What changed in this filing

/stocks — the workspaceLOADING

Item 2. Management’s Discussion and Analysis

2026-05-06 compared with 2025-11-10 · 242 added, 279 removed, 73 unchanged (88% of the section changed)

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2024 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH.

We are pleased with our favorable results in the third quarter, during which time we generated $146.8 million of revenue with $23.9 million of net income, representing substantial improvement over the $105.2 million of revenue with $1.6 million of net income generated in the prior year period.

For the nine months ended September 30, 2025, we generated $367.5 million of revenue with $42.1 million of net income both materially above prior year performance.

Traditional summer weather patterns coupled with higher energy demand and higher natural gas prices provided for a supportive energy-pricing environment during the quarter that led to higher revenue at our Hallador Power subsidiary.

Following the completion of Unit 2’s annual maintenance outage in early July 2025, both units operated very well throughout the quarter.

We also saw positive results in our Coal Operations resulting from solid coal production, increased shipments and consistent operating costs.

The favorable power markets led to increased dispatch levels at both Merom and customer plants, which provided a boost to coal shipments and helped to decrease coal inventories at both the power plant and the mine.

During the third quarter 2025 , the Company entered into a $20.0 million prepaid forward power sales contract with scheduled deliveries throughout the first half of 2027.

As we have previously noted, these firm forward sales allow us to improve liquidity from lower future price environments and also provides an advantage, as we saw in this instance, when pricing is stronger.

These prepaid sales help us to lock in prices in the near term as we continue to focus on securing a long-term power purchase agreement in support of utility, data center and/or other large scale industrial development.

The prepaid funds will be used to support company operations and capital expenditures.

We continue to see significant and accelerating interest in our capacity and energy offerings.

As the third quarter progressed, we saw increased activity from both data center developers and load serving entities seeking the scarce inventory of large blocks of capacity and energy that we have available in the coming decade.

We are in advanced discussions on both fronts and anticipate making positive progress towards a long-term agreement with a data center developer or load serving entity by early 2026.

Each of the interested parties brings a unique perspective to the negotiations and each presents differentiated value creation opportunities and challenges to effectively monetize our capacity and energy offerings.

We continue to believe that the evolving energy markets, specifically related to data center growth and favorable load serving entity demand, as well as the newly supportive regulatory environment, are providing us with opportunities that were not available when we began the request for proposal process.

We also recognize that these opportunities have an undefined lifespan and we continue to work diligently to secure an agreement that will benefit the Company and our shareholders, both now and in the future.

While we still believe that an agreement with a load serving entity is intrinsically more straightforward to negotiate, can be implemented sooner and could result in greater sales volumes of energy and accredited capacity, we are beginning to see improving timelines on the developer side, especially where the developers had the foresight to speculatively acquire required infrastructure, such as step-down transformers, switch gear and other site-specific level electrical equipment.

We anticipate favorable pricing in these potential opportunities, but, as we have highlighted before, data center arrangements are inherently more complex and involve multiple parties, which by its nature adds time and alignment challenges to the negotiation process.

Notwithstanding those challenges, returning to non-exclusive negotiations reinforced our belief that we will forge a strategic partnership and create significant value for years to come.

Throughout the past several years, we have expressed our strong belief that the prevailing industry trend of retiring dispatchable generators in favor of non-dispatchable resources, such as wind and solar, will create and has created an unbalanced supply and demand equation, resulting in reduced availability and increased price of accredited capacity.

It is our position that the enhanced reliability of dispatchable generation, like Merom, versus non-dispatchable generators will increase the value of the attributes of Hallador Power in the overall energy markets.

With this in mind, we continue to evaluate the potential to enhance value through strategic growth initiatives such as the acquisition of retiring or retired generation assets and infrastructure.

We are regularly evaluating potential acquisition opportunities to diversify and

increase our dispatchable generation as well as other strategic opportunities, which we believe would inherently diversify our generation portfolio, and provide an avenue to realize future growth opportunities.

We believe that this approach has the potential to enhance our financial flexibility and strengthen our position in the evolving energy market.

We remain optimistic about the potential to add to our strategic generation 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 capture value by providing accredited capacity and reliable energy.

In connection with this belief, on November 3, 2025, Hallador Power submitted an application to MISO’s Expedited Resource Addition Study (ERAS) program to add an additional 525 MW of gas generation at the Merom site.

Given the strong market signals that we are currently seeing for our product offerings and the robust interest in the types of long-term arrangements that we are currently evaluating, we believe that it is an appropriate time to explore increasing generation at Merom.

While the application is only a first step in our growth process and does not guarantee that we will be able to add the full load which we applied for, or any additional generation as part of ERAS, we are excited to participate in the opportunity and for what it could mean to the future of Hallador.

We are currently targeting the generation to come online late in 2028.

The process is capital intensive and includes operational, financial, regulatory and legal risks that could impact the project’s viability and/or timeline.

Additionally, we see the potential of enhancing Merom’s reliability, resiliency and flexibility by incorporating natural gas and creating a dual fuel configuration should operational and financial conditions support it.

While we remain in the evaluation process, by adding the capability to co-fire with gas or coal, we believe that it could provide Hallador Power and its customers the ability to take advantage of economic fluctuations in fuel cost and provide potential flexibility as we manage other operating expenses.

We believe that the ability to co-fire with natural gas and coal will also provide increased resiliency in times where gas availability is limited and allow us to retain the economic advantages of operating our Sunrise Coal subsidiary and leveraging our own fuel supply to ensure competitively priced offerings from third party fuel providers.

This evaluation is complex on a variety of levels, specifically customer preference and an evolving regulatory environment, each of which could materially impact the timing and economic benefits of undertaking such a change.

In 2024, we delivered 2.9 million MWh of energy during the first nine months at an average sales price of $50.97 per MWh.

In 2025, we delivered 4.0 million MWh of energy during the first nine months at an average sales price of $48.88.

As illustrated in the forward sales position table, below, following 2026, we are optimistic that we will be able to sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a strong forward energy pricing curve.

Shifting to our Coal Operations, during the quarter, we saw improvements in operational expenses and increased shipments.

The improved dispatch levels at Merom and our customers’ plants helped to reduce our previously elevated inventories, while still allowing us adequate fuel inventory to position us well to meet industry needs if power plants, including Merom, dispatch at higher levels over the course of the upcoming Winter season.

With renewed support of coal mining and coal fired generation on both the federal and state level, we believe that we are well-positioned to take advantage of opportunities for strategic growth and/or organic expansion.

We believe that current market dynamics remain stronger than they were in the past year, and we are actively assessing the timing and feasibility of expanding coal production in 2026.

As we have previously said, our average contracted sales price in 2026 across all coal sales contracts is approximately $4.00 per ton higher than the average contracted sales price in 2025.

We currently expect to produce approximately 3.8 million tons of coal in 2025.

In the first three quarters of 2025, we produced 3.1 million tons of coal at our Oaktown Mining Complex.

We also use supplemental coal from third party suppliers at Merom, typically purchased at favorable prices to help diversify self-production supply risk and to provide us with additional flexibility in our ability to rapidly respond to customer demand if spot market pricing justifies doing so.

This optionality to obtain low-cost fuel either internally or from third-parties while capturing upward swings in the commodity markets for coal should allow us to further maximize margins while optimizing fuel costs at Merom.

The continued transformation of Hallador from a commodity focused producer of coal to a vertically integrated IPP remains our primary focus.

This allows us to leverage the ongoing impacts of the energy transition to capture the

expanding margins of the energy markets and capitalize on the rising demand for reliable electricity.

As described above, we continue to see very strong interest from data center developers and load serving entities with respect to our energy and accredited capacity offerings.

This interest and the number of inquiries accelerated throughout the quarter and we are encouraged by the variety of interested parties and the varied deal structures that we are seeing with respect to our offerings.

We continue to believe that our business is well positioned to take advantage of opportunities for growth and cash flow generation as they arise.

Like our competitors, Hallador’s business is affected by various macroeconomic factors, including tariffs and inflationary trends.

has implemented, or is considering implementing, higher tariffs on imports into the U.S.

While such tariffs could potentially result in reduced economic activity, increased costs in operating our business including potential supply chain disruptions, and changes in purchasing behaviors for thermal coal or other potentially adverse economic outcomes, tariffs (or retaliatory trade measures imposed by other countries on U.S.

goods) have not yet had a significant impact on our business or results of operations.

Our goal is for Hallador Power to generate up to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below), if the markets and energy pricing support that level of generation.

During the first nine months of the year, Hallador Power generated approximately 3.7 million MWh, or roughly 82.0% of our year-to-date target and economically purchased 0.3 million MWh.

Three Months Ended September 30,

Nine Months Ended September 30,

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 775 MW and 829 MW per day for 2025 and 2024, 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.

When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million.

For 2025, we have contracted approximately $58.1 million or 89.4% of our target.

We believe our forward Capacity sales goals are attainable as illustrated in our “Forward Sales Position” table below.

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

This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements.

These metrics are significant factors in assessing our operating results and profitability.

The following is an overview our Electric Operations and Coal Operations results for Q3 2025 compared to Q2 2025.

Q3 2025 Net Income of $23.9 million.

Electric Operations:

In Q3 2025, Total Electric Sales were $93.2 million, or $59.09 per MWh sold, an increase of $33.2 million or 55.3% from Q2 2025.

In Q3 2025, Total Electric Operations expenses on a segment basis were $75.2 million or $47.64 per MWh sold an increase of $23.7 million or 46.0% from Q2 2025.

Q3 2025 Electric Operations net income was $18.3 million an increase of $6.7 million or 57.8% from Q2 2025.

Key drivers in Q3 2025 Electric Operations results were:

(1) During the third quarter of 2025, we sold 1.6 million MWh representing a 100.0% increase in total MWh sold from the second quarter of 2025.

This increase was expected as Q2 2025 typically has lower demand for power and we had a planned maintenance outage on one of our units at Merom for approximately two months during the second quarter.

On a per MWh basis, Q3 Electrics Sales were $59.09 per MWh sold compared to $72.44 per MWh sold in Q2 2025.

The variance on a per MWh basis was primarily due to the allocation of capacity revenue over increased energy volumes.

(2) In Q3 2025, significant operating costs including fuel, other operating and maintenance and cost of purchased power were $56.2 million, or $35.61 per MWh compared to $34.2 million, or $41.31 per MWh in Q2 2025.

The increase in costs reflect the higher plant output and planned maintenance as also reflected in the decreased cost per MWh from Q2.

(3) Q3 2025 Electric Operations income before income taxes was $18.3 million or $11.57 per MWh, an increase of $6.7 million and a decrease of $2.42 per MWh from Q2 2025.

Coal Operations:

In Q3 2025, Total Coal Sales on a segment basis were $68.8 million, or $50.79 per ton sold, an increase of $23.3 million or 51.2% from Q2 2025.

In Q3 2025, Total Coal Operations Expenses on a segment basis were $66.7 million, or $49.20 per ton sold, an increase of $21.1 million or 46.3% from Q2 2025.

Q3 2025 Coal Operations Net Income on a segment basis was $6.1 million an increase of 335.7% from Q2 2025.

Key drivers in Q3 2025 Coal Operations results were:

(1) In Q3 2025, tons sold were 1.4 million tons on a segment basis at an average price per ton of $50.79, with approximately 0.3 million tons of that being shipped to Merom for $17.6 million compared to 0.9 million tons sold in Q2 2025 at an average price of $51.16, with approximately 0.1 million tons of that being shipped to Merom for $7.4 million.

This increase was expected as Q2 is the shoulder season and typically has lower demand for coal at both Merom and third-party customers.

(2) In Q3 2025, Other operating and maintenance costs were $35.0 million, or $25.86 per ton, compared to $18.2 million, or $20.50 per ton, on a segment basis, in Q2 2025.

This increase is mainly attributable to an increase of sales related royalties of $3.0 million and an increase of $14.9 million in coal cost of sales directly related to the increase in sales.

(3) Q3 2025 Coal Operations income before income taxes was $6.1 million or $4.53 per ton on a segment basis.

This is an increase of $4.7 million or $2.95 per ton from Q2 2025.

The following discussion and analysis, which should be read in conjunction with our consolidated financial statements and the discussion and analysis included in our 2025 10-K, is intended to assist in providing an understanding of changes in our results of operations and financial condition and is organized as follows:

• 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.

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.

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

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

Unless otherwise indicated, operational data is presented as of March 31, 2026.

FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to us.

When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements.

Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements.

These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements.

Among the factors that could cause actual results to differ from those in the forward-looking statements are:

• changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position;

• fluctuations in weather, natural gas and electricity commodity costs, inflation and economic conditions that impact demand of our customers and our operating results;

• the outcome or escalation of current international hostilities;

• changes in competition, or changes in electricity, natural gas or coal prices, demand, and availability which could affect our operating results and cash flows;

• risks associated with the expansion of our operations and properties;

• risks relating to Midcontinent Independent System Operator’s (“MISO”) Expedited Resource Addition Study (“ERAS”) program review and approval process;

• risks relating to our ability to secure agreements in support of the development and construction of planned projects, including the expansion of the Merom Generating Station through the ERAS program;

• legislation, regulations, administrative actions (e.g., executive orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases (“GHG”), mining, miner health and safety, and health care, as well as those relating to data privacy protection;

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

• dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts;

• changes in the geopolitical environment in industries in which our customers operate;

• changes in attitude toward environmental, social, and governance (“ESG”) matters among regulators, investors and parties with which we do business;

• the effect of changes in taxes or tariffs and other trade measures, including uncertainty regarding tariffs on imports into the United States, which could impact the Company’s procurement and sourcing strategies;

• risks relating to inflation and increasing interest rates;

• liquidity constraints, including due to restrictions contained in our debt agreements or other arrangements and those resulting from any future unavailability of financing;

• customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, including failures to make payments when due;

• customer delays or failure to take coal or electricity under contracts;

• adjustments made in price, volume or terms to existing coal or electricity contracts;

• our productivity levels and margins earned on our coal or electricity sales;

• supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures;

• changes in the availability of skilled labor;

• our ability to maintain satisfactory relations with our employees;

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

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

• operational interruptions due to geologic, permitting, labor, weather-related or other factors, including challenges in operating an aging coal-fired power plant;

• risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control;

• results of litigation, including claims not yet asserted;

• difficulty maintaining our surety bonds for mine reclamation;

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

• risks resulting from natural disasters;

• difficulty in making accurate assumptions and projections regarding landfill and mine reclamation;

• uncertainties in estimating and replacing our coal reserves;

• the impact of current and potential changes to federal or state tax rules and regulations, including the effects of the One Big Beautiful Bill Act (“OBBBA”) or a loss or reduction of benefits from certain tax deductions and credits;

• difficulty obtaining commercial property insurance;

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

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

• other factors, including those discussed in “Item 1A.

Risk Factors” in our 2025 Form 10-K.

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement.

When considering forward-looking statements, you should also keep in mind the risk factors described in “Item 1A.

Risk Factors” in our 2025 Form 10-K.

The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement.

We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law.

You should consider the information above when reading any forward-looking statements contained in this 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.

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 include Hallador Power which provides accredited capacity and energy to utilities and other energy market participants through its MISO interconnection, and Sunrise which 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 (“Sunrise Energy”) and Oaktown Gas, LLC (“Oaktown Gas”), 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 system, 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 Power Purchase Agreements (“PPA”) 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 Illinois Basin (“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.

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 diversification, durability, scale, and geographic expansion opportunities to our Electric Operations.

While these opportunities 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 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 “Material Changes in Financial Condition — 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 system, 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.

MATERIAL CHANGES IN RESULTS OF OPERATIONS

Our contracted forward sales for accredited capacity, energy, and coal are detailed below with estimated revenue from forward sales of $1.2 billion as of March 31, 2026.

Forward Sales Position (unaudited)*

Accredited Capacity

Average daily contracted accredited capacity MW

Average contracted accredited capacity price per MWd

Contracted accredited capacity revenue (in millions)

Contracted MWh (in millions)

1 unchanged sentence

Contracted revenue (in millions)

Average daily contracted capacity MW

Average contracted capacity price per MWd

Contracted capacity revenue (in millions)

Total Energy & Capacity Revenue

Contracted Power revenue (in millions)

Total Accredited Capacity & Energy Revenue (in millions)

Priced tons - 3rd party (in millions)

6 unchanged sentences

TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT

* 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.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity and Capital Resources

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $73.0 million and $27.0 million for the nine months ended September 30, 2025 and 2024, respectively.

On a net basis, bank debt did not change during the nine months ended September 30, 2025.

As of September 30, 2025, our bank debt was $44.0 million.

We expect cash generated from operations to primarily fund our capital expenditures and our debt service.

As of September 30, 2025, we also had an additional borrowing capacity of $33.8 million.

Total liquidity as of September 30, 2025 was $46.4 million.

Material 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 $17.7 million, including $6.1 million at Merom, presented as asset retirement obligations (“ARO”) and “accounts payable and accrued liabilities” in our accompanying condensed 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.

CAPITAL EXPENDITURES (“Capex”)

For the nine months ended September 30, 2025, capex was $44.3 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

Our operations are divided into two primary reportable segments:

Electric Operations and Coal Operations.

The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the notes to the condensed consolidated financial statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest 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.

Forward sales figures in the 2026 column are for the period from April 1, 2026 through December 31, 2026.

Discussion and Analysis of our Reportable Segments

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 our 50% interests in Sunrise Energy and Oaktown Gas, which we account for using the equity method.

Electric Operations

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

Three Months Ended March 31,

(in thousands)

Delivered Energy

Capacity Revenue

Accredited Capacity Revenue

Electric Sales

3 unchanged sentences

General and Administrative

EBITDA Margin

Segment EBITDA

Other Operating Revenue

1 unchanged sentence

Asset Retirement Obligations Accretion

Interest Income

Interest Expense

Income before Income Taxes

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

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

Three Months Ended September 30,

Nine Months Ended September 30,

(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 included in fuel and other operating costs.

Three Months Ended March 31,

MWh Generated (in thousands)

2 unchanged sentences

Delivered Energy

Capacity Revenue

Accredited Capacity Revenue

Electric Sales

3 unchanged sentences

General and Administrative

EBITDA Margin

Segment EBITDA

Other Operating Revenue

1 unchanged sentence

Asset Retirement Obligations Accretion

Interest Income

Interest Expense

Income before Income Taxes

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

(2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1).

In Q3 2025, Total Electric Sales were $93.2 million or $59.09 per MWh sold compared to $72.1 million or $60.96 per MWh sold for Q3 2024, an increase of $21.1 million or 29.3%.

In Q3 2025, Total Electric Operations expenses on a segment basis were $75.2 million or $47.64 per MWh compared to $53.1 million or $44.91 per MWh in Q3 2024, an increase of $22.1 million or 41.6%.

Q3 2025 Electric Operations income before income taxes was $18.3 million or $11.57 per MWh compared to $19.2 million or $16.21 per MWh in Q3 2024, a decrease of $0.9 million or $4.64 per MWh or 28.6%.

Key drivers in Electric Operations Q3 results were:

(1) Delivered Energy revenue increased $21.5 million, or 38.3%, and $1.74 per MWh from the same period in the prior year.

During 2025, (i) we sold 0.4 million more MWh of Delivered Energy, or 33.4%, (ii) we began delivery on two additional PPA contracts resulting in a $14.4 million increase, or 41.7%, (iii) MISO pricing during the quarter was in excess of 2024 prices, with July 2025 average price of $55.37 per MWh compared to $33.54 per MWh in July of 2024 and (iv) we sold 0.3 million MWh during the quarter to MISO at these elevated prices compared to 0.1 million in Q3 2024.

(2) Capacity Revenues were $15.5 million or $9.80 per MWh sold for Q3 2025 and $15.9 million or $13.41 per MWh sold for Q3 2024.

Capacity revenues are not impacted by the MWh generated at the plant therefore the price per MWh sold decreased due to the allocation of revenue over increased energy volumes.

(3) Fuel costs increased $14.6 million, or 48.3%, compared to the third quarter of 2024.

On a per MWh basis, fuel costs increased $2.85, or 11.2%.

This change was due to increased energy production as noted above resulting in 0.2 million tons, or 37.5%, more tons of coal used.

The average purchase price per ton of coal used in the plant on a segment basis, was $54.22 in the third quarter of 2025 up from $53.33 per ton in the third quarter of 2024.

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.

(4) Other operating and maintenance costs increased $3.8 million, or 68.5%, and increased $1.24, or 26.4%, on a MWh basis.

These increases were due to $3.4 million in additional planned maintenance costs compared to 2024.

(5) Electric interest expense increased $2.4 million, or 1328.2%, compared to the third quarter of 2024.

On a per MWh basis, interest expense increased $1.49, or 993.3%.

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

(6) Income before income taxes decreased $0.9 million, or 4.8%, compared to the third quarter of 2024.

The main drivers of this change in income before income taxes are described in the discussion above.

Total Electric Sales for YTD 2025 were $239.2 million or $60.24 per MWh compared to $193.0 million or $66.25 per MWh YTD 2024, an increase of $46.2 million or 23.9%.

Total Electric Operations expenses on a segment basis YTD 2025 were $193.5 million or $48.73 per MWh compared to $152.6 million or $52.40 per MWh YTD 2024 an increase of $40.9 million or 26.8%

Electric Operations income before income taxes for YTD 2025 was $49.1 million or $12.37 per MWh compared to $40.9 million or $14.03 per MWh for YTD 2024 an increase of $8.2 million or 20.0%.

Key drivers in Electric Operations YTD results were:

(1) Delivered energy increased $45.6 million, or 30.7%, compared to the first nine months of 2024.

During 2025, (i) we began delivery on two additional PPA contracts resulting in a $44.3 million, or 63.4%, increase in revenue compared to 2024, (ii) we increased Delivered Energy MWh sold by 1.1 million, or 36.3%, and (iii) the average MISO price for 2025 of $41.83 per MWh is above the average 2024 price of $30.91, or an increase of 35.3%.

(2) Fuel increased $24.6 million, or 31.0%, compared to the first nine months of 2024.

The increase in fuel costs were directly related to the increase in MWh generated, requiring the increased use of fuel by 0.4 million tons of coal, or 30.1%.

On a per MWh basis, fuel decreased $1.07, or 3.9%, at an average cost of $53.88 per ton for 2025 compared to an average cost of $54.83 per ton for 2024.

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

(3) The cost of purchased power increased $3.4 million, or 44.1%, compared to year-to-date 2024.

When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market, which we record as cost of purchased power.

(4) Utilities increased $2.5 million, or 171.0%, compared to the first nine months of 2024.

This change was due to increased production at the Merom Plant described above as well as a change in meters for auxiliary power.

(5) Other operating revenue increased $2.9 million, or 558.9%, compared to the first nine months of 2024.

On a per MWh basis, other operating revenues increased $0.68, or 377.8%.

These changes were due to revenue received related to contractual negotiations on the former exclusivity agreement.

(6) Electric interest expense increased $5.7 million, or 1105.4%, compared to the first nine months of 2024.

On a per MWh basis, interest expense increased $1.38, or 766.7%.

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

(7) Income before income taxes increased $8.2 million, or 20.0%, compared to the first nine months of 2024.

The main drivers of this change in income before income taxes are described in the discussion above.

(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 included in fuel and other operating costs.

Segment operating revenues from electric operations decreased $20.8 million, or 24.3%, compared to the first quarter of 2025, attributable to a $22.6 million decrease in sales of delivered energy partially offset by a $1.7 million increase in accredited capacity revenue.

Our Electric Operations generated 0.5 million fewer MWh, but purchased an additional 0.1 million MWh for resale resulting in a net decrease of energy sales of 0.4 million MWh, a decrease of 27.9% compared to the first quarter of 2025.

Lower plant availability in the first quarter of 2026 due to equipment issues at Merom had a significant impact on the total MWh generated.

The impacted generating unit is scheduled to undergo a major maintenance outage beginning in May 2026, which we expect will improve performance upon completion.

The price per MWh for delivered energy decreased 4.8% year-over-year from $46.42 for the three-month period ended March 31, 2025 to $44.21 in 2026.

Accredited capacity revenue increased 12.5% to $15.5 million for the three-month period ended March 31, 2026 from $13.8 million in the comparable prior year period.

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.

Other operating and maintenance costs increased $4.3 million, or 95.6%, from the first quarter of 2025.

The increase was driven by increased maintenance activities attributable to the aforementioned equipment issues at Merom.

In addition to the increased maintenance activities in the first quarter of 2026, t he impacted generating unit will receive a major maintenance outage beginning in May.

Cost of purchased power increased $8.0 million, or 117.3%, from the first quarter of 2025.

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 economic net hourly purchases of power in the MISO market to satisfy our obligations, which we record as cost of purchased power.

In 2026, we purchased an incremental 51,000 MWh compared to 2025, an increase of 38.6% that was further impacted by the energy pricing dynamics at the time of the purchases.

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.

Labor expenses were largely flat for the first quarter of 2026 versus the comparable period in 2025 as headcount was relatively stable year-over-year.

Interest expense increased $1.2 million, or 70.2%, from the first quarter of 2025.

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

Income before income taxes decreased $24.3 million from $19.2 million of income before taxes in the first quarter of 2025 to a loss before taxes of $5.0 million in the first quarter of 2026, which is attributable to the items described in the discussion above.

Coal Operations

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

Three Months Ended March 31,

(in thousands)

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General and Administrative

EBITDA Margin

Segment EBITDA

Other Operating Revenue

Depreciation, Depletion and Amortization

Asset Retirement Obligations Accretion

ARO Accretion

Exploration Costs

Gain on Disposal or Abandonment of Assets, Net

Interest Income

Interest Expense

Income (Loss) before Income Taxes

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

Three Months Ended March 31,

Tons Sold (in thousands)

Other Operating and Maintenance Costs

General and Administrative

EBITDA Margin

Segment EBITDA

Other Operating Revenue

Depreciation, Depletion and Amortization

Asset Retirement Obligations Accretion

ARO Accretion

Exploration Costs

Gain on Disposal or Abandonment of Assets, Net

Interest income

Interest expense

Income (Loss) before Income Taxes

In Q3 2025, Total Coal Sales on a segment basis were $68.8 million, or $50.79 per ton sold compared to $48.3 million or $52.18 per ton from Q3 2024, an increase of $20.5 million or 42.4%.

In Q3 2025, Total Coal Operations Expenses on a segment basis were $66.7 million, or $49.20 per ton sold, compared to $64.0 million or $69.14 per ton from Q3 2024, an increase of $2.7 million or 4.2%.

Q3 2025 Coal Operations Net Income on a segment basis was $6.1 million compared to a net loss of $14.7 million in Q3 2024, an increase of $20.8 million or 141.7%.

Key drivers in Q3 2025 Coal Operations results were:

(1) Coal sales increased $20.5 million, or 42.4%, compared to the third quarter of 2024.

On a per ton basis, coal sales decreased $1.39, or 2.7%.

These changes were primarily due to increased third-party contractual coal sales of 0.4 million tons during the period, partially offset by a decrease in coal prices per ton of $1.39.

(2) Other operating and maintenance costs increased $8.0 million, or 29.7%, compared to the third quarter of 2024.

On a per ton basis other operating and maintenance costs decreased $3.33, or 11.4%.

These changes were the result of a $2.6 million increase in sales related royalties, an increase of $8.4 million related to coal cost of sales, $1.0 million decrease in group health insurance costs and a $1.0 million decrease in maintenance costs.

(3) Depreciation, depletion and amortization decreased $5.0 million, or 55.7%, compared to the third quarter of 2024.

On a per ton basis, depreciation, depletion and amortization decreased $6.78, or 69.7%.

This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million.

(4) Gain on disposal or abandonment of assets, net, increased $2.0 million, or 704.8%, and $1.41, or 454.8%, on a per ton basis compared to the third quarter of 2024.

This change was due to the sale of land during the third quarter of 2025.

(5) Income before income taxes increased $20.8 million, or 141.7%, compared to the third quarter of 2024.

The main drivers of this change in income before income taxes are described in the discussion above.

Total Coal Sales on a segment basis YTD 2025 were $169.1 million or $51.00 per ton compared to $160.1 million or $53.55 per ton YTD 2024, an increase of $9.1 million or 5.7%.

Total Coal Operations expenses YTD 2025 were $173.4 million or $52.31 per ton $206.5 million or $69.08 per ton for YTD 2024, a decrease of $33.1 million or 16.0%.

Income before income taxes YTD 2025 was $2.4 million or $.74 per ton compared to a loss of $43.9 million or $14.68 per ton YTD 2024, an increase of $46.3 million or 105.6%.

Key drivers in YTD 2025 Coal Operations results were:

(1) Labor decreased $8.6 million, or 12.9%, compared to the first nine months of 2024.

On a per ton basis, labor decreased $4.77, or 21.5%.

This change was the result of the organizational restructuring that occurred in February 2024 which reduced the Coal Operations headcount to 626 as of September 30, 2025 from 924 prior to the restructuring.

(2) Other operating revenue increased $2.3 million, or 115.5%, compared to the first nine months of 2024.

On a per ton basis, other operating revenue increased $0.64, or 94.1%.

This change was the result of increased utilization of our rail facility by a customer resulting in an increase in transloading fee revenue.

(3) Depreciation, depletion and amortization costs decreased $14.5 million, or 50.7%, compared to the first nine months of 2024.

On a per ton basis, depreciation, depletion and amortization decreased $5.32, or 55.5%.

This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million.

(4) Interest expense decreased $2.6 million, or 29.7%, compared to the first nine months of 2024.

Interest expense on a per ton basis decreased $1.09, or 36.6%.

Our decreased interest expense primarily relates to reductions of convertible debt of $11.0 million and related party debt of $5.0 million.

(5) Income before income taxes increased $46.3 million, or 105.6%, compared to the first nine months of 2024.

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.

Loss before income taxes narrowed by $2.1 million, or 41.4% compared to the first quarter of 2025.

The main drivers of this change in loss before income taxes are described in the discussion above.

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Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton sold (Coal Operations)

Capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

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Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton (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.

Coal Operations costs are presented in the “Presentation of Segment Information” above.

Presentation of Consolidated Information

(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.

EARNINGS (LOSS) PER SHARE

Our effective tax rate (ETR) is estimated at ~0% and ~24% for the nine months ended September 30, 2025 and 2024, respectively.

For the nine months ended September 30, 2025, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate.

Our effective tax rate (“ETR”) is estimated at ~5.2% and ~0% for the three months ended March 31, 2026 and 2025, respectively.

For the three months ended March 31, 2026, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate.

Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance.

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RESTRICTED STOCK GRANTS

Financial Statements - Note 9 - Stock Compensation Plans” for a discussion of RSUs.

Financial Statements - Note 8 - Stock Compensation Plans” for a discussion of restricted stock unit (“RSUs”).

MATERIAL CHANGES IN FINANCIAL CONDITION

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 $43.4 million of cash and restricted cash as of March 31, 2026 versus $15.4 million at December 31, 2025.

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 new credit facility.

For the details of the borrowing availability under our credit facility, see “Item 1.

Financial Statements - Note 4 – Bank Debt” to our unaudited condensed 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 March 31, 2026 unaudited condensed 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.

Liquidity consists of our additional borrowing capacity and unrestricted cash and cash equivalents.

As of March 31, 2026, we had additional borrowing capacity of $60.8 million under the New Revolving Credit Facility and total liquidity of $97.5 million.

Our additional borrowing capacity is net of $14.2 million in outstanding letters of credit as of March 31, 2026 that were required to maintain surety bonds and other credit support obligations.

Consolidated Statement of Cash Flows Summary.

The first quarter of 2026 and 2025 unaudited condensed consolidated statements of cash flows are summarized as follows:

Three Months Ended March 31,

Net cash provided by operating activities

Net cash used in investing activities

Net cash (used in) provided by financing activities

Increase in cash, cash equivalents, and restricted cash

Operating Activities.

The decrease in net cash provided by our operating activities is primarily attributable to the combination of (i) lower Adjusted EBITDA and related working capital items, (ii) increased inventory levels, (iii) incremental amortization of prepaid forward sales contracts for cash received in prior periods, and (iv) lower cash payments of interest, partially offset by incremental cash received for annual sales of accredited capacity compared to the first quarter of 2025.

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 condensed consolidated statements of operations.

Investing Activities.

The change in net cash used by our investing activities is primarily attributable to (i) a decrease in our capital expenditures of $4.0 million partially attributable to lower capitalization of mine development costs and (ii) a $0.2 million increase in the proceeds from sales of equipment.

For the three months ended March 31, 2026, capital expenditures (“Capex”) was $7.7 million allocated as follows (in millions):

Capex per the condensed consolidated statements of cash flows

We expect our 2026 Capex to remain broadly stable as compared to our 2025 Capex, excluding any impacts of the ERAS Project.

The actual amount of our 2026 Capex 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 Capex will not vary materially from our expectations.

Financing Activities.

The increase in net cash provided by our financing activities is primarily attributable to the net effect of (i) an increase in cash of $53.8 million from the net proceeds of the CMPO, (ii) a reduction in cash attributable to higher net repayments of bank debt of $9.0 million, and (iii) a decrease in cash from incremental lease financing payments of $1.5 million.

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.

Prior to March 5, 2026, the Company was party to a credit agreement with PNC Bank, National Association (in its capacity as administrative agent, "PNC Bank").

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

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 daily 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.

See “ Item 1.

Financial Statements - Note 4 – Bank Debt ” to our unaudited condensed 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 $18.0 million, including $6.3 million at Merom, presented as asset retirement obligations (“ARO”) and accrued liabilities in our accompanying condensed 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, and the estimates used in impairment analysis are our critical accounting estimates.

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

If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected.

The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data.

The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available.

Changes in the reserves estimates from the prior year were nominal.

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

SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations.

Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.

Obligations are reflected at the present value of their future cash flows.

We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished.

The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves.

We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums.

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

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

On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience.

Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions.

We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions.

We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position.

We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries.

Changes to the estimates from reported amounts in the prior year were not significant.

Inventory is valued at a lower of cost or NRV.

Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change.

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 September 30, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively.

Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group.

For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations.

These determinations could impact the determination and measurement of a potential asset impairment.

Management evaluates

assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed.

If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value.

Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants.

The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review.

Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

No material changes from the disclosure in our 2024 Annual Report on Form 10-K .

For a description of our critical accounting policies and estimates, refer to “ Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations ” included in our 2025 Form 10-K.

For a discussion of recent accounting pronouncements, newly adopted and recent accounting pronouncements not yet adopted, see “ Note 2 – Recent Accounting Pronouncements” to the accompanying unaudited condensed consolidated financial statements included in Item 1 of this Quarterly Report.

We did not have any material changes in critical accounting policies, estimates, judgments and assumptions during the three months ended March 31, 2026.

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-Q

Item 2. Management’s Discussion and Analysis