HNRG 10-K & 10-Q changes, risk factors and insider trading

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.

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.

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.

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 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 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.

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 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:

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.

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.

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.

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.

Solid Forward Sales Position - Segment Basis, Before Intercompany Eliminations

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 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.

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.

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.

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 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

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 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:

•Forward-Looking Statements. This section provides a description of certain factors that could cause actual results or events to differ materially from anticipated results or events.

•Overview. This section provides a general description of our business and recent events.

•Material Changes in Results of Operations. This section provides an analysis of our results of operations for the three months ended March 31, 2026 and 2025.

•Material Changes in Financial Condition. This section provides an analysis of our liquidity and our condensed consolidated statements of cash flows.

You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; 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.

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable included in fuel and other operating costs.

Fuel costs on a segment basis decreased $10.5 million, or 27.7%, from the first quarter of 2025. Fuel costs on a consolidated basis decreased $0.2 million or 1.5%, from the first quarter of 2025. The decrease is due to electricity generation falling by 0.5 million MWh, or 34.0%. We used 0.2 million tons less in production on both a segment and consolidated basis, as we utilized 0.2 million less tons produced at the Oaktown mining complex in 2026 compared to 2025. The decrease in electric power generation was attributable to the aforementioned equipment issues, which resulted in 0.5 million lower MWh generated, compared to the same period in 2025. The weather contributed to higher demand for electricity and natural gas causing an increase in the average spot price at Chicago citygate of $1.30 per thousand cubic feet to $5.70 per thousand cubic feet in January 2026 compared to January 2025. Total fuel costs were impacted by an increase in the cost of coal consumed from $53.80 per ton in 2025 to $54.58 per ton in 2026.

Utilities expense decreased $0.5 million, or 80.2%, in the first quarter of 2026 compared to 2025. The change was attributable to decreased production at Merom, as well as new meters installed in 2025 that allow for active management of pricing of auxiliary power in the day-ahead market.

Segment operating revenue from coal operations (including intercompany sales to Merom) decreased $8.4 million, or 15.3%, compared to the first quarter of 2025. The decrease was driven by lower volume partially offset by an increase in the average sales price for our coal. We sold 0.9 million tons of coal during the first quarter of 2026, a decrease of 0.2 million tons, or 20.3%, versus 2025. Our average sales price, on a segment basis, increased $3.21 per ton from $51.14 per ton to $54.35 per ton. The decreased sales were driven by lower coal demand from Merom due to the aforementioned equipment issues. Sunrise sold 0.3 million fewer tons of coal to Merom, offset by a 7.2% increase in tons sold to third parties in the first quarter of 2026 compared to 2025. On a consolidated basis, third party sales increased $4.9 million, or 16.2%, versus the first quarter of 2025 attributable to 0.3 million incremental tons sold to third parties, supplemented by an 8.4% increase in our average third party price per ton.

Other operating and maintenance costs decreased $3.6 million, or 15.0%, which is attributable to the decrease in total tons sold of 0.2 million, or 20.3%, versus the first quarter of 2025, partially offset by mine expansion costs at Oaktown. Labor expenses increased $0.4 million, or 2.0%, from the first quarter of 2025; however, because tons sold declined 20.3%, labor cost per ton sold rose $4.92 as production at the mine outpaced coal sales.

Depreciation, Depletion and Amortization decreased by $5.6 million, or 57.1%, compared to the first quarter of 2025, partially attributable to the lower production during the first quarter of 2026. Following the impairment of our coal operations, the cost basis of our coal operations assets upon which depreciation, depletion and amortization is calculated was also lower resulting in significantly lower expense.

Interest expense decreased $1.2 million, or 59.4%, from $2.0 million for the three months ended March 31, 2025 to $0.8 million in 2026. The decrease is attributable to the paydown of the Company’s bank facility from $30.0 million at December 31, 2025 to zero at March 31, 2026.