilized by Oaktown Mining Complex is not unique to the ILB
region (i.e., Oaktown Mining Complex’s mining equipment is similar to the equipment commonly used by
competitor underground mines in the region).
Table 7.1, below, presents Oaktown Mining Complex’s projected number of CM super-sections for 2025
through 2035 according to BOYD’s conceptual LOM:
A listing of equipment typically employed by the two mines’ CM super-sections is shown in Table 7.2, below.
Based on BOYD’s review of the Oaktown Mining Complex’s equipment and asset listings, the operations’
current complement of equipment is sufficient to meet the production levels projected for each of the
operations over their conceptual LOM plans. Additionally, capital projections prepared by Sunrise have
accounted for future equipment related expenditures to maintain production at forecasted levels. In BOYD’s
opinion, all mining equipment utilized on the Oaktown Mining Complex’s CM super-sections is suitable for
the mining conditions anticipated, as well as for the future proposed rates of production.
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7.2.2
Staffing
Oaktown Mining Complex’s underground mines and coal preparation facility are staffed by a workforce
primarily from the surrounding southwestern Indiana and southeastern Illinois areas. The workforce, which is
comprised of both hourly and salary employees, has no labor affiliation (i.e., the Oaktown Mining Complex is
union-free). Table 7.3, below, provides recent historical employment as reported by MHSA for each
operational site.
Future employment levels are expected to resemble historical levels. Given Sunrise’s ability to hire and retain
employees, staffing is not expected to hinder the Oaktown Mining Complex operations’ ability to achieve
forecasted production levels.
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7.3
Mine Production
7.3.1
Historical Mine Production
Historical mine production data for the two Oaktown Mining Complex underground R&P mines, based on
publicly available information reported by MSHA, are detailed in Table 7.4, below.
As a complex, Oaktown Mining Complex has produced a combined 75 million tons of clean coal between
2009 and 2024. Through the same period, the complex has recorded an average productivity level of 3.8 tons
per employee-hour (TPEH). Figure 7.2, on the following page, illustrates the historic mining productivity for
the
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Oaktown Mining Complex and each mine individually since their start of commercial production.
Figure 7.2: Historic Mining Productivity Levels
7.3.2
Forecasted Production
BOYD developed LOM plans for each of the Oaktown Mining Complex underground mines based on
generally accepted engineering practices, and in alignment with historical and industry norms. It is BOYD’s
opinion that the forecasted production levels for the Oaktown Mining Complex operations are reasonable,
logical, and consistent with typical CM mining practices within the ILB and historical practices utilized by
the Oaktown Mining Complex.
The Oaktown Mining Complex LOM plans, as shown in Table 7.5, following this page, portray a consistent
production output during 2025 through 2032 and then a decline in production as the number of CM units are
reduced gradually as the mining reserves are depleted. In the aggregate, the Oaktown Mining Complex LOM
plan projects the complex will produce approximately 57.1 million tons of ROM and approximately
34.4 million tons of clean coal over its operational horizon.
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Average clean yield and quality on an annual basis over the life of the Oaktown Mining Complex is provided
in Table 7.6, below.
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In general, Oaktown Mining Complex’s annual clean coal yield and quality is relatively consistent over the
11-year period; this consistency is indicative of the local Indiana V Seam coal geology.
During the 11-year life of mine, the Oaktown Mining Complex is forecasted to produce approximately 34.4
million tons of clean coal. While it is expected that the mines will encounter local areas of high ash and/or
sulfur from either individual mine, the aggregate product from Oaktown Mining Complex should see minimal
impact. This reflects the fact that Oaktown Mining Complex’s infrastructure allows for the blending of each
the individual mines’ segregated ROM product, thus mitigating the influence/impact that an individual mine
or production unit (producing in a localized area of lesser coal quality) could have on the complex’s overall
product quality.
7.3.3
Mining Recovery and Dilution Factors
The Oaktown Mining Complex’s underground R&P mines operate within the same geological setting and
coal seam with little distinguishable differences. As such, the design of each mine is largely the same (e.g.,
mains width, panel width and length, and CM support pillars). As a result, mining recoveries within the
individual mine plans are largely similar. The estimated mining recoveries for Oaktown Mining Complex
generally range from 40% to 50%. Based on our review of Oaktown Mining Complex’s reserves by
individual mining areas, it is BOYD’s opinion that the mining area recoveries utilized are reasonable and
align with general engineering principles.
The proximity of the operations within the same geologic setting and coal seam also results in similar dilution
factors for both Oaktown Mining Complex’s mines. The mining horizon targeted by each of the mines
includes the main bench of the Indiana V Seam and any in-seam partings. Both mines traditionally operate
within the seam as much as possible with little OSD.
The CM mains sections are more subject to sporadic OSD due to maintaining proper ventilation airways,
airway intersection locations with planned undercasts, provide adequate clearances for belt transfers, etc.,
regardless of the targeted mining horizon thickness. These variances are more likely a result of mine
infrastructure and design rather than fluctuations in geology.
7.3.4
Expected Mine Life
The LOM plan for each of the Oaktown Mining Complex mines’ operation was developed with input from
both Sunrise and BOYD. The LOM plan was developed with consideration taken for mineral control and
timing based upon forecasted production levels for each mine. The depicted general layout and mineral
control for Oaktown Fuels No. 1 and No. 2 mines are shown in Figure 3.1.
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The final year of the Oaktown LOM plan is 2035. While Oaktown Mining Complex is forecasted to operate
through 2035, each mine has a different expected mining life. Table 7.7 provides the expected mine life for
each of the individual underground R&P mines:
Production units will start to decrease following 2031 as the coal reserves are gradually depleted at Oaktown
Fuels No. 1 Mine. The Oaktown Fuels No. 2 Mine is scheduled to resume mining in 2030 with two
production units until its second to last year of operation in 2034. Coal reserves at both mining operations of
the Oaktown Mining Complex are expected to be exhausted in 2035.
7.4
Other Mining Considerations
7.4.1
Mine Design
Mines in the ILB region utilize a wide range of techniques for the extraction of coal including both surface
and underground mining methods. However, the majority of coal mining production from the ILB region
focuses largely on the Indiana V (Springfield) and Indiana VI (Herrin) seams extracted through underground
mining methods.
Given the large extent of reported coal reserves, overall good mining conditions, general coal seam
consistency, consistent depth of cover, and relatively low population density on the overlying surface, the
Oaktown Mining Complex is well suited for underground R&P mining. Mining plans for R&P mines without
secondary extraction are relatively simple yet highly flexible. Unlike LW operations (having a rigid system),
the Oaktown Fuels No. 1 and No. 2 mines’ mining method allows for the opportunity to alter the mining plan
to avoid specific areas with adverse mining conditions (such as thin coal, poor roof, etc.) or poor coal quality
(such as high sulfur, etc.). Mains and sub-mains are typically established in areas where confidence is highest
regarding good mining conditions, roof conditions, coal thicknesses, etc. Panels are then developed out to a
desired length (whether that be operationally, or engineering based) or until adverse mining conditions or poor
coal quality warrant the cessation of development. When the mine panels reach the end of their advance stage
of mining, the mine operator removes the production equipment and reinstalls it to another location within the
mine to commence production.
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The Oaktown Mining Complex is approved for “first only” mining and partial pillar extraction (fender cuts)
on a case-by-case basis. Sunrise has no intentions of employing full pillar extraction mining methods at either
of the operations. The use of “first only” mining and “fender cuts” is common for the ILB region R&P
underground mines. There remains substantial public and environmental group opposition to mining in
general, however this is more particularly targeted towards LW mining and full pillar extraction and the
effects of subsidence on surface structures and, more recently, perennial streams. The Oaktown Mining
Complex is shielded from a portion of this opposition given the implementation of “first only” and partial
pillar extraction mining methods. While there are likely to be some instances of heightened environmental
and communal concern regarding mining within the Oaktown Mining Complex plans, Sunrise has historically
demonstrated the ability to apply for and obtain the necessary permits for continued mining within their
controlled coal reserves, even while being met with some environmental pushback.
7.4.2
Mining Risk
Underground R&P mines face two primary types of operational risks. The first category of risk includes those
daily variations in physical mining conditions, mechanical failures, and operational activities that can
temporarily disrupt production activities. Several examples are as follows:
●
Roof control problems and roof falls.
●
Water accumulations/soft floor conditions.
●
Ventilation disruption and concentrations of methane gas.
●
Variations in seam consistency, thickness, and structure.
●
Failures or breakdowns of operating equipment and supporting infrastructure.
●
Weather disruptions (power outages, inability to load barges due to flooding of rivers, etc.).
The above conditions/circumstances can adversely affect production on any given day, but are not regarded as
“risk issues” relative to the long-term operation of a mining operation. Instead, these are considered “nuisance
items” that, while undesirable, are encountered on a periodic basis at virtually all mining operations.
Engineered mining plans and projections for the Oaktown Mining Complex appear to incorporate generally-
accepted industry and Sunrise historical performance levels as a basis, and thereby mitigate the likelihood that
the mines will experience such disruptions to production operations to the extent that they have previously
occurred. BOYD does not regard the issues listed above as being material to the Oaktown Mining Complex
mining operations or otherwise compromising the forecasted performance.
The second type of risk is categorized as “event risk.” Items in this category are rare, but significant
occurrences that are confined to an individual mine, and ultimately have a pronounced
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JOHN T. BOYD COMPANY
impact on production activities and corresponding financial outcomes. Examples of event risks are major fires
or explosions, floods, or unforeseen geological anomalies that disrupt extensive areas of underground mine
workings and require alterations of mining plans. Such an event can result in the cessation of production
activities for an undefined but extended period (measured in months, and perhaps years) and/or result in the
sterilization of coal reserves.
The U.S. mining industry has made tremendous strides in enhancing employee safety and reducing the
likelihood of fires, explosions, and other dramatic events over the past several decades. Underground R&P
mining is largely a predictable and safe industry. BOYD does not regard the Oaktown Fuels No. 1 and No. 2
mining operations and mine plans as being particularly risky, inadequately managed, or otherwise susceptible
to major events. There is no basis to predict or otherwise anticipate major operational shortfalls and/or
extraction of coal reserves at the subject mining operation.
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8.0
PROCESSING OPERATIONS
8.1
Overview
The centrally located Oaktown Complex CPP is designed to process the combined ROM output produced by
Oaktown Mining Complex’s two underground R&P mines. Comprised of ROM coal stockpile areas, a coal
processing plant, clean coal storage, a rail loadout facility, and truck scales/loading, the approximate 150-acre
processing complex is located within proximity of the active operations.
The Oaktown Complex CPP first began operation as the coal washing facility for the Oaktown Fuels No. 1
Mine in 2009. In 2013, major renovations were made to the Oaktown Complex CPP to accommodate
additional tonnage supplied from the newly developed Oaktown Fuels No. 2 Mine. Major process upgrades
focused on adding a second 800 TPH circuit, increasing total CPP throughput capacity to 1,600 TPH.
While the capacity of the facility has grown, the coal preparation process at Oaktown Complex CPP, like
other preparation plants in the ILB mining region, has largely remained unchanged since commissioning.
Processing circuits within the Oaktown Complex CPP consist of heavy media bath, heavy media cyclones,
hydro-spirals, and froth flotation. Straightforward when compared to many other mineral processing
techniques, the coal process is largely based on separating rock material from coal material contained in the
raw coal feed by mechanically reducing the size of the feed and utilizing the materials’ different densities to
gravitationally separate one from the other. Largely, the process requires water, magnetite, and frothing
agents.
ROM coal arrives directly to the complex from the Oaktown Fuels No. 1 and No. 2 mines via two
independent slope conveyor belts. There are two ROM coal storage areas that provide approximately 1.2
million tons of above-ground storage capacity for the Oaktown Mining Complex underground mines. The
ROM coal storage areas enable each mine to provide their plant feed separately to the preparation facility, or
to be combined for a blended product. The clean coal product is dried with screen-bowl centrifuges.
Processed product is then transported via overland conveyor belt just over 1 mile to the north and stored at the
open-air clean coal storage area. The main clean coal storage area has a capacity of approximately 980,000
tons, with an auxiliary clean coal storage located adjacently (capacity of approximately 290,000 tons) that can
be utilized as necessary.
Clean coal is sampled and loaded into 120-car unit trains through a flood load system. The Oaktown Complex
CPP is served by both CSX and INRD via a short rail spur that connects the
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JOHN T. BOYD COMPANY
complex’s double loop rail system with the mainline rail just north of Oaktown, Indiana. Two rail sidings are
employed to facilitate railroad transportation logistics and allowing the accommodation of two-unit trains at
any time.
Following this page are Figure 8.1, which provides an aerial overview of the preparation facility area, and
Figure 8.2, which provides a generic flow sheet of the CPP and related facilities.
8.2
Historical Operation
Due to the evolution and enlargement of Sunrise’s Oaktown Mining Complex operations, the Oaktown
Complex CPP underwent modification and expansion to accommodate the complex’s increased coal
production and washing requirements. The plant’s expanded capacity is evidenced by its current average
annual plant feed, which has grown from approximately 6.2 million tons processed in 2012 and 2013, to an
average plant feed of 8.6 million ROM tons between 2017 to 2021.
The Oaktown Complex CPP has historically produced a very consistent clean coal product that possesses
medium ash and high sulfur characteristics and between 11,000 to 12,000 Btu per lb on an as received basis.
The plant’s ability to blend raw coal production from the two underground mines into a singular plant feed
allows for both more consistent plant operation and coal product qualities.
8.3
Future Operations
Sunrise intends to utilize the Oaktown Complex CPP throughout the LOM. Table 7.6 (page 7-9) summarizes
the planned production from the Oaktown Complex CPP over the expected life of the operations.
Annual plant feed (i.e., ROM coal) and clean coal production tonnages over the balance of the LOM are
within the capacities of the Oaktown Complex CPP.
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Figure 8.1
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Figure 8.2
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JOHN T. BOYD COMPANY
8.4
Conclusion
Based on our review of historical processing data and forecasts of future production, it is BOYD’s opinion
that the present processing methods found at Oaktown Complex CPP will be sufficient for future processing
of coals at Oaktown Mining Complex.
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JOHN T. BOYD COMPANY
9.0
MINE INFRASTRUCTURE
9.1
Mine Surface Facilities
Operations at each of the two Oaktown Mining Complex underground mines are supported by multiple
surface facilities located within the areal proximity of the mines’ reserve boundary. Major surface
infrastructure elements include: engineering and business offices, personnel bathhouses, parking areas, supply
yards, warehouse buildings, ventilation fan structures, ventilation air shafts, high voltage power distribution
stations, and primary underground access points, including slope tunnels (for transporting supplies
underground/conveying ROM coal to the surface) and mine portals (shafts for transporting
employees/supplies underground). Figure 3.1 provides a general location map highlighting the layout of the
two Oaktown Mining Complex underground mines and the surface location of their primary deep mine access
points. Each of the Oaktown Mining Complex underground R&P mines maintains their own separate surface
facilities. In terms of industry standards, the Oaktown Mining Complex operations’ surface infrastructure is
comparable to facilities typically found within the ILB mining region.
The current surface facilities located at each of the mines are well constructed and have the necessary
capacity/capabilities to support the Oaktown Mining Complex’s near-term mining plans. Longer term, as the
individual mines progress beyond their near-term mine plans and the location of future mining activities is
centered outside the physical and/or operationally efficient limitations of the existing infrastructure, additional
surface facilities of comparable design may be required to support continued mining (refer to Chapter 11 for a
discussion regarding Sunrise’s expectations for future capital expenditures).
Given Sunrise’s demonstrated ability to steadily construct its expanding surface facility infrastructure in a
timely fashion (relative to underground mine production), the need for continued surface facilities at the
mines of Oaktown Mining Complex is not seen as a hindrance for the execution of the LOM plans.
All ROM output from the Oaktown Mining Complex mines is processed in the Oaktown Complex CPP,
which is discussed in Chapter 8.
JOHN T. BOYD COMPANY
9.2
Oaktown Complex Refuse Facility
The Oaktown Complex refuse facility serves as the disposal location for all waste rock (coarse coal refuse)
and a portion of fine coal slurry (fine coal refuse) produced during the processing of ROM coal from the two
Oaktown Mining Complex underground R&P mines. The majority of the fine coal slurry is transported
overland via a network of pumps and pipelines for underground disposal within mined-out void areas. The
current Oaktown Complex refuse facility encompasses more than 320 permitted acres located adjacent to the
Oaktown Complex CPP and across the Oaktown Mining Complex surface (i.e., to facilitate slurry injection).
The Oaktown Complex surface refuse facility includes one main disposal area for coarse coal refuse and fine
coal refuse. In addition to the one main disposal area, multiple underground slurry injection locations are
located across the Oaktown Mining Complex to utilize void space within mined out areas of the Oaktown
Fuels No. 1 and No. 2 mines.
According to forecasted LOM coal refuse disposal requirements, currently permitted refuse areas can
accommodate coarse disposal through approximately 2031 and fine coal refuse disposal through late-2027 or
early-2028.
Sunrise representatives indicated that the fine refuse disposal plan post-2027 and coarse refuse disposal plan
post-2031 will be based on proven practices and approaches. Sunrise has historically demonstrated the ability
to operate the refuse facility and injection sites in a prudent manner, obtain associated permits, and to execute
construction of disposal areas (injection sites) in a timely fashion. It is BOYD’s opinion that Sunrise’s staged
injection disposal through 2028 will meet the practices demonstrated by other industry peers. At this time,
lack of a properly staged and detailed fine coal refuse disposal plan post-2027 and coarse refuse disposal plan
post-2031 is not seen as a major hindrance to Oaktown Mining Complex meeting the LOM plans.
JOHN T. BOYD COMPANY
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10.0
MARKET ANALYSIS
10.1
Indiana Coal Industry Background
The following section provides a brief description of the Indiana coal mining industry.
10.1.1 Coal Reserves
The coalfield of Indiana covers an area of 6,500 square miles in the southwestern portion of the
state forming the east-central portion of the ILB. The configuration of the coal-bearing area in
Indiana is roughly triangular in shape, with a maximum east-west width of approximately 80 miles
along the Ohio River and extending approximately 200 miles to the north to Benton County. The
state’s coal-bearing strata dip in a southwesterly direction at about 30 ft per mile toward the center
of the ILB in southeastern Illinois.
According to the Indiana Geological Survey, Indiana’s total coal geological resources are
approximately 57 billion tons, of which 17 billion tons is recoverable using current technology. A
distribution by mining method suggests 88% of the state’s mineable resources (15 billion tons) are
recoverable by underground mining techniques with the balance recoverable by surface mining.
Based on current production rates, Indiana's 17 billion tons of available mineable coal resources
could last more than 500 years. Twenty counties within, or partly within, the Indiana coalfield have
significant coal resources. As seen in Table 10.1, below, coal production within the state has been
primarily centered within Gibson, Sullivan, and Knox counties over the past five years.
JOHN T. BOYD COMPANY
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Currently, the Indiana V (Springfield) and VII (Danville) are the Indiana coal seams most extensively
mined, although limited mining is also conducted in the Colchester and Survant seams. The Indiana
VI (Herrin), which is one of the predominant economically mineable seams of the ILB, has limited
presence within Indiana.
10.1.2 Coal Quality
Coal produced in Indiana is typically a medium to high volatile (25% to 30+%) bituminous rank coal
with medium to high thermal content (i.e., ranges from approximately 11,000 to 11,500 Btu/lb) and
relatively high sulfur content. The primary market for Indiana coal is the in-state coal-fired utility
market. Table 10.2, below, summaries the Indiana coal quality shipped to domestic coal-fired
generating plants in 2024, as reported by the U.S. Energy Information Administration (EIA).
Relative to chlorine content, Indiana coals are generally advantaged by relatively low levels of
chlorine across the mining region. A summary of Indiana coal quality, including available chlorine
content data derived from studies completed by the U.S. Geological Survey and other sources, is
provided in Table 10.3, below.
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By comparison, the chlorine content of the Illinois No. 5 (Springfield) and No. 6 (Herrin) coal seams,
which are the two seams mined extensively throughout Illinois, typically ranges from 0.1% to 0.6%.
Coals having chlorine content above 0.3% is found to cause damaging boiler corrosion, a fact that
negatively impacts the marketability of high-chlorine coal produced in Illinois.
10.1.3 Transportation
ILB coal producers are supported by a multi-modal transportation infrastructure system capable of moving
coal to end users by truck, rail, and barge (operating alone and/or in combination). Class I railroads operating
in the region include the Union Pacific, CSX, NS, and the Canadian National. The ILB is also supported by
several regional short-line railways. In many instances, due to geographic location of the mine in relation to
the end-user or river loading facility, rail delivery must be conducted via multi-line movements. Any coal
movement could involve multiple rail-line hauls, third-party controlled river loading facilities, short rail haul
distances or long truck haul distances.
Multiple transportation carriers and multiple transportation modes can have a significant influence on overall
delivered costs. Situations can arise where two mines can be in fairly close proximity with one another, but
one has a decided transportation advantage based on its access to a particular rail service provider.
Several coal producers in the basin have direct or indirect access to the inland waterway system providing
river borne transportation options on the Green, Ohio, and/or Mississippi rivers. Mines located in western
Kentucky are generally better suited to direct river loading than those in Indiana and Illinois.
The Indiana coal fields are crossed by numerous roads and railroads. Feeder lines from Class 1 railroads
support numerous loadout facilities found in the State’s coal-producing counties. In addition, a well-
developed network of federal and state highways crosses the coal-producing region (as well as a supporting
system of secondary all weather roads) and provide adequate truck hauling capacity.
JOHN T. BOYD COMPANY
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10.1.4 Production Evolution
Table 10.4, below, illustrates the progression of Indiana’s coal producers and their associated mines operating
from 2020 to 2024.
In 2016, Indiana’s coal industry produced approximately 29 million tons from 27 mines. By 2020, the number
of operating mines decreased by 26% (to 20) while coal production from the State declined by 31% (to 20
million tons). The modest production rationalization that ensued during that period was primarily driven by
the closure of less productive, marginal operations. As shown in the table above, coal production in the State
has been relatively consistent, both in tons produced and number of active mines.
10.1.5 Mining Methods
Indiana coal operators utilize traditional surface and underground mining technology to produce over 20
million tons annually. Surface mines primarily employ truck/shovel operations and draglines (at select mines);
underground mines typically utilize continuous miners in R&P and/or super-section applications. There are no
LW operations in Indiana. Historical state coal production by mining method is shown in Figure 10.1, on the
following page.
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Figure 10.1: Indiana Coal Production by Mining Method
In 2005, Indiana coal output totaled nearly 35 million tons. In that year, approximately 68% (23.5 million
tons) was produced from surface operations. Due to the depletion of mineable reserves with economic
stripping ratios, as well as the encroachment of urban and farm development over time, coal mining in
Indiana has gradually shifted towards underground operations. In 2024, of the 20.1 million tons of coal
produced, approximately 56% (11.3 million tons) was attributed to surface mines.
10.1.6 Coal Demand by Market
Historically, coal produced from mines in Indiana has been used primarily for electric power generation, with
the balance directed into the industrial coal market (including process heat, steam, and space heating). A
major portion of the Indiana coal industry is located on or near major Class 1 railroads, enabling coal
suppliers to service the regional markets and/or some out of state customers. In 2023, Indiana coal mines
supplied approximately 19.3 million tons into the general coal market. Of the total Indiana coal sales,
approximately 19 million tons (or 98%) went to electric generators, with the remaining balance shipped to
industrial customers (e.g., cement and sugar plants). The annual distribution of Indiana coal shipments by
market sector for 2019 through 2023 is shown in Table 10.5, below.
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In the past five years, Indiana coal has had a limited presence in the international export markets. The
majority of Indiana produced thermal coal is shipped to electricity generating plants in Indiana. Table 10.6,
below, summarizes Indiana thermal coal shipments for the past five years to generating stations by state.
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10-7
In 2023, Indiana thermal coal directed into the domestic U.S. utility market totaled almost 19 million tons. Of
this amount, generating plants operating in Indiana consumed 15.5 million tons or approximately 81% of
Indiana’s total thermal coal deliveries.
10.2
Sunrise Coal
10.2.1 Product Specifications
Sunrise’s primary product from their main mining operations is a thermal coal that is directed into the U.S.
generation market. Indicative quality specifications for coal shipped by Sunrise from the Oaktown Mining
Complex to U.S. generating stations in 2024 is provided in Table 10.7, below.
10.2.2 Primary Markets
Sales into the domestic thermal coal market is Sunrise’s primary focus, accounting for over 97% of the
company’s annual coal production tonnage over the past five years. A summary of Sunrise’s 2020 to 2024
(January to November only) deliveries to U.S. generating stations by state is provided in Table 10.8, below.
JOHN T. BOYD COMPANY
10-8
During this period, the primary markets for Sunrise have been Indiana and Florida.
As an existing producer with a lengthy commercial history and established customer base, it is BOYD’s
opinion that market entry strategies are not required for continued sale of the Oaktown Mining Complex’s
thermal coal products.
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10.2.3 Market Outlook
Coal use among domestic power generators has fallen out of favor in the United States and is systematically
being replaced by natural gas and renewable forms of generation. In response to this development, domestic
thermal coal markets are expected to weaken over the next few years, in line with coal plant retirements and
the associated drop in coal demand. However, recent cold weather has increased domestic coal consumption,
particularly in the midcontinent and mid-Atlantic regions that rely on coal for a significant portion of their
electric power generation. In the near term, increased power demand and higher than average natural gas
prices are expected to drive coal demand and pricing.
10.2.4 Future Sales
Sunrise is expected to align its future sales with the U.S. market trends, although the regional Indiana market
is expected to remain relatively firm over the near term.
As shown in Figure 10.2, below, a significant portion of Sunrise’s near-term coal production is “committed”
(i.e., allocated) to existing supply contracts/agreements. It is reasonable to expect Sunrise to commit future
production on an ongoing basis according to its business strategies.
Figure 10.2: Future Coal Sales by Order Type
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10-10
Historically, the top-five customers by sales revenue account for approximately 75% to 85% of total coal
sales from the Oaktown Mining Complex annually.
10.2.5 Price Forecast
Market prices for Sunrise’s thermal coal products are influenced by many factors, and the coal market
environment can be volatile. The primary factors influencing future prices include: (1) demand, primarily at
scrubbed base-load stations, (2) competition in the form of other regional coal suppliers, natural gas-fired
generation, and renewables, (3) exhaustion of competing regional mines (thereby reducing local fuel supply),
(4) transportation differentials, and (5) cost structures associated with sustained coal production levels.
Coal prices can change quickly. This has been demonstrated in the current market environment, as the price of
Illinois Basin coal has rebounded by somewhere between $10/ton and $20/ton in various marketplaces in the
span of a few months; coal prices have moved from the $30s in early 2021 to somewhere in the $40s or $50s
by the end of 2021. Prices continued to rise into the low $60 range by 2023 but fell off slightly into the
low-$50s in 2024. This is the result of increased demand coupled with declining stockpiles and a relatively
constrained production response from mine operators.
The prices of competing fuel sources for power generation are meaningful, with the price of natural gas being
the most significant. Coal and natural gas are at relative parity at a natural gas price of $2.50 per MMBtu, and
when natural gas prices are more than $3 per MMBtu, coal becomes the fuel of choice. The relative scarcity
of natural gas in the marketplace has resulted in prices that have recently surpassed $4 per MMBtu, which has
further enhanced the competitiveness of coal, even at robust coal prices. While it is reasonable that there will
eventually be some pullback in this marketplace, the current market for Illinois Basin coal is likely to remain
strong for the next two years. Likewise, the lack of recent investment throughout the Illinois Basin will
preclude meaningful coal production responses across that Basin that could contribute to oversupply.
BOYD anticipates the recent slow rise in coal pricing to be indicative of the market conditions over the next
four years (2025 through 2028). Thereafter, we expect a pricing that is in the mid-to-high $40s/ton (FOB
CPP) range when expressed in constant dollars.
BOYD’s price forecast for the Oaktown Mining Complex’s future coal sales is a weighted average of
Sunrise’s committed sales prices and our forecasted prices for uncommitted (or spot) sales. Our coal price
forecast for the Oaktown Mining Complex is provided in Table 10.9, below.
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As shown, BOYD expects selling prices (FOB CPP) for the Oaktown Mining Complex’s thermal coal
products to range from $47.25 to $51.47 and average $48.72 per clean ton over the life of the reserves.
JOHN T. BOYD COMPANY
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11.0
CAPITAL AND OPERATING COSTS
11.1
Historical Financial Performance
Oaktown Mining Complex’s performance relative to productivity, cost control, and production has
made it one of the leading underground coal operators within the ILB region. Comprised of two
state-of-the-art underground R&P mines, the operation’s ability to consistently achieve high annual
output at generally low operating costs is attributed to its well-capitalized operations and financial
controls.
Table 11.1 summarizes the past five years of financial data for the Oaktown Mining Complex.
Over the five-year period:
●
Oaktown Mining Complex’s average realization (i.e., coal selling price) was range-bound
between $39.50 and $60.78 per ton.
●
Cash operating costs for the complex were approximately $8.45 per ton higher in 2024 than
2023, primarily due to significant increases in direct labor and direct operating costs due to one-
time reduction in workforce expenses.
●
In response to weakening market conditions, Sunrise reduced production from Oaktown Mining
Complex in early 2024 by idling the Oaktown Fuels No. 2 Mine. The drop in overall output in
2024, combined with one-time expenses related to the reduction in workforce, resulted in an
increase to the complex’s average unit cost (and declining cash margins) for 2024.
JOHN T. BOYD COMPANY
11-2
Cost performance for the individual mines is portrayed graphically in Figure 11.1, below.
Figure 11.1: Historical Operating Costs by Mine
Historically, the Oaktown Fuels No. 1 and No. 2 mines have had operating costs that compare favorably with
other industry producers.
Of the two Oaktown Mining Complex underground R&P mines, Oaktown Fuels No. 1 Mine
has consistently demonstrated the lowest operating cost over the past five years. This is
predominantly attributable to more favorable geologic conditions experienced and
increased economies of scale2.
Relative to industry peers, the Oaktown Mining Complex (including its supporting centralized preparation
facilities) is well capitalized. This reflects Sunrise’s ongoing attention to prudent capital upgrade/replacement
programs, routine investment in mine infrastructure expansions, and maintenance of production equipment.
The amount of capital spent (per individual mine or for the Oaktown Complex CPP) has varied on an annual
basis as a percent of Oaktown Mining Complex’s total expenditures, illustrating differing capital requirements
and/or operational timelines for each operation. Notwithstanding the significant capital expenditures of 2022
and
2 Economies of scale are of fundamental importance; a mine that has a productive year versus its budgeted plan
can expect to have low unit costs while surpassing projected margins. Alternatively, a R&P mine that achieves poor
production levels would see a proportional reduction in revenue, but this would not be accompanied by a corresponding
reduction in total costs. Such a mine would instead see high unit costs, and most of the revenue loss would flow through
to the bottom line.
JOHN T. BOYD COMPANY
11-3
2023 for major equipment rebuilds, Oaktown Mining Complex’s aggregate capital expenditure level was
relatively consistent and generally within the range of $4.00 to $5.00 per clean ton.
11.2
Estimated Costs
BOYD developed mine plans for the Oaktown Mining Complex based on engineered mine layouts3 which
were designed for optimum reserve recovery, using efficient mining methods and practices. Sunrise’s
historical and generally accepted industry operating performance parameters and mining rates were applied to
the mine plan to develop coal production and mining schedules. Financial budgets were then prepared (based
on mine plan outputs and labor requirements), resulting in operating cost projections (based on constant 2021
dollars). The individual mining plans recognize the impact of variations in physical mining conditions,
mechanical failures, and operational activities that can temporarily disrupt production activities. The mine
plans for Oaktown Mining Complex are reasonable and achievable, provided no major abnormalities are
encountered.
Forecasting performance based on the continuation of consistent mining conditions, excluding impacts from
unforeseen events, increases the risk of underperformance versus the mine plan. BOYD’s approach does not
directly account for situations that can occur in underground coal mining, such as fire, water inundations,
geological anomalies, etc. However, risk mitigation has been reflected in the production schedules through the
use of multiple CM sections operating in various locations throughout the mine reserve. The geographical
distribution of mining sections throughout the area of the mine plan mitigates the likelihood that all CM
sections will experience adverse mining conditions at a given time. Each CM section also utilizes production
contingency factors, which are incorporated into the mining forecast.
BOYD reviewed historical Sunrise mining plans (including development strategy, production and
productivity, capital expenditures, and total cash costs) and concluded: (1) the Sunrise pro-forma plans are
reasonable and achievable and align with BOYD’s independent LOM plans, and (2) Oaktown Mining
Complex is well-positioned to achieve the conceptual LOM plan as projected by BOYD provided no major
abnormalities are encountered: within the coal market, or at the mine level.
3 The mining plans for R&P operations are relatively simple and highly flexible when compared to LW mines. The
entire foundation of the mining plan is based upon locating mains and sub-mains in areas of the deposit where coal
quality and mining conditions are most suitable. Panels are then developed out to a desired length or until adverse mining
conditions (or poor coal quality) warrant the cessation of development. This results in the opportunity to alter the mining
plan so as to avoid specific areas with adverse mining conditions (such as thin coal, poor roof, etc.) or poor coal quality
(such as high sulfur, etc.).
JOHN T. BOYD COMPANY
11-4
The Sunrise forecasted financial performance aligns with what BOYD would anticipate for an established
underground R&P coal facility operating in the ILB region. BOYD developed an independent LOM
projection for operating and capital costs which aligns with general industry standards and the Sunrise
forecasted figures. BOYD believes the extended LOM projection of operating and capital costs to align with
those of other similarly capitalized mining complexes operating in the ILB region and to be accurate to within
±25%. We did not assign a contingency budget to the extended life-of-mine projection estimates.
In general, the projected operating costs and capital expenditures over the life of the coal reserves are
informed by general engineering principles and are consistent with industry norms. BOYD considered the
estimated costs reasonable and appropriate.
11.2.1
Forecasted Production
BOYD’s LOM plans reflect: (1) the near-term continued idling of the Oaktown Fuels No. 2 Mine, and (2)
status quo production levels from the Oaktown Fuels No. 1 Mine. The Oaktown Mining Complex forecast of
saleable tons produced is summarized in Figure 11.2, below.
Figure 11.2
Oaktown Mining Complex
Projected Saleable Production
Oaktown Mining Complex’s future production over the life of the reserves are expected to remain well within
the complex’s previously achieved output levels and in line with current infrastructure capacities and
capabilities. This results in a less capital-intensive
JOHN T. BOYD COMPANY
11-5
forward forecast, as capital expenditures are associated with sustaining production rather than new
mine development and/or production capacity expansion.
11.2.2 Projected Operating Costs
Operating cost estimates were developed based on recent actual costs and considering specific operational
activity levels and cost drivers. The estimates consider current and expected labor headcount and salaries,
major consumables and unit prices, power costs, and equipment and maintenance costs. The total operating
cost estimate includes all site costs related to mining, processing, and general and administrative activities.
Operating costs for Oaktown Mining Complex are projected to be more favorable versus those of 2024. This
is primarily a result of reduced direct operating costs associated with the recent restructuring of mining
operations, including the near-term idling of the Oaktown Fuels No. 2 Mine. BOYD anticipates relatively
stable operating costs over the remaining life of the operations as the result of consistent performance and
annual output. BOYD’s estimate of operating costs over the life of the Oaktown Mining Complex as
presented in Table 11.2, on the following page.
11.2.3
Projected Capital Expenditures
The Oaktown Mining Complex and related facilities are fully developed and should not require any near-term
major capital investment to maintain full commercial production. Historically, the timing and amount of
capital expenditures have been largely discretionary and within Sunrise’s control.
Oaktown Mining Complex is expected to maintain a consistent level of spending on capital over the
remaining life of the operations, focused on mine infrastructure expansion, maintenance of production
equipment (new equipment purchases and/or rebuilds), and refuse placement (injection) expansions. BOYD
projected sustaining capital expenditures using nominal unit cost rates which includes maintenance of
production equipment as well as other items for the operation. These unit cost rates are based on our
experience with other ILB underground R&P operations. Over the final four years of the Oaktown Mining
Complex’s operation, capital expenditures are projected to decline as production volumes decrease. BOYD’s
estimates of capital expenditure requirements over the life of the Oaktown Mining Complex are presented in
Table 11.2, on the following page.
q:\eng_wp\3467.008 sunrise - fy2024\wp\report\ch-11 - capital and operating costs.docx
JOHN T. BOYD COMPANY
11-6
JOHN T. BOYD COMPANY
12-1
12.0
ECONOMIC ANALYSIS
12.1
Approach
The economic analysis presented in this chapter was prepared by BOYD for the purpose of confirming the
commercial viability of the Oaktown Mining Complex’s reported coal reserves and not for the purpose of
valuing the Oaktown Mining Complex, or its assets. The economic analysis contains forward-looking
information related to the projected operating and financial performance of the Oaktown Mining Complex.
This projection involves inherent known and unknown risks and uncertainties, some of which may be outside
of Sunrise’s control. Sunrise, as with all mining companies, actively evaluates, changes, and modifies
business and operating plans in response to various factors that may affect operational and/or financial results.
Actual results, production levels, operating expenses, sales realizations, and all other modifying factors could
vary significantly from the assumptions and estimates provided in this analysis. Risk is subjective, as such,
BOYD recommends that each reader should evaluate the project based on their own investment criteria.
The financial model used for the purposes of the economic analysis forecasts future free cash flow from coal
production and sales over the life cycle of the Oaktown Mining Complex using the annual forecasts of
production, sales revenues, and operating and capital costs discussed earlier in this report. A DCF analysis, in
which future free cash flows are discounted to present value, is used to derive an NPV for the coal reserves.
The use of DCF-NPV analysis is a standard method within the mining industry to assess the economic value
of a project after allowing for the cost of capital invested.
The financial evaluation of the Oaktown Mining Complex has been undertaken on a simplified after-tax basis
and does not reflect Sunrise’s corporate tax structure. NPV is calculated using an after-tax discount rate of
12% (NPV12). Cash flows were assumed to occur in the middle of each year and are discounted to January 1,
2025. Cost estimates and other inputs to the cash flow model for the project have been prepared using
constant 2024 money terms, i.e., without provision for inflation. The internal rate of return and project
payback were not calculated, as there was no initial investment (sunk costs) considered in the financial model
provided herein.
JOHN T. BOYD COMPANY
12-2
A suite of sensitivities was calculated to evaluate the effect of the main drivers of economic performance
(including variations in sales prices, operating costs, and capital costs).
It is BOYD’s opinion that the financial model provides a reasonable and accurate reflection of the Oaktown
Mining Complex’s expected economic performance based on the assumptions and information available at
the time of our review.
12.2
Assumptions and Limitations
Cash flow projections for the Oaktown Mining Complex have been generated from the annual
forecasts of production, sales prices, and operating and capital costs discussed earlier in this report.
A summary of the key assumptions and limitations is provided below:
●
Production quantities are based on BOYD’s independently developed LOM plans for the
Oaktown Mining Complex. Please refer to Chapters 7 and 8 for further information.
●
Forecasted revenues are based on BOYD’s FOB sales price forecast for washed thermal coal
from the Oaktown Mining Complex’s CPP (i.e., FOB CPP). Additional transportation and
delivery costs are assumed to be incurred by the customer or added as a pass-through to the FOB
CPP price. Market specifications and forecasted sales prices for the Oaktown Mining Complex’s
washed thermal coal are provided in Chapter 10.
●
Capital and operating costs are discussed in Chapter 11. Capital expenditures and unit operating
costs are expected to remain relatively constant over the life of the operation.
●
No allowance for changes in or the recapture of working capital has been made in the financial
analysis as the Oaktown Mining Complex has been in operation for many years. Exclusion of
working capital from the financial analysis does not have a material impact on the NPV
calculation.
●
Depreciation and amortization expenses for existing assets are derived from Sunrise’s
depreciation schedules. Sustaining capital is depreciated over 8 years on a straight-line basis.
●
A combined federal and state corporate tax rate of 25% has been applied on all taxable income.
All other taxes and fees are included in the estimates of operating costs.
JOHN T. BOYD COMPANY
12-3
●
Asset recovery/salvage values were not included in the financial analysis.
●
Post-mining reclamation costs are included as a lump sum operating cost in the final year of the
financial analysis.
It is BOYD’s opinion that the production and financial projections provided herein are reasonable
and are accurate to within ±25%.
12.3
Financial Model Results
Estimated LOM pre-tax and after-tax cash flows for coal production from the Oaktown Mining Complex are
presented in Table 12.1 (on the following page) and summarized in Table 12.2 (below).
DCF-NPV on a pre-tax and after-tax basis, using discount rates of 10%, 12% (the base case), 15%, and 18%
were calculated utilizing the projected cash flows. Table 12.3, below, summarizes the results of the pre-tax
and after-tax DCF-NPV analyses.
JOHN T. BOYD COMPANY
12-4
12-5
The economic analysis confirms that the Oaktown Mining Complex generates positive pre- and after-tax
financial results and a real NPV12 of $70.7 million. As such, it is BOYD’s opinion that the coal reserves of the
Oaktown Mining Complex have demonstrated economic viability.
12.4
Sensitivity Analysis
Table 12.4, below, shows the sensitivity of the project after-tax for a cash flow discounted at 12% (NPV12) to
a variation over a range of 20% above and below the base case in: (1) average selling prices and (2) operating
costs.
JOHN T. BOYD COMPANY
As expected, the project is most sensitive to changes in product pricing and operating costs. The project is less
sensitive to changes in capital costs. There are only very minor impacts to the NPV12 when varying the capital
costs from 80% to 120% of the base case.
This analysis demonstrates the project value to be very sensitive to fluctuations in coal sales prices and/or
operating costs. However, BOYD recognizes that Sunrise is likely to modify operation plans and/or
production levels to minimize the impact (or conversely, maximize the opportunity) of short-term coal price
fluctuations. BOYD opines that such minor adjustments are likely to be immaterial to the economic viability
of the Oaktown Mining Complex’s coal reserves.
JOHN T. BOYD COMPANY
13-1
13.0
PERMITTING AND COMPLIANCE
13.1 Permitting Requirements and Status
Mining and related activities on the Oaktown Mining Complex properties is regulated by both federal and
state laws. The relevant federal laws include:
●
Clean Air Act of 1970/1977.
●
Clean Air Act Amendments of 1990.
●
Clean Water Act of 1977.
●
Surface Mining Control and Reclamation Act of 1977 (SMCRA).
●
Resource Conservation and Recovery Act of 1976.
In Indiana and Illinois, responsibility for enforcing these acts primarily lies with the IL-EPA and IN-DNR and
their various subdivisions.
Numerous permits are required by federal and state law for underground mining, coal preparation and related
facilities, and other incidental activities. BOYD reviewed the permits for the Oaktown Mining Complex that
are necessary for continued operations. Such required permits appear to be valid and in good standing. The
approved permits and certifications are adequate for the continued operation of the facility. A listing of the
current permits for the Oaktown Mining Complex is provided in Table 13.1, on the following page.
Permits generally require that the permittee post a performance bond in an amount established by the
regulator program to: (1) provide assurance that any disturbance or liability created during mining operation
is properly mitigated, and (2) assure that all regulations requirements of the permit are fully satisfied. Sunrise
reports holding surety
JOHN T. BOYD COMPANY
13-2
bonds to cover its current obligations relating to mining and reclamation, road repair, etc. Those obligations
currently equate $6.7 million.
New permits and/or permit revisions/amendments may be necessary from time to time to facilitate future
operations. Given sufficient time and planning, Sunrise should be able to secure new permits, as required, to
maintain its planned operations within the context of the current regulations. Continuously increasing efforts
are required to obtain permits for R&P mining and related activities in Indiana and Illinois. The primary
contributing factors are the effects on protected surface areas and the ability to permit refuse sites.
JOHN T. BOYD COMPANY
13-3
13.2
Environmental Studies
It is BOYD’s understanding that no standalone environmental studies have been conducted for the Oaktown
Mining Complex. As part of the state and federal permitting process, various environmental assessments have
been conducted and reviewed by the relevant local, state, and federal agencies. As the necessary permits for
mining and processing operations have been issued, it is BOYD’s understanding that all environmental
assessments have been accepted by the relevant regulatory bodies and no material issues were found.
13.3
Waste Disposal and Water Management
The coarse refuse generated from the coal preparation process is used in the construction of the existing
permitted, on-site slurry impoundment. The fine refuse generated from the coal preparation process is
disposed of by pumping it into the slurry impoundment or by injecting it into former underground mining
areas. Waste disposal facilities are in place for current mining operations, with plans to expand the disposal
facilities to meet life of reserve storage requirements. Please refer to Section 9.2 for a detailed description of
these facilities.
The underground mines are below drainage with shaft/slope access. Such mines are designed and permitted to
avoid water break out and acid mine discharge. The potential for discharge of acid mine drainage at
underground mines is limited to minor run off from disposal and other surface sites.
Water control structures are in place and function as required by regulatory agencies. All runoff from the
slurry impoundment(s) is managed by sediment control structures including diversions, sumps, and sediment
basins. Prior to discharge from the permitted areas, water must meet compliance standards as defined in the
NPDES permits. Water samples at discharge locations are collected in accordance with the approved permit
and analyzed by an independent laboratory.
13.4
Compliance
Based on our review of information provided by Sunrise and other public information sources, it is BOYD’s
opinion that Sunrise has a generally typical coal industry record of compliance with applicable mining, water
quality, and environmental regulations. BOYD is not aware of any regulatory violation or compliance issue
that would materially impact the coal reserve estimate.
JOHN T. BOYD COMPANY
13-4
13.5
Plans, Negotiations, or Agreements
New permits and certain permit amendments/revisions require public notification. The public is made aware
of pending permits by advertisement in local newspapers. Additionally, a copy of the
application is retained at the local county’s public library for review. A comment period follows the last
advertisement date to allow the public to submit comments to the regulatory authority.
BOYD is not aware of any community or stakeholder concerns, impacts, negotiations, or agreements that
would materially impact the coal reserve estimate.
13.6
Mine Closure
A detailed plan for reclamation activities upon completion of mining required at the Oaktown Mining
Complex has been prepared. Given the application of underground mining methods at the operation, the
disturbed acreage on the surface is relatively limited. The primary reclamation liabilities are associated with
the refuse disposal sites.
Mine site reclamation costs are funded from Sunrise’s operating account. Funding for reclamation liabilities is
included in the Oaktown Mining Complex’s operating costs discussed in Chapter 11 and included in the
economic analysis presented in Chapter 12. Reclamation liability estimates are reviewed annually and are
currently estimated at approximately $6.7 million for the Oaktown Mining Complex. In BOYD’s opinion, the
estimated mine closure and reclamation costs for the property are reasonable and appropriate.
13.7
Local Procurement and Hiring
BOYD is not aware of any commitments for local procurement or hiring. However, Sunrise reports making
efforts to source supplies and materials from regional vendors. The workforce is likewise located in the
regional area.
JOHN T. BOYD COMPANY
14.0
INTERPRETATION AND CONCLUSIONS
14.1
Findings
BOYD’s independent technical assessment conducted in accordance with S-K 1300 concludes:
●
Sufficient data have been obtained through various exploration and sampling programs and
mining operations to support the geological interpretations of seam structure, thickness, and
quality for the portions of the Indiana V Seam situated within the bounds of the Oaktown Mining
Complex area. The data are of sufficient quantity and reliability to reasonably support the coal
resource and coal reserve estimates in this technical report summary.
●
Estimates of coal reserves reported herein are reasonably and appropriately supported by
technical studies, which consider mining plans, revenue, and operating and capital cost
estimates.
●
The 34.4 million tons of underground coal reserves identified on the property are economically
mineable under reasonable expectations of market prices for thermal coal products, estimated
operation costs, and capital expenditures.
●
There is no other relevant data or information material to the Oaktown Mining Complex that is
necessary to make this technical report summary not misleading.
14.2
Significant Risks and Uncertainties
As a mining operation with a lengthy operating history, the purpose of Sunrise’s periodic mine planning
exercises is to collect and analyze sufficient data to reduce or eliminate risk in the technical components of
the project and to refine economic projections based on current data. There is a high degree of certainty for
this project under the current and foreseeable operating environment. A general assessment of risk is
presented in the relevant sections of this report.
14-1
GLOSSARY OF ABBREVIATIONS AND DEFINITIONS - Continued
JOHN T. BOYD COMPANY
GLOSSARY OF ABBREVIATIONS AND DEFINITIONS
$
:
U.S. dollar(s)
%
:
Percent or percentage
AC
:
Alternating current
As-Received Basis
:
Data or results are calculated to the moisture condition of the coal sample when
it arrived at the testing facility.
ASTM
:
ASTM International (formerly American Society for Testing and Materials)
BOYD
:
John T. Boyd Company
Btu
:
British thermal unit. A unit of heat; it is defined as the amount of heat required to
raise the temperature of one pound of water by one degree Fahrenheit.
CM
:
Continuous Miner
CPP
:
Coal Preparation Plant
Coal
:
Combustible sedimentary rock in which organic matter, including residual
moisture comprises more than 50% by weight and more than 70% by volume of
carbonaceous material formed from altered plant remains.
Coal Reserve
:
An estimate of tonnage and grade or quality of indicated and measured coal
resources that, in the opinion of the qualified person, can be the basis of an
economically viable project. More specifically, it is the economically mineable
part of a measured or indicated coal resource, which includes diluting materials
and allowances for losses that may occur when the material is mined or
extracted.
Coal Resource
:
A concentration or occurrence of coal of economic interest in or on the Earth's
crust in such form, quality, and quantity that there are reasonable prospects for
economic extraction. A coal resource is a reasonable estimate of mineralization,
considering relevant factors such as cut-off grade, likely mining dimensions,
location, or continuity, that, with the assumed and justifiable technical and
economic conditions, is likely to, in whole or in part, become economically
extractable. It is not merely an inventory of all mineralization drilled or sampled.
CRDA
:
Coal Refuse Disposal Area
GLOSSARY OF ABBREVIATIONS AND DEFINITIONS - Continued
JOHN T. BOYD COMPANY
CSX
:
CSX Corporation. A rail-based freight transportation company
CY
:
Cubic yards
DCF
:
Discounted Cash Flow
DOR
:
Indiana Department of Natural Resources’ Division of Reclamation
Dry Basis
:
Data or results are calculated to a theoretical base as if there were no moisture
in the coal sample.
EIA
:
U.S. Energy Information Administration
FOB
:
Free-on-Board
Hallador
:
Hallador Energy Company and its subsidiaries
ILB
:
Illinois Basin. Coal producing region consisting of Illinois, Indiana, and Western
Kentucky.
IL-EPA
:
Illinois’s Environmental Protection Agency
IN-DNR
:
Indiana’s Department of Natural Resources
Indicated Coal
Resource
:
That part of a coal resource for which quantity and quality are estimated based
on adequate geological evidence and sampling. The level of geological
certainty associated with an indicated coal resource is sufficient to allow a
qualified person to apply modifying factors in sufficient detail to support mine
planning and evaluation of the economic viability of the deposit. Because an
indicated coal resource has a lower level of confidence than the level of
confidence of a measured coal resource, an indicated coal resource may only
be converted to a probable coal reserve.
INRD
:
Indiana Railroad Company. A rail-based freight transportation company
Inferred Coal
Resource
:
That part of a coal resource for which quantity and quality are estimated based
on limited geological evidence and sampling. The level of geological uncertainty
associated with an inferred coal resource is too high to apply relevant technical
and economic factors likely to influence the prospects of economic extraction in
a manner useful for evaluation of economic viability. Because an inferred coal
resource has the lowest level of geological confidence of all coal resources,
which prevents the application of the modifying factors in a manner useful for
evaluation of economic viability, an inferred coal resource may not be
considered when assessing the economic viability of a mining
GLOSSARY OF ABBREVIATIONS AND DEFINITIONS - Continued
JOHN T. BOYD COMPANY
project, and may not be converted to a coal reserve.
IRR
:
Internal rate-of-return
ISO
:
International Organization for Standardization
lb
:
Pound
LOM
:
Life-of-Mine
LW
:
Longwall
Measured Coal
Resource
:
That part of a coal resource for which quantity and quality are estimated based
on conclusive geological evidence and sampling. The level of geological
certainty associated with a measured coal resource is sufficient to allow a
qualified person to apply modifying factors, as defined herein, in sufficient detail
to support detailed mine planning and final evaluation of the economic viability
of the deposit. Because a measured coal resource has a higher level of
confidence than the level of confidence of either an indicated coal resource or
an inferred coal resource, a measured coal resource may be converted to a
proven coal reserve or to a probable coal reserve
Mineral Reserve
:
See “Coal Reserve”
Mineral Resource
:
See “Coal Resource”
Modifying Factors
:
The factors that a qualified person must apply to indicated and measured coal
resources and then evaluate to establish the economic viability of coal
reserves. A qualified person must apply and evaluate modifying factors to
convert measured and indicated coal resources to proven and probable coal
reserves. These factors include, but are not restricted to: mining; processing;
infrastructure; economic; marketing; legal; environmental compliance; plans,
negotiations, or agreements with local individuals or groups; and governmental
factors. The number, type and specific characteristics of the modifying factors
applied will necessarily be a function of and depend upon the mineral, mine,
property, or project.
MSHA
:
Mine Safety and Health Administration. A division of the U.S. Department of
Labor
NPDES
:
National Pollutant Discharge Elimination System
NS
:
Norfolk Southern Corporation. A rail-based freight transportation company.
GLOSSARY OF ABBREVIATIONS AND DEFINITIONS - Continued
JOHN T. BOYD COMPANY
NPV
:
Net Present Value
GLOSSARY OF ABBREVIATIONS AND DEFINITIONS - Continued
JOHN T. BOYD COMPANY
Oaktown Mining
Complex
:
Oaktown Mining Complex. Includes the Oaktown Fuels No. 1 Mine,
Oaktown Fuels No. 2 Mine, and Oaktown Complex Coal Preparation Plant
OSD
:
Out-of-Seam Dilution. Rock, impurities recovered from above and below
the coal seam with the coal seam during the normal mining process
OSMRE
:
Office of Surface Mining, Reclamation and Enforcement
Probable Coal
Reserve
:
The economically mineable part of an indicated and, in some cases, a
measured coal resource.
Production Stage
Property
:
A property with material extraction of coal reserves.
Proven Coal
Reserve
:
The economically mineable part of a measured coal resource which can
only result from conversion of a measured coal resource.
QP
:
Qualified Person
Qualified Person
:
An individual who is:
1.
A mineral industry professional with at least five years of relevant
experience in the type of mineralization and type of deposit under
consideration and in the specific type of activity that person is
undertaking on behalf of the registrant; and
2.
An eligible member or licensee in good standing of a recognized
professional organization at the time the technical report is prepared.
For an organization to be a recognized professional organization, it
must:
a. Be either:
i.
An organization recognized within the mining industry as a
reputable professional association; or
ii.
A board authorized by U.S. federal, state, or foreign statute to
regulate professionals in the mining, geoscience, or related
field;
b.
Admit eligible members primarily based on their academic
qualifications and experience;
c.
Establish and require compliance with professional standards of
competence and ethics;
d.
Require or encourage continuing professional development;
e.
Have and apply disciplinary powers, including the power to
suspend or expel a member regardless of where the member
practices or resides; and
GLOSSARY OF ABBREVIATIONS AND DEFINITIONS - Continued
JOHN T. BOYD COMPANY
f.
Provide a public list of members in good standing.
R&P
:
Room-and-pillar
RC
:
Ram cars
ROM
:
Run-of-Mine. The as-mined material including coal, in-seam rock partings
mired with the coal, and out-of-seam dilution.
SC
:
Shuttle cars
SGF
:
Specific gravity float
SEC
:
U.S. Securities and Exchange Commission
S-K 1300
:
Subpart 1300 and Item 601(b)(96) of the U.S. Securities and Exchange
Commission’s Regulation S-K
SMCRA
:
Surface Mining Control and Reclamation Act of 1977
Sunrise
:
Sunrise Coal, LLC and its subsidiaries
Ton
:
Short Ton. A unit of weight equal to 2,000 pounds
TPH
:
Tons per Hour
TPEH
:
Tons per Employee-Hour