What changed in this filing

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Item 2. Management’s Discussion and Analysis

2025-11-10 compared with 2025-08-11 · 161 added, 151 removed, 191 unchanged (62% of the section changed)

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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 positive results in the second quarter, which is especially encouraging given that energy pricing and demand in the spring season is typically lower due to milder weather.

During the quarter we generated $102.9 million of revenue with $17.6 million of EBITDA margin, an improvement of $9.1 million of EBITDA margin over the same period a year ago.

One of our two generating units at Merom was out of service for planned maintenance during the majority of the quarter.

We benefited from higher-than-expected energy prices and consistent energy volumes from the generating unit that was in operation.

We also saw positive results in our Coal Operations segment, including improvements in our coal production, operating costs and recovery metrics at our Oaktown mining complex.

These improvements, in addition to the planned outage at Merom, resulted in higher coal inventory levels companywide.

We expect coal inventories to decrease in the second half of 2025 based on increased coal shipments and greater energy generation at Merom now that this year’s planned outage is completed.

The Company continued its strategy of supplementing periods of weaker pricing with limited sales of firm energy.

These firm energy sales help to mitigate the impacts of inconsistent weather and fluctuating energy prices and allowed us to focus on maximizing the value of Merom in a way that balances challenging periods while also giving us flexibility to capture upside opportunity in periods of elevated pricing, like we saw in June.

In late June, we expanded our relationship with one of our firm energy counterparties, entering into a $35.0 million prepaid forward power sales contract with energy to be delivered at various periods throughout 2025 and 2026.

In connection with this agreement, we also entered into the Third Amendment to our Credit Amendment, which moved the required Term Loan payment from October 2025 to January 2026 and adjusted various covenants to provide additional operating flexibility throughout the summer and into the fourth quarter.

The prepaid funds will be used in a variety of ways, including fully cash collateralizing the outstanding $19.0 million Term Loan principal balance under the Credit Agreement and to support company operations.

Turning to our negotiations in support of a long-term power purchase agreement with a utility or data center developer, we have seen significant interest in our capacity and energy offerings throughout the quarter.

Following the termination of our exclusivity agreement with a leading global data center developer, we have seen a high level of engagement from third parties, including other data center developers and utilities.

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

While we remain in contact with our original counterparty, we are encouraged by our discussions with several of these newly interested parties.

We believe that the evolving energy markets, specifically as related to data center growth and favorable utility demand, as well as the favorable regulatory environment, provide the potential to leverage opportunities that simply were not available when we began the request for a proposal process last summer.

The utility discussions that we are currently engaged in are intrinsically more straightforward to negotiate, can be implemented sooner and could result in greater sales volumes of energy and accredited capacity.

We anticipate pricing will be around the energy curve with terms of ten years or more.

As we have highlighted in previous disclosures, many of the non-utility arrangements are inherently complex and involve multiple parties, which adds time and alignment challenges to the negotiation process.

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

Over the last several quarters, we have highlighted our belief that the prevailing industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable resources such as wind and solar will create an unbalanced energy equation, reduce reliability and increase long-term volatility in the energy markets.

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.

In light of this, we continue to evaluate how to further enhance this value.

As we have previously discussed, we are actively seeking acquisition opportunities for additional dispatchable generation, which we believe will help diversify our risk and provide opportunities to upsize strategic future

arrangements.

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.

Additionally, we see the potential of enhancing the reliability, resiliency and flexibility of Merom by adding natural gas and creating a dual fuel scenario, if and when the opportunity makes operational and financial sense.

While we are still in the evaluation process, by adding the capability to co-fire with gas or coal, we believe that it could provide Hallador Power the ability to take advantage of the best fuel cost scenario and better control our operating expenses.

We believe that the ability to co-fire with natural gas and/or coal will also provide increased resiliency in times where gas availability is traditionally limited, as we have seen in various winter storms across the last several years.

This co-firing also allows us to retain the advantage of operating our Sunrise Coal subsidiary and leveraging our own coal supply to prevent unreasonable price increases by third party providers while simultaneously supporting our workforce and the surrounding community.

This evaluation is complex on a variety of levels, specifically customer preference and an evolving regulatory environment that could have material impacts on the timing and economic benefits of undertaking such a change.

We continue to invest in the future of the plant through extensive maintenance and capital expenditures.

We had one unit out of service for planned maintenance for most of the quarter and extending into early third quarter.

We typically choose the shoulder season periods for these planned maintenance outages as power demand and pricing in spring are traditionally lower than in other parts of the year.

We also try to limit our firm energy sales during these periods to guard against any unforeseen or forced outages, which have the potential to expose us to spot market pricing.

Despite the outage, we saw stronger than expected prices in June, which we were able to take advantage of with the unit that remained online.

As illustrated in the solid forward sales position table below, in 2026, we currently have 4.0 million delivered energy MWh contracted at an average sales price of $43.05 per MWh.

We continue to see higher demand and increase in our average contracted sales price.

Our largest PPA contract will see an increase of more than $20.00 per MWh in 2026 as compared to 2025 on expected volumes of approximately 1.6 million MWh.

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 curve.

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 remain 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 capture value from the critical factors limiting artificial intelligence and data center growth, accredited capacity and reliable and affordable energy.

Importantly, the positive momentum that we continue to see from the current administration on both the federal and state levels should make transactions of this sort more feasible than they would have been under the prior administration.

Shifting to our Coal Operations, we continue to see the benefits of our 2024 organizational restructuring.

While much of the last year was focused on optimizing production, headcount, and strategy to best support our Electric Operations and our existing third-party coal contracts, we have seen improved operational expenses, more efficient recoveries and accelerating shipments.

As we have said before, this organizational restructuring should provide us with greater flexibility to quickly scale if we see coal prices increase to a point that justifies restarting production at higher cost units.

Additionally, while our coal inventories are elevated, we believe that we are well-positioned to meet industry needs in the event that coal plants, including Merom, continue to dispatch at higher levels.

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

Current market dynamics remain stronger than they have been in the past year, and we continue to evaluate if and when it makes sense to bring on additional coal production in the back half of 2025 and/or 2026.

Starting in 2026 our average contracted sales price across all contracts is approximately $4.00 per ton higher than the average contracted sales price in 2025.

Notwithstanding this potential to increase production, we currently expect to produce approximately 3.7 million tons of coal in 2025.

In the first half of 2025, we produced approximately 2.1 million tons of coal at our Oaktown Mining Complex.

We 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 additional flexibility in our sales portfolio if prices increase on the spot market.

This optionality to obtain low-cost tons 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 fuels costs at Merom.

The continued transformation of Hallador from a commodity focused producer of coal to an IPP remains our primary focus, while leveraging this transition to capture the expanding margins of the energy markets and capitalize on the soaring demand for reliable electricity.

The strong and varied interest that we have experienced following the end of our exclusivity period has been encouraging and we are steadfast in our belief of the value that our strategic transition in support of the economy’s desire for reliable energy will bring.

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.

Our goal is for Hallador Power to generate on average 1.5 million MWh on a quarterly basis, which equates to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below).

During the first six months of the year, Hallador Power generated 2.2 million MWh, or 73.3% of our quarterly target and purchased 0.2 million MWh.

Three Months Ended June 30,

Six Months Ended June 30,

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

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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 “Solid Forward Sales Position” table below.

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.

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

The following is an overview our Electric Operations and Coal Operations for Q2 2025 compared to Q1 2025.

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:

During the second quarter of 2025, we sold 0.8 million MWh representing a 50.0% decrease in total MWh sold from Q1 2025.

This decrease was expected as Q2 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 quarter.

Operating revenues increased $17.53 per MWh from the first quarter of 2025.

This change was primarily due to the allocation of capacity revenue over lower energy volumes.

In Q2 2025, Electric Sales were $60.0 million, or $72.44 per MWh sold, on a segment basis.

In Q2 2025, Electric Operations fuel, other operating and maintenance and cost of purchased power were $34.2 million, or $41.31 per MWh compared to $49.4 million, or $31.59 per MWh in Q1 2025.

This increase in costs per MWh was due to lower energy volumes driven by the planned maintenance outage at Merom.

Q2 2025 Electric Operations income before income taxes was $13.99 per MWh, an increase of $1.72 from Q1 2025.

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:

During the second quarter of 2025, 0.9 million tons of coal were shipped on a segment basis, with approximately 0.1 million tons of that being shipped to Merom for $7.4 million.

This is a decrease of 0.2 million tons of coal shipped from Q1 2025, on a segment basis.

This decrease in coal shipments is mainly driven by a 70.0% reduction in shipments to Merom due to the shoulder season and lower demand for power.

In Q2 2025, Coal Operations operating revenues were $45.5 million, or $51.16 per ton, on a segment basis, an increase of $0.02 per ton from Q1 2025.

In Q2 2025, Hallador’s Coal Operations other operating and maintenance costs were $18.2 million, or $20.50 per ton, compared to $23.9 million, or $22.27 per ton, on a segment basis, in Q1 2025.

We recorded income before income taxes for the quarter of $1.58 per ton on a segment basis.

This is an increase of $7.56 per ton from Q1 2025.

Solid Forward Sales Position (unaudited)

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.

Forward Sales Position (unaudited)*

Contracted MWh (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.

* 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 $49.8 million and $39.9 million for the six months ended June 30, 2025 and 2024, respectively.

Bank debt increased by $1.0 million during the six months ended June 30, 2025.

As of June 30, 2025, our bank debt was $45.0 million.

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 June 30, 2025, we also had an additional borrowing capacity of $32.8 million.

Total liquidity as of June 30, 2025 was $42.0 million.

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

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CAPITAL EXPENDITURES (“Capex”)

For the six months ended June 30, 2025, capex was $24.8 million allocated as follows (in millions):

For the nine months ended September 30, 2025, capex was $44.3 million allocated as follows (in millions):

Oaktown – maintenance capex

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Electric Operations

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

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(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 June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

MWh Generated (in thousands)

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(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).

Delivered Energy revenue on a dollar and per MWh basis remained flat quarter over quarter, however MWh generated decreased 0.1 million or 3.3% and MWh purchased increased 0.1 million MWh or 25.4% during the same periods.

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.

Cost of purchased power in Q2 2025 was $2.2 million at an average purchase price of $29.35 MWh compared to $2.6 million at an average price of $44.39 per MWh in Q2 2024.

Fuel costs decreased $3.1 million, or 12.6%, compared to the second quarter of 2024.

On a per MWh basis, fuel costs decreased $3.34, or 11.5%.

This change was due to decreased production of energy as noted above resulting in 0.1 million tons or 11.4% less tons of coal used.

The average purchase price per ton of coal used in the plant on a segment basis, was $53.38 in the second quarter of 2025, decreasing from $54.17 per ton in the second quarter of 2024.

Other operating revenue increased $3.0 million, or 1701.1%, compared to Q2 2024.

Other operating revenue on a per MWh basis increased $3.58, or 1704.8%.

This change was due to revenue received related to contractual negotiations on the exclusivity agreement.

Electric interest expense increased $1.7 million, or 916.7%, compared to the second quarter of 2024.

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 and June 2025.

Income before income taxes increased $5.0 million, or 75.3%, compared to the second quarter of 2024.

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.

Delivered energy increased $24.0 million, or 26.1%, compared to the first six months of 2024.

This increase is attributable to new PPA contracts starting in Q1 2025 that were not in effect during 2024.

Total PPA hours delivered in the first six months of 2025 were 1.8 million at an average price of $36.63 per MWh compared to delivery of 1.0 million MWh at an average price of $34.42 for the same period in 2024.

Fuel increased $10.0 million, or 20.4%, compared to the first six months of 2024.

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.

On a per MWh basis, cost of purchased power increased $1.14, or 43.3%.

Electric interest expense increased $3.3 million, or 984.7%, compared to the first six months of 2024.

(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 and June 2025.

Income before income taxes increased $9.1 million, or 41.9%, compared to the first six months of 2024.

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.

Coal Operations

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

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Income (Loss) before Income Taxes

Three Months Ended June 30,

Six Months Ended June 30,

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

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Income (Loss) before Income Taxes

Other operating and maintenance costs decreased $3.4 million, or 15.5%, compared to the second quarter of 2024.

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%.

This change was the result of impacts related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as increased coal production of 0.2 million tons or 19.1% in Q2 2025 over Q2 2024 whereas coal sales increased 0.1 million tons or 4.8% increasing coal inventory.

General and administrative costs decreased $1.6 million, or 45.2%, compared to the second quarter of 2024.

On a per ton basis general and administrative costs decreased $1.96, or 47.7%.

This change was related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as the retirement of an executive officer in 2024.

Depreciation, depletion and amortization decreased $8.6 million, or 96.0%, compared to the second quarter of 2024.

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 as well as a $4.8 million out-of-period adjustment recorded during the second quarter of 2025 due to an overestimate of depreciation, depletion and amortization expense in the first quarter 2025.

Interest expense decreased $1.3 million, or 39.5%, compared to the second quarter of 2024.

On a per ton basis, interest expense decreased $1.59, or 42.3%.

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

Income before income taxes increased $15.9 million, or 109.7%, compared to the second quarter of 2024.

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

Coal sales decreased $11.4 million, or 10.2%, compared to the first six months of 2024.

On a per ton basis, coal sales decrease $3.02, or 5.6%.

Consolidated coal sales decreased $14.1 million, or 17.1% from 2024.

These declines were due to reductions in volume and average sales price for our coal.

Our average sales price, on a segment basis, decreased $2.99 per ton and we sold 0.1 million tons less compared to 2024.

Our average sales price, on a consolidated basis for 2025 decreased $4.27 per ton and we sold 0.2 million tons less compared to 2024.

Other operating and maintenance costs decreased $11.3 million, or 21.1%, compared to the first six months of 2024.

On a per ton basis, other operating and maintenance costs decreased $4.41, or 17.0%.

This change was partially the result of the organizational restructuring that occurred in February 2024 extending into Q2 2024 which led to an expected reduction in production costs related to the higher cost mining locations such as roof support and maintenance.

Tons sold decreased 0.1 million tons or 4.9% which further decreased royalty expenses.

Labor decreased $8.8 million, or 18.8%, compared to the first six months of 2024.

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 655 as of June 30, 2025 from 924 prior to the restructuring.

General and administrative costs decreased $1.7 million, or 28.7%, compared to the first six months of 2024.

On a per ton basis, general and administrative decreased $0.72, or 25.0%.

This change was related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as the retirement of an executive officer in 2024.

Other operating revenue increased $1.4 million, or 108.3%, compared to the first six months of 2024.

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.

Depreciation, depletion and amortization costs decreased $9.5 million, or 48.3%, compared to the first six months of 2024.

(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.

Interest expense decreased $2.5 million, or 38.7%, compared to the first six months of 2024.

(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.

Loss before income taxes decreased $25.5 million, or 87.4%, compared to the first six months of 2024.

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

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

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EARNINGS (LOSS) PER SHARE

Our effective tax rate (ETR) is estimated at ~0% and ~23% for the six months ended June 30, 2025 and 2024, respectively.

For the six months ended June 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 ~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 ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance.

25 unchanged sentences

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

Inventory is valued at a lower of cost or net realizable value (NRV).

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

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.

11 unchanged sentences

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