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Item 7. Management’s Discussion and Analysis

2026-03-12 compared with 2025-03-17 · 237 added, 439 removed, 155 unchanged (81% of the section changed)

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.

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.

The following discussion and analysis, which should be read in conjunction with our consolidated financial statements, is intended to assist in providing an understanding of our results of operations and financial condition and is organized as follows:

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

● Results of Operations.

This section provides an analysis of our results of operations for the years ended December 31, 2025 and 2024.

● Liquidity and Capital Resources.

This section provides an analysis of our liquidity and consolidated statements of cash flows.

● Critical Accounting Policies, Judgments and Estimates.

This section discusses those material accounting policies that involve uncertainties and require significant judgment in their application.

● Quantitative and Qualitative Disclosures about Market Risk.

This section provides discussion and analysis of the commodity, interest rate and other market risks that our company faces.

Included below is an analysis of our results of operations and cash flows for 2025, as compared to 2024.

An analysis of our results of operations and cash flows for 2024, as compared to 2023, can be found under “ Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Part II of our Annual Report on Form 10-K for the year ended December 31, 2024, which is available through the SEC’s website at www.sec.gov.

The capitalized terms used below have been defined in the notes to our consolidated financial statements.

In the following text, the terms “we,” “our,” “our company” and “us” may refer, as the context requires, to Hallador or collectively to Hallador and its subsidiaries.

Hallador is a vertically integrated, independent power producer IPP and fuel company with operations primarily in Indiana.

The Company operates across multiple stages of the energy supply chain, from accredited capacity and energy to coal.

The Company’s electric operations are located within the MISO footprint.

Our operations comprise Hallador Power that provides accredited capacity and energy to utilities and other energy market participants through the MISO interconnection, and Sunrise that mines bituminous coal in Indiana to serve various power plants in the Midwest and Southeast United States.

Our business is organized based on the services and products we provide in two segments:

(i) Electric Operations and (ii) Coal Operations.

The Company also holds 50% interests in Sunrise Energy, LLC and Oaktown Gas, LLC, which are accounted for using the equity method.

Through its operating subsidiaries, the Company delivers three main products to its customers.

Accredited Capacity.

Hallador Power, the Company’s wholly-owned electric subsidiary, owns and operates the Merom Power Plant (“Merom”), a 1,080 MW coal-fired power generating station, consisting of two steam turbine generators.

Unit 1 entered commercial operations in 1982 and Unit 2 in 1983.

The units are dispatched through its MISO interconnection.

In order to purchase energy through the MISO Interconnection, an end user must supply or purchase accredited capacity for an equivalent load.

As accredited capacity is primarily available in large quantities from dispatchable sources of energy, such as natural gas and coal-fired power plants, Hallador Power sells accredited capacity to utilities and other energy market participants within the MISO system through PPAs and other bilateral transactions.

In addition to accredited capacity, Hallador Power sells wholesale energy to utilities, generation and transmission cooperatives, and other energy market participants within the MISO system through PPAs and other bilateral transactions, and sells on a spot basis in the day-ahead and real-time MISO markets.

Sunrise, the Company’s wholly-owned mining subsidiary, mines coal from reserves found in the ILB.

Coal mined by Sunrise is used as a primary fuel source for generating electricity at various power plants in the Midwest and Southeast United States.

In addition, Sunrise has a developed infrastructure for the transport of coal, which is typically sold free on board from the shipping point, including rail networks and truck loading systems, facilitating the efficient movement of the resource from the mine to its customers.

Sunrise’s Oaktown Mining Complex is about twenty miles from Merom, which is located in Sullivan County, Indiana, enabling Merom and Sunrise to take advantage of low-cost fuel on a delivered basis.

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, that resulted in a significant reduction in headcount and the temporary idling of our mining operations at the Oaktown Mine No.

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.

The 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

Strategy and Management Focus

We view our business as two integrated operations, “Electric Operations” (our gigawatt Merom power generating station), and “Coal Operations” (our coal mining and coal sales group).

We strive to achieve margin expansion through organic revenue growth and profitability in our operations by negotiating and fulfilling contracts for accredited capacity, wholesale energy, and thermal coal to utilities and other energy market participants.

We continue to monitor opportunities to expand the volume of our electric generation capabilities through expansion of existing facilities utilizing MISO’s ERAS program, or via acquisition.

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 well-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.

In addition, we focus our organic capital investments on strategic maintenance projects to maintain our safe operational performance and improve the reliability of Merom.

As discussed further under “Liquidity and Capital Resources — Capitalization” below, we also seek to maintain our debt at levels that provide for attractive equity returns without assuming undue risk.

Competition and Other External Factors

We are experiencing competition in both our Electric and Coal Operations.

This competition drives lower market prices for our products and services.

Competitors for our Electric Operations include other power generators who bid into the MISO interconnection, while competitors for our Coal Operations include other mining entities that are able to service our existing and potential customers via truck or rail within the Midwest and Southeast United States.

RESULTS OF OPERATIONS

Our contracted forward sales for electricity, accredited capacity and coal are detailed below with estimated revenue from forward sales of $1.3 billion as of December 31, 2025.

Forward Sales Position

Contracted MWh (in millions)

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Contracted revenue (in millions)

Average daily contracted capacity MWh

Average contracted capacity price per MWd

Contracted capacity revenue (in millions)

Total Energy & Capacity Revenue

Accredited Capacity

Average daily contracted accredited capacity MW

Average contracted accredited capacity price per MWd

Contracted accredited capacity revenue (in millions)

Total Energy & Accredited Capacity Revenue

Contracted Power revenue (in millions)

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TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT

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

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.

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.

Year Ended December 31,

Power Capacity and Utilization

Nameplate capacity (MW) (i)

Accredited capacity for the period (MW) (ii)

Accredited capacity utilization (iii)

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.

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.

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.

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.

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)

Oaktown Fuels No.

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.

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.

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:

Recoverable Coal Reserves as of December 31, 2024 and 2023

Recoverable Coal Reserves (As-Received)

Oaktown Mining Complex

Oaktown Fuels No.

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.

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.

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)

Oaktown Mining Complex

Oaktown Fuels No.

Total Oaktown Mining Complex Production

Other Properties

The Company holds other recoverable coal reserves in the ILB, which are not deemed individually material.

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.

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.

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:

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:

Merom Power Plant

2026 - 2028 (total)

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

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.

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.

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

Oaktown – investment

Capex per the Condensed Consolidated Statements of Cash Flows

Results of Operations

Presentation of Segment Information

Actual revenue related to 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.

Discussion and Analysis of our Reportable Segments

Our business is organized based on the services and products we provide in two segments:

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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.

Corporate and Other and Eliminations primarily consist of unallocated corporate costs and activities, including our 50% interests in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.

Electric Operations

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Delivered energy

Capacity Revenue

Accredited capacity revenue

Electric sales

3 unchanged sentences

General and administrative

EBITDA Margin

Segment EBITDA

Other operating revenue

Amortization of Contract Asset

Depreciation, depletion and amortization

Asset Retirement Obligations Accretion

ARO accretion

Interest income

Interest expense

Income (Loss) before Income Taxes

1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

Income before Income Taxes

1) Other operating costs primarily include costs for lime dust.

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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Delivered energy

Capacity Revenue

Accredited capacity revenue

Electric sales

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General and administrative

EBITDA Margin

Segment EBITDA

Other operating revenue

Amortization of Contract Asset

Depreciation, depletion and amortization

Asset Retirement Obligations Accretion

ARO accretion

Interest income

Interest expense

Income (Loss) before Income Taxes

1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash.

1) Other operating costs primarily include costs for lime dust.

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.

Segment operating revenues from electric operations increased $49.2 million, or 18.8%, compared to 2024 attributable to an increase in sales of delivered energy while accredited capacity revenue was stable.

Our electric operations generated an additional 0.9 million MWh and purchased an additional 0.1 million MWh for resale resulting in incremental energy sales of 1.0 million MWh, an increase of 23.7% compared to 2024.

Seasonal weather in the first and third quarters of 2025 leading to incremental generation was offset by lower plant availability due to equipment issues at Merom in the fourth quarter impacting total MWh generated.

The price per MWh was relatively flat year-over-year at $48.82 for 2025 compared to $48.62 for 2024.

Accredited capacity revenue totaled $58.1 million for each of the years ended December 31, 2025 and 2024.

Other operating revenue increased $2.6 million, or 273.6%, compared to 2024 attributable to the exclusivity payments received during the contractual negotiations for the future accredited capacity and energy generated at Merom.

Fuel costs on a segment basis increased $20.8 million, or 18.6%, from 2024.

Fuel costs on a consolidated basis increased $15.3 million or 33.0%, from 2024.

This increase is due to electricity generation increasing by 0.9 million MWh, or 22.6%.

We used an incremental 0.3 million tons in production on both a segment and consolidated basis compared to the prior year.

We utilized approximately 0.1 million more tons produced at the Oaktown mining complex in 2025 compared to 2024.

The increase in demand for electric power was related to seasonal weather in the first and third quarters of 2025, which resulted in 0.6 million and 0.5 million incremental MWh respectively, compared to the same periods in 2024.

The weather contributed to higher demand for natural gas in Indiana causing an increase in the average spot prices of $0.84 per thousand cubic feet, or 24.1% compared to 2024.

Total fuel costs benefited from a slight decrease in the cost of coal consumed from $54.30 per ton in 2024 to $53.98 per ton in 2025.

We also made an adjustment to coal inventory during the third quarter of 2025 as part of the Company’s routine inventory reconciliation process resulting in an increase in fuel costs of $2.6 million.

Cost of purchased power increased $10.0 million, or 91.9%, from 2024.

W hen 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.

W hen there is an outage at one of the generating units at Merom or energy hours at the Merom Hub are priced below our production cost, we have the option to make net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power.

Approximately 47.0% of the 2025 net hourly purchases occurred in the fourth quarter as a result of the equipment issues.

Utilities increased $2.5 million, or 122.8%, in 2025 compared to 2024.

The change was attributable to increased production at Merom, as well as incremental billing for auxiliary power.

Labor increased $1.8 million, or 5.9%, in 2025 versus 2024.

The increase in labor costs is attributable to year-over-year wage increases and the use of outsourced labor.

Interest expense increased $7.2 million, or 385.2%.

The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024, and various points in 2025.

Income before income taxes increased $5.4 million, or 10.5%, compared to 2024 and is attributable to the items described in the discussion above.

Coal Operations

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General and administrative

EBITDA Margin

Segment EBITDA

Other operating revenue

1 unchanged sentence

Asset impairment

Asset Retirement Obligations Accretion

ARO accretion

Exploration costs

Gain (loss) on disposal or abandonment of assets, net

Interest income

Interest expense

Loss on Extinguishment of Debt

Settlement of litigation

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General and administrative

EBITDA Margin

Segment EBITDA

Other operating revenue

1 unchanged sentence

Asset impairment

Asset Retirement Obligations Accretion

ARO accretion

Exploration costs

Gain (loss) on disposal or abandonment of assets, net

Interest income

Interest expense

Loss on Extinguishment of Debt

Settlement of litigation

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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

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.

The Organizational Restructuring provided better operating leverage for our Coal Operations as decreased labor costs were a significant driver of our improved performance.

Segment operating revenue from coal operations increased $18.5 million, or 9.1%, versus 2024, despite only actively mining Oaktown Mine No.

1 during 2025.

The increase was due to increases in volume offset by a reduction in the average sales price for our coal.

We sold 4.3 million tons of coal in 2025, an increase of 0.4 million tons, or 11.6%, versus 2024.

Our average sales price, on a segment basis, decreased $1.14 per ton from $52.41 per ton to $51.27 per ton.

The incremental sales were made possible through increased demand for coal fired electricity due to seasonal weather specifically in the third quarter of 2025.

On a consolidated basis, third-party sales increased $11.2 million, or 8.2%, versus 2024 attributable to 0.3 million incremental tons sold, offset by a 3.5% reduction in our average third-party price per ton.

Other operating and maintenance costs increased $10.6 million, or 11.9%, which is attributable to the 0.4 million ton, or 11.6%, increase in total tons sold versus 2024.

Labor decreased $7.3 million, or 8.6%, from 2024, resulting in a reduction in labor cost per ton sold of $3.99 attributable to more efficient operations following the idling of Oaktown Mine No.

2 during 2024.

The change was 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 in 2024 that were included in coal operations labor costs.

These charges related to compensation, tax, professional, and insurance related expenses and are considered non-recurring charges paid during 2024.

Through the organizational restructuring and regular attrition during the year, our coal employee headcount decreased 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.

During the fourth quarter of 2024, we completed 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.

The core hole samples at our Oaktown Mine No.

2 mine were of a lower quality and density than that of Oaktown Mine No.

As such, we decided to temporarily seal Oaktown Mine No.

2, and to focus coal production at Oaktown Mine No.

1, 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 result of the 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 and recorded an impairment charge.

Depreciation, Depletion and Amortization decreased by $27.8 million, or 60.1%, in 2025 compared to 2024.

Following the impairment of our coal operations discussed above, the cost basis of our coal operations assets upon which depreciation, depletion and amortization is calculated was much lower resulting in significantly lower expense.

Interest expense decreased $3.2 million, or 29.3%, from $11.0 million in 2024 to $7.8 million in 2025.

The decrease is attributable to the net paydown of the Company’s bank facility from $44.0 million at December 31, 2024 to $30.0 million at December 31, 2025 coupled with decreased interest rates of 1.5% on our revolving credit facility and 0.41% on the term loan from 2024 to 2025.

Income (loss) before income taxes increased $274.6 million, or 100.2%, from a loss of $274.1 million in 2024 to income of $0.5 million in 2025.

The main drivers of this change in income from operations are described in the discussion above.

Quarterly coal sales and cost data follow on a segment basis (in thousands, except for per ton data and wash plant recovery percentage):

Tons produced

Wash plant recovery in %

Capex (Coal Operations)

Capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

Tons produced

Wash plant recovery in %

Capex (Coal Operations)

Capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

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, divided by tons sold for the respective period in this table.

Coal Operations costs are presented in the “Discussion and Analysis of our Reportable Segments” above.

During the fourth quarter of 2024, the Company made certain reclassification adjustments to other operating and maintenance costs and depreciation, depletion and amortization .

Presentation of Consolidated Information

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.

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Depreciation, depletion and amortization

Asset retirement obligations accretion

ARO accretion

Exploration costs

General and administrative

Asset impairment

(Gain) loss on disposal or abandonment of assets, net

Settlement of litigation

Gain on disposal or abandonment of assets, net

Total operating expenses

INCOME (LOSS) FROM OPERATIONS

Interest income

Interest expense

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Depreciation, depletion and amortization

Asset retirement obligations accretion

ARO accretion

Exploration costs

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(Gain) loss on disposal or abandonment of assets, net

Asset impairment

Settlement of litigation

Total operating expenses

INCOME (LOSS) FROM OPERATIONS

Interest income

Interest expense

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WEIGHTED AVERAGE SHARES OUTSTANDING:

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

Tons produced

Wash plant recovery in %

Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

Tons produced

Wash plant recovery in %

Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

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.

Our effective tax rate (“ETR”) is approximately 4% for the years ended December 31, 2025 and 2024.

For the year ended December 31, 2025, our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance.

The deduction for statutory percentage depletion does not necessarily change proportionately to changes in income (loss) before income taxes.

Restricted Stock Grants

Financial Statements - Note 8 - Stock Compensation Plans” in the Consolidated Financial Statements for a discussion of RSUs.

LIQUIDITY AND CAPITAL RESOURCES

Sources and Uses of Cash

We are a holding company that is dependent on the capital resources of our subsidiaries to satisfy our liquidity requirements at the corporate level.

Each of our significant operating subsidiaries typically generate cash from operating activities, but our ability to access the liquidity of these and other subsidiaries may be limited by tax and legal considerations, and other factors.

Cash and cash equivalents

Hallador had $15.4 million of cash and restricted cash as of December 31, 2025 versus $12.2 million at December 31, 2024.

Liquidity of Hallador

Our short-term sources of corporate liquidity include (i) cash and cash equivalents held by Hallador, (ii) cash provided by operations, (iii) interest income received on our cash and cash equivalents and, (iv) borrowing availability under our bank facility.

For the details of the borrowing availability under our bank facility, see “Item 8.

Financial Statements - Note 4 – Bank Debt” to our Consolidated Financial Statements.

The liquidity of Hallador generally is used to fund (i) capital expenditures, (ii) debt service requirements and (iii) general and administrative expenses, as well as to settle certain obligations that are not included on our December 31, 2025 consolidated balance sheet.

In this regard, we have commitments related to (a) leases of railcars that qualify for the short-term lease exception and (b) certain operating costs associated with our Electric Operations and our Coal Operations.

From time to time, we may also require liquidity in connection with (i) acquisitions and other investment opportunities, (ii) the satisfaction of contingent liabilities, (iii) capital distributions to Hallador equity owners, (iv) the repayment of third-party debt, or (v) income tax payments.

No assurance can be given that any external funding would be available to us on favorable terms, or at all.

Consolidated Statement of Cash Flows Summary.

The 2025 and 2024 consolidated statements of cash flows are summarized as follows:

Year ended December 31,

(in millions)

Net cash provided by operating activities

Net cash used in investing activities

Net cash used in financing activities

Increase in cash, cash equivalents, and restricted cash

Operating Activities.

The increase in net cash provided by our operating activities is primarily attributable to the combination of (i) an increase in cash provided by our Adjusted EBITDA and related working capital items, (ii) new prepaid forward sales contracts in 2025, and (iii) lower cash payments of interest.

Consolidated Adjusted EBITDA is a non-GAAP measure, which investors should view as a supplement to, and not a substitute for, GAAP measures of performance included in our consolidated statements of operations.

Investing Activities.

The change in net cash used by our investing activities is primarily attributable to the net effect of (i) an increase in our capital expenditures of $15.8 million (ii) a $1.1 million decrease in the proceeds from sales of equipment, and (iii) a $3.2 million decrease in proceeds from held-for-sale investments.

For the year ended December 31, 2025, our Capex was $69.2 million allocated as follows (in millions):

Capex per the Condensed Consolidated Statements of Cash Flows

We expect our 2026 capital expenditures to modestly increase as compared to our 2025 capital expenditures, excluding any impacts of the ERAS project.

The actual amount of our 2026 capital expenditures may vary from our expectations for a variety of reasons, including (i) changes in (a) the competitive or regulatory environment, (b) business plans, or (c) our expected future operating results and (ii) the availability of sufficient capital.

Accordingly, no assurance can be given that our actual capital expenditures will not vary materially from our expectations.

Financing Activities.

The decrease in net cash used in our financing activities is primarily attributable to the net effect of (i) a decrease in cash used of $33.5 million due to lower net repayments of debt, (ii) a reduction in cash provided from the issuance of equity securities of $21.0 million, and (iii) a decrease in cash provided of $5.1 million in proceeds from sales and leaseback arrangements.

Capitalization

We seek to maintain our debt at levels that provide for equity returns without assuming undue risk.

Our ability to service or refinance our debt and to maintain compliance with the leverage covenants in our credit agreement is dependent primarily on our ability to maintain or increase the Adjusted EBITDA of our consolidated businesses, maintain adequate liquidity and coverage of fixed charges, and to achieve adequate returns on our capital expenditures and acquisitions.

In addition, our ability to obtain additional debt financing is limited by the incurrence-based leverage covenants contained in our debt instruments.

For example, if the Adjusted EBITDA of our business was to decline, our ability to obtain additional debt could be limited.

As of December 31, 2025, our bank debt was $30.0 million, which was repaid subsequent to year-end as further described below.

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 Bank, National Association (in its capacity as administrative agent, "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 provided for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company repaid 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, would take the place of the $6.5 million quarterly Term Loan payments.

On June 27, 2025, the Company executed the Third Amendment (“Third Amendment”) to our Credit Agreement, which was accounted for as a debt modification.

The primary purpose of the Third Amendment was to provide additional

operating flexibility for the remainder of 2025 by redefining covenants, deferring certain covenants until the third quarter of 2025 and moving our October 2025 payment to January 2026.

The Third Amendment provided for additional flexibility for the Company to enter into prepaid forward power sale contracts, provided that the Company maintained one hundred percent of the outstanding aggregate principal balance of the Term Loan as a compensating balance.

As part of the Third Amendment, the required October 2025 principal payment of $6.0 million and the January 2026 principal payment of $6.5 million, pursuant to the Term Loan, were both due in January 2026.

The balance of the Term Loan was paid off in November 2025.

On March 5, 2026, Hallador entered into a credit agreement with Texas Capital Bank and Old National Bank, among others, that replaces the Credit Agreement with PNC Bank and includes a $75.0 million revolving credit facility (the "New Revolving Credit Facility") and a $45.0 million delayed draw term loan (the "Delayed Draw Term Loan", and together with the New Revolving Credit Facility, the "New Credit Facility").

The New Credit Facility bears interest with margins ranging from 2.25% to 3.75% above SOFR or the applicable base rate, subject to a SOFR floor of 1.00%.

The applicable margin is determined based upon the Company's leverage ratio and the type of loan drawn.

The New Credit Facility includes a commitment fee of 0.50% on any unused portions of the New Revolving Credit Facility.

If the Delayed Draw Term Loan occurs, which is subject to meeting certain conditions, the principal balance of the Delayed Draw Term Loan shall be due and payable in equal quarterly installments of 2.5% of the original principal amount of such Delayed Draw Term Loan with a final payment of the remaining balance upon maturity.

The New Credit Facility matures on March 5, 2029, and is collateralized by substantially all our assets.

When drawn, the proceeds from the New Credit Facility may be used for ongoing working capital and general corporate purposes.

Liquidity at December 31, 2025 excludes the availability under the New Credit Facility.

See “ Item 8.

Financial Statements - Note 4 – Bank Debt ” to our Consolidated Financial Statements for additional discussion about our bank debt and related liquidity.

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 $17.8 million, including $6.2 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 $30.9 million to cover ARO.

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.

In connection with the preparation of our consolidated financial statements, we make estimates and assumptions that affect the reported amounts of assets and liabilities, revenue and expenses and related disclosure of contingent assets and liabilities.

Critical accounting policies are defined as those policies that are reflective of significant judgments, estimates and uncertainties, which would potentially result in materially different results under different assumptions and conditions.

We believe the following accounting policies are critical in the preparation of our consolidated financial statements because of the judgment necessary to account for these matters and the significant estimates involved, which are susceptible to change:

● estimates of coal reserves;

● asset retirement obligations;

● income tax accounting;

● impairment of long-lived assets.

Estimates of Coal Reserves

The reserve estimates are used in the depreciation, depletion and amortization calculations and our internal cash flow projections.

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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.

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.

Asset Retirement Obligations

SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans.

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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

reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.

Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, reclamation of refuse areas, slurry ponds and our landfill.

Accretion expense is recognized on the obligation through the expected settlement date.

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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.

Income Tax Accounting

We are required to estimate the amount of income taxes for the current year and the deferred tax assets and liabilities for the future tax consequences of differences between the financial statement carrying amounts and income tax basis of assets and liabilities and the expected benefits of utilizing net operating losses and tax credit carryforwards, using enacted tax rates for the year in which those temporary differences are expected to be recovered or settled.

This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact of such items.

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.

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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 .

Impairment of Long-lived Assets

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.

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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.

These determinations could impact the analysis 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.

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis