What changed in this filing

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Item 2. Management’s Discussion and Analysis

2025-08-11 compared with 2025-05-12 · 162 added, 115 removed, 180 unchanged (61% 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 very pleased with our first quarter results.

Building on the progress we made throughout 2024 in transitioning our company from a bituminous coal producer to an integrated independent power producer (“IPP”), our quarterly results showed the upside of this strategy and business model.

As gas inventories dropped and colder weather prevailed, we benefitted from higher energy prices and delivered energy volumes during January and February.

We also saw improvements in our coal production throughout the first three months of the year as our 2024 restructuring efforts continue to take hold.

During the quarter, we generated $117.8 million of revenue generating $19.3 million of adjusted EBITDA, an improvement of $6.2 million and $12.5 million , respectively, over the same period a year ago.

The Company continued to leverage the strong relationships we built with multiple counterparties, allowing us to supplement periods of weaker pricing with limited sales of firm energy.

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

With respect to our ongoing negotiations with a leading global data center developer for the supply of a significant portion of our plant's output of capacity and energy for well over a decade, we believe that we continue to make meaningful progress towards the execution of definitive agreements.

Our partner has made substantial investment with Hallador through the purchase of an exclusivity agreement which we disclosed last quarter, and with other stakeholders through payments and agreements to secure land, transmission capacity and equipment in support of the potential transaction.

As we have previously disclosed, the exclusivity period runs through the beginning of June 2025.

As we also highlighted in previous disclosures, these types of deals are inherently complex and involve multiple parties, which adds time and alignment challenges to the negotiation process.

Despite these challenges, we remain encouraged by our partners and the steady progress that we continue to make towards definitive agreements.

That said, it is uncertain that the definitive agreements will be executed by the expiration of the current exclusivity period.

We are presently evaluating our counterparty’s request to extend the exclusivity period versus entertaining other opportunities while concurrently moving our original deal forward on a non-exclusive basis.

While we remain encouraged by our progress and still believe that our current development partner represents a tremendous long-term opportunity for our company and its shareholders, we would be remiss to ignore the high level of interest that we have seen from third parties that would like to discuss alternative opportunities if we are ultimately unable to finalize definitive agreements with our current partner.

Taken as a whole, we firmly believe that, in the end, we will forge a strategic partnership that will create significant value for years to come.

In the past, we 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 lead to an unbalanced energy equation and extended volatility in the energy markets.

We believe this volatility has the potential to make the attributes of our subsidiary, Hallador Power, much more valuable due to the enhanced reliability we provide versus non-dispatchable generators.

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.

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.

Consistent with this belief, we are actively seeking opportunities to acquire additional dispatchable generation, which should help diversify our risk and provide opportunities to upsize the strategic deals that we continue to evaluate.

We believe that this approach enhances our financial flexibility and strengthens our position in the evolving energy market.

We continue to study the benefits of not only adding additional generation through acquisition or expansion, but the potential of enhancing the reliability, resiliency and flexibility of our current plant by adding natural gas co-firing and creating a dual fuel scenario.

While we are still in the evaluation process, and we recognize the tremendous amount of work that is required to accomplish such a transition, by adding the capability to co-fire with gas or coal, we believe that it will lead to opportunities where the counterparty desires to limit the amount of coal fired electricity that they are purchasing, while also providing Hallador the ability to take advantage of the best fuel cost scenario and better control our operating expenses across multiple fuel scenarios.

Additionally, 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 limited, as we have seen in various winter storms across the last several years.

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.

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.

As we look to the future, our Merom Power Plant can produce up to 6 million MWh annually.

The forward power price curves indicate that the margins earned on energy produced at Merom and the value of the accredited capacity sales assigned to the plant continue to increase, as we saw in the most recent MISO auction, where accredited capacity sold at prices in excess of $600 per MW Day in high demand seasons.

We are seeing strong indications for both energy and capacity sales in 2025 and beyond and remain excited by our negotiations related to supporting data center development within the State of Indiana for many years to come.

We believe that our approach should allow Hallador Power to capture higher prices and energy volumes in the future versus what we have historically achieved since buying the plant in late 2022, specifically as we look to 2027 and beyond.

Following the end of the quarter, we completed maintenance on one of the units at the plant and now have that unit back in service.

We currently have a second unit out of service for scheduled maintenance and expect that unit to be back online early in the third quarter.

We typically choose the shoulder season periods for these scheduled 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 electricity sales during these periods to guard against any unforeseen or forced outages, which have the potential to expose us to spot market pricing.

Despite these outages, we have contracted approximately 3.0 million MWh for the remainder of 2025 at an average price of $37.20/MWh, which should help to smooth our exposure to the spot market throughout the remainder of the year.

For 2026, we currently have contracted 3.4 million MWh at an average sales price of $44.43/MWh and continue to see high demand.

Following 2026, we are optimistic that we can sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a higher forward curve.

As we said on March investor call, we continue to evaluate other strategic transactions that could add durability, scale, and geographic expansion opportunities to our electric operations.

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.

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 struggling grid rather than cannibalizing the overall reliability of what exists today.

We are optimistic about the potential to add to our strategic portfolio and the long-term benefits that such a transaction could produce for the company, its shareholders and its customers.

This model for growth enables us to continue our shift away from the less favorable pricing related to plant acquisition, to traditional wholesale market pricing, and ultimately to the enhanced pricing associated with supporting data centers and other large load end users.

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

Shifting to our coal operations, we continue to see improvements from the restructuring of our Sunrise Coal division that we initially announced in the first quarter of 2024.

We spent much of last year optimizing production, headcount, and strategy to best support our electric operations and our existing third-party coal contracts.

As we look to the future, this restructuring should provide us with greater flexibility to quickly scale if we see coal prices increase to a point that justifies restarting production at our more expensive units.

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

Current market dynamics have improved over where they were last year, and if this trend continues, it has the potential to encourage us to bring on additional coal production in the back half of 2025 and/or 2026.

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 quarter of 2025, we produced approximately 1.0 million tons of coal at our Oaktown Mining Complex and shipped approximately 1.1 million tons to Merom and other customers.

We use supplemental coal from third party suppliers typically purchased at favorable prices to diversify self-production supply risk and to provide us additional flexibility in our sales portfolio.

The optionality to

obtain low-cost tons either internally or from third parties while capturing upward swings in the commodity markets for coal should further maximize margins while optimizing fuels costs at Merom.

We remain excited about the continued and deliberate transformation of Hallador from a commodity focused producer of coal to an IPP.

We believe this transition provides a significant opportunity to capture the expanding margins of the energy markets and capitalize on the soaring demand for electricity.

We are pleased by the strong interest we continue to see from potential counterparties in our energy and capacity offerings, bolstered by Indiana’s efforts to attract data centers and other high-density power users through its business-friendly climate and favorable tax policies.

The support of the coal industry by the Trump administration throughout the first quarter should also help to dampen the headwinds we were previously facing and provide flexibility as we continue our strategic transition in support of the economy’s insatiable appetite for reliable energy that we see advancing every day.

We continue to believe that our business model positions us well to materially strengthen our opportunities for growth and cash flow generation.

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 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 three months of the year, Hallador Power generated 1.4 million MWh, or 93.3% or our quarterly target and purchased 0.2 million MWh.

Three Months Ended March 31,

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,

Power Capacity and Utilization

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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 $56.0 million or 86.2% of our target with $45.5 million remaining to be delivered in 2025.

For 2025, we have contracted approximately $56.0 million or 86.2% of our target.

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

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Electric Operations:

During the first quarter of 2025, we sold 1.6 MWh representing a 23.1% increase in total MWh sold and an increase of $0.10 in operating revenues per MWh from the fourth quarter of 2024.

This increase is primarily due to entering the winter season which has greater contracted delivered energy MWh than the fall season (Q4 2024).

In Q1 2025, Electric Operations operating revenues were $85.9 million, or $54.91 per MWh sold, on a segment basis.

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.

Coal Operations:

During the first quarter of 2025, 1.1 million tons of coal were shipped on a segment basis during the quarter, with approximately 0.5 million tons of that being shipped to the Merom Power Plant for $24.6 million.

This is an increase of 0.2 million tons of coal shipped from Q4 2024, on a segment basis.

This increase in coal shipments is mainly driven by an increase in shipments to our Merom Power Plant and a new coal contract.

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.

This increase is a result of new coal contract terms.

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.

This change is due to certain reclassifications made as of Q4 2024 for the entirety of 2024 that reduced “other operating and maintenance costs” and increased “depreciation, depletion and amortization”.

This reclassification totaled $8.0 million of which $6.4 million related to the first three quarters of 2024.

We recorded a loss before income taxes for the quarter of $5.98 per ton on a segment basis.

This is a decrease in our loss of $257.11 per ton from Q4 2024 income from operations.

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)

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Liquidity and Capital Resources

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $38.4 million and $16.4 million for the three months ended March 31, 2025 and 2024, respectively.

Bank debt was reduced by $21.0 million during the three months ended March 31, 2025.

As of March 31, 2025, our bank debt was $23.0 million.

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.

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

As of March 31, 2025, we also had an additional borrowing capacity of $52.8 million.

Total liquidity as of March 31, 2025 was $69.0 million.

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.

Material Off-Balance Sheet Arrangements

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CAPITAL EXPENDITURES (capex)

For the three months ended March 31, 2025, capex was $11.7 million allocated as follows (in millions):

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

Oaktown – maintenance capex

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Electric Operations

Three Months Ended March 31,

Three Months Ended June 30,

Six Months Ended June 30,

(in thousands)

Delivered Energy

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Interest expense

Income (Loss) before Income Taxes

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 March 31,

Three Months Ended June 30,

Six Months Ended June 30,

MWh Generated (in thousands)

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Interest expense

Income (Loss) before Income Taxes

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).

Delivered Energy increased $23.2 million, or 47.5%, and we sold 0.7 million MWh more than we did in Q1 2024.

These increases were due to $26.4 million in new revenue contracts starting in Q1 2025 that were not in effect during Q1 2024.

During the quarter we experienced a significantly higher priced natural gas environment when compared to Q1 2024,

( average spot price for natural gas was up $2.02 per mbtu, or 94.7%, compared to Q1 2024).

As natural gas is a competitor to coal, this price increase helped drive up the demand for Power during Q1 2025.

Fuel increased $13.6 million, or 55.8%, compared to the first quarter of 2024.

Our generated MWh’s increased by 0.6 million MWh, or 74.3%, from the first quarter of 2024.

W e used 0.2 million tons, or 61.2%, more in production compared to the prior year.

These increases were primarily related to our increased electricity sales which were partially offset by declines in coal market pricing.

The average purchase price per ton of coal used in the plant on a segment basis, was $53.80 in the first quarter of 2025, decreasing from $57.45 per ton in the first quarter of 2024.

Cost of purchased power was $4.9 million during the first quarter of 2025.

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

During the first quarter of 2025, we purchased 0.2 million MWh, an increase of 90.7% from Q1 2024, at an average price of $47.83 per MWh.

Interest expenses increased $1.6 million, or 1070.3%, compared to the first quarter of 2024.

The increase in our interest expense primarily relates $1.2 million of accretion related to our to a prepaid delivered energy contract.

Income before income taxes increased $4.1 million, or 27.3%, compared to the first quarter of 2024.

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.

On a per MWh basis, interest expense increased $2.06, or 936.4%.

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 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.

The increase in fuel costs were directly related to the increase in MWh generated, requiring the increased use of fuel by 0.2 million tons of coal or 21%.

On a per MWh basis, fuel decreased $3.70, or 13.0% at an average cost of $53.65 per ton for 2025 compared to an average cost of $55.80 per ton for 2024.

The cost of purchased power increased $4.5 million, or 98.3%, 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.

On a per MWh basis, interest expense increased $1.32, or 694.7%.

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

Coal Operations

Three Months Ended March 31,

Three Months Ended June 30,

Six Months Ended June 30,

(in thousands)

Other Operating and Maintenance Costs

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Exploration Costs

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

Gain on disposal or abandonment of assets, net

Interest expense

Income (Loss) before Income Taxes

Three Months Ended March 31,

Three Months Ended June 30,

Six Months Ended June 30,

(in thousands)

Other Operating and Maintenance Costs

5 unchanged sentences

Exploration Costs

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

Gain on disposal or abandonment of assets, net

Interest expense

Income (Loss) before Income Taxes

Coal sales decreased $11.3 million, or 17.1%, compared to the first quarter of 2024.

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

On a per ton basis other operating and maintenance costs decreased $4.94, or 19.4%.

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.

On a per ton basis, depreciation, depletion and amortization decreased $10.11, or 96.2%.

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.

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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.

Operating revenues for the first quarter of 2025 include $24.6 million in sales to the Merom plant which were eliminated in the consolidation.

Other operating and maintenance costs decreased $7.9 million, or 25.0%, compared to the first quarter of 2024.

During the first quarter of 2025, we produced 0.3 million tons less on a segment basis than 2024.

Labor decreased $8.6 million, or 31.3%, from 2024, and decreased $5.01 per ton sold.

These changes were driven by the Reorganization Plan disclosed in “Note 13 — Organizational Restructuring” to the condensed consolidated financial statements.

As part of the Organizational Restructuring, we incurred aggregate expenses of $1.1 million in the first quarter of 2024 that were included in coal operations “Labor” .

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

Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 201 employees.

Interest expense decreased $1.2 million, or 38.0%, compared to the first quarter of 2024.

Our decreased interest expense relates to reductions of convertible debt of $11.0 million, related party debt of $5.0 million and bank debt of $54.0 million, from Q1 2024.

Loss before income taxes decreased $9.6 million, or 65.4%, compared to the first quarter of 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.

On a per ton basis, labor decreased $3.32, or 14.6%.

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.

On a per ton basis, other operating revenue increased $0.76, or 119.2%.

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.

On a per ton basis, depreciation, depletion and amortization decreased $4.35, or 45.6%.

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.

Interest expense on a per ton basis decreased $1.10, or 35.6%.

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.

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 ~26% for the three months ended March 31, 2025 and 2024, respectively.

For the three months ended March 31, 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 ~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 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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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 March 31, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively.

As of June 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.

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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.

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.

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis