What changed in this filing

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Item 2. Management’s Discussion and Analysis

2025-05-12 compared with 2024-11-12 · 176 added, 193 removed, 119 unchanged (76% 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.

Hallador Energy made significant progress in its transformation to an Independent Power Producer this quarter by signing a non-binding term sheet (“Term Sheet”) with a leading global data center developer.

Our team is working diligently to finalize definitive agreements with this partner and relevant utilities that will support the delivery of our in front of the meter energy and capacity to the large hyperscaler.

As we have discussed before, these types of deals are complex arrangements involving multiple parties.

If we reach definitive agreements, we will have contracted large portions of our plant’s energy and capacity at much improved margins for more than a decade to come.

The completion of the transaction contemplated by the Term Sheet is subject to, among other matters, the negotiation and execution of definitive agreements and there can be no assurance that definitive agreements will be entered into or that the proposed transaction will be consummated on the terms or timeframe currently contemplated, or at all.

The path to this type of long-term, higher margin transaction has been focused and deliberate.

While we have not yet reached a binding agreement, we are encouraged both by the relationship with our current partner and the heavy interest that we continue to see from alternative counterparties in our energy and capacity offerings.

This continued interest highlights the supply shortage in accredited capacity that we believe the MISO market is experiencing and provides the Company options in the event that we are unable to reach agreement in connection with the executed Term Sheet.

We believe accredited capacity in MISO continues to increase in value and demand, particularly in our sales region of MISO Zone 6, an area that includes Indiana and a portion of western Kentucky.

This is important to Hallador based on our belief that Hallador has a significant amount of the remaining unsold accredited capacity in MISO Zone 6 over the next few years.

Our current belief is guided by several factors, including:

● Demand for power is growing at the fastest rate in several decades due to new demand from data centers, electric vehicles, and onshoring of industry.

● Indiana is seeing consistent interest from data center developers, likely due to favorable Indiana tax law for datacenter development and a pro-business climate.

● Supply Response is Restricted:

o MISO has significantly reduced the capacity accreditation it awards to wind and solar generation (non-dispatchable), making it challenging to support accredited capacity needs from generating resources other than coal, U.S.

natural gas (“Gas”), and nuclear (dispatchable).

o We are currently seeing minimal supply response of accredited capacity which we believe relates to the regulatory and environmental challenges for all types of baseload generation, including Gas.

Additionally, we believe the muted supply response is exacerbated by the glut of solar and wind projects, which provide minimal accredited capacity, overwhelming the queue and delaying access to dispatchable generation projects that would supplement the supply of accredited capacity.

● While our data center PPA negotiations proceed, we continue to focus on improving our balance sheet and access to liquidity.

During the quarter we modified our credit facility to provide the Company with short-term covenant relief to pursue additional liquidity.

Subsequent to the quarter, we executed a prepaid forward power sale in the amount of $60.0 million (see “Item 1.

Footnote 21 - Subsequent Events” ), delivering power from June 2025 through December 2026.

A portion of the proceeds were used to pay down $20.0 million on our Term Loan, which satisfies our January 2025, April 2025, July 2025 and a portion of our October 2025 required quarterly Term Loan payments.

Our October 2025 required quarterly Term Loan payment is reduced to $6.0 million as part of the $20.0 million Term Loan pay down.

We also paid $34.0 million on our revolver.

We did not utilize the ATM in the third quarter.

● Quarter-over-Quarter our financial results improved.

Our wholly owned subsidiary, Hallador Power, generated 1,074,000 MWh during the quarter versus 780,000 MWh in the second quarter of 2024.

This is a result of stronger power pricing during the quarter and a significant decrease in Gas inventory levels against the imbalances we saw in the first half of the year.

As Gas inventory decreased and prices increased, coal generation’s position in the dispatch stack improved.

During the third quarter of 2024, our power plant operated more frequently than in the second quarter of 2024, partly due to having no planned maintenance, and as a result, our costs at the plant improved to $44.42 per MWh from $62.98 per MWh.

● During the third quarter, results at our Sunrise Coal subsidiary also improved in connection with the restructuring of our mining division that we undertook beginning in the first quarter of 2024 (see “Item 1.

Footnote 16 – Organizational Restructuring” ).

In July of 2024, we completed a project for four of our most productive units, which allowed all units to be on a split air system, which helped to improve efficiency and reduce operating costs at the mine to $66.43 per ton produced, a decrease of $1.59 from the second quarter of 2024.

Sunrise Coal entered into a third-party coal contract to provide 2.5 million tons of coal from January 2026 to December 31, 2028, at an average price of $57.60 per ton.

Our goal is for Hallador Power to generate approximately 1,500,000 MWh on a quarterly basis, which equates to approximately 6,000,000 MWh annually (see Hallador Power’s capacity and utilization information below).

During the nine months ended September 30, 2024, Hallador Power generated 2,670,000 MWh, or 59.3% of our target.

During the first nine months of the year, we experienced sales prices of nearly $261.00 per MWh for limited times, balanced against several days of pricing below our variable cost to produce.

These fluctuations led to an inconsistent dispatch schedule.

Three Months Ended September 30,

Nine Months Ended September 30,

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.

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.

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.

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.

Notwithstanding this potential to increase production, we currently expect to produce approximately 3.8 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.

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,

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.

We have already sold a large portion of our near term Capacity, which we believe makes our forward Capacity sales goals attainable as illustrated in our “Solid Forward Sales Position” table below.

In addition to the Term Sheet discussed above, which is not included in the graph below, our forward contracted energy sales position has a significant price increase in future years as illustrated in the graph below.

To match Sunrise’s production levels and cost structure to that of the market demands, we restructured Sunrise operations in the first quarter of 2024.

As we have previously noted, the restructuring included a reduction in force (“RIF”) of approximately 110 people in February, and we have since allowed attrition to further reduce our workforce by approximately 140 additional people, a total workforce reduction of more than 25%.

We also restructured our operations to focus on our more profitable units and to idle units with higher production costs.

Transitioning our Oaktown mining facilities from 7 units of production to 4 units of production was a deliberate process which took considerable time and effort, and was completed in mid-July.

We are encouraged by the early results of Sunrise’s restructuring and have seen improvement in mining costs since we made the decision to adjust our operations.

The Company last reviewed its long-lived assets for impairment during the fourth quarter of 2023 and concluded no impairment was indicated.

In preparing the Company’s impairment analysis, it utilizes undiscounted net cash flows over the expected life of the long-lived asset based upon anticipated production along with contracted and forward prices as well as historical operating expenses adjusted for inflation.

This cash flow analysis is largely dependent upon the operating plans of the Company, which are reviewed by the Company and its Board of Directors no less than annually, normally during the fourth quarter of each year.

Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.

During the third quarter of 2024, the Company began a review of our mining assets and our future mining plans.

This review will continue through the fourth quarter of 2024.

Should the anticipated future mining activity be reduced, an impairment of our mining assets could occur.

The amount of any such potential impairment, if any, is not currently estimable and will ultimately be based upon the finalized operating plans of the Company as approved by its Board of Directors, market driven pricing and cost trends, which are not known at this time.

Nevertheless, the carrying amount of the Company’s mining assets is material to its condensed consolidated balance sheet at September 30, 2024 and any future impairment of such assets could therefore be material.

The Company has concluded that no impairment exists as of September 30, 2024 as no triggering events have occurred during the period ended September 30, 2024.

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.

We believe our forward Capacity sales goals are attainable as illustrated in our “Solid 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 Q1 2025 compared to Q4 2024.

Q1 2025 Net Income of $10.0 million.

Electric Operations:

During the third quarter of 2024, we sold 1,183,000 MWh representing a 41.0% increase in total MWh sold and a decrease of $10.31 in operating revenues per MWh from Q2 2024.

In Q3 2024, Electric Operations operating revenues were $71.9 million, or $60.78 per MWh, on a segment basis.

In Q3 2024, Electric Operations operating expenses were $52.5 million, or $44.42 per MWh, which represents a decrease of $18.56 per MWh from Q2 2024.

Q3 2024 Electric Operations income from operations was $16.36 per MWh, an increase of $8.25 from Q2 2024.

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.

In Q1 2025, Electric Operations fuel, other operating and maintenance and cost of purchased power were $49.4 million, or $31.59 per MWh compared to $41.1 million, or $32.34 per MWh in Q4 2024.

Q1 2025 Electric Operations income before income taxes was $12.27 per MWh, an increase of $4.02 from Q4 2024.

Coal Operations:

During the third quarter of 2024, 0.9 million tons of coal were shipped on a segment basis during the quarter, with approximately 0.3 million tons of that being shipped to the Merom Power Plant for $16.7 million.

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.

In Q3 2024, Coal Operations operating revenues were $49.3 million, or $53.27 per ton, on a segment basis.

In Q3 2024, Hallador’s Coal Operations operating expenses were $66.43 per ton on a segment basis, which represents a $1.59 per ton decrease from Q2 2024.

We recorded a loss from operations for the quarter of $13.16 per ton 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.

In Q1 2025, Coal Operations operating revenues were $54.8 million, or $51.14 per ton, on a segment basis an increase of $5.55 per ton from Q4 2024.

This increase is a result of new coal contract terms.

In Q1 2025, Hallador’s Coal Operations other operating and maintenance costs were $23.9 million, or $22.27 per ton, compared to $8.9 million, or $10.13 per ton, on a segment basis, in Q4 2024.

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.

Q3 2024 Activity

Cash Flow & Debt

During Q3 2024, we had net cash used in operating activities of $12.9 million, and we increased our bank debt by $24.5 million.

During the third quarter of 2024, we executed the First Amendment to our Credit Agreement.

The primary purpose of the First Amendment was to provide us with short-term covenant relief to pursue additional liquidity.

As of September 30, 2024, our bank debt was $70.0 million and our total liquidity was $34.9 million.

Total liquidity is comprised of a) our additional borrowing capacity which is net of outstanding letters of credit that we are required to maintain for surety bonds and amounts drawn on our revolver, and b) cash and cash equivalents.

Footnote 5 – Bank Debt” .

During Q3 2024, we signed a ninety-day ROFR with a potential buyer of our wholly-owned subsidiary Summit for $3.2 million.

Summit is included in our “Corporate and other and eliminations” segment and primarily holds property, plant and equipment.

Summit met the held-for-sale criteria and its assets were included in “assets held-for-sale” in our current assets section of our condensed consolidated balance sheets.

Footnote 20 – Assets Held-For-Sale” .

Solid Forward Sales Position (unaudited)

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Average daily contracted capacity MW

Average contracted capacity price per MW

Average contracted capacity price per MWd

Contracted capacity revenue (in millions)

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Contracted coal revenue - 3rd party (in millions)

Committed and unpriced tons - 3rd party (in millions)

Total contracted tons - 3rd party (in millions)

TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED

Priced tons - Merom (in millions)

Avg price per ton - Merom

Contracted coal revenue - Merom (in millions)

Priced tons - Intercompany (in millions)

Avg price per ton - Intercompany

Contracted coal revenue - Intercompany (in millions)

TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT

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Liquidity and Capital Resources

As set forth in our condensed consolidated statements of cash flows, cash provided by operations was $27.0 million and $79.5 million for the nine months ended September 30, 2024 and 2023, respectively.

Bank debt was reduced by $21.5 million during the nine months ended September 30, 2024.

As of September 30, 2024, our bank debt was $70.0 million.

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.

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

As of September 30, 2024, we also had an additional borrowing capacity of $31.1 million.

Total liquidity as of September 30, 2024 was $34.9 million.

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.

Material Off-Balance Sheet Arrangements

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CAPITAL EXPENDITURES (capex)

For the nine months ended September 30, 2024, capex was $39.6 million allocated as follows (in millions):

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

Oaktown – maintenance capex

Oaktown – investment

Freelandville Mine

Capex per the Condensed Consolidated Statements of Cash Flows

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Electric Operations and Coal Operations.

The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the Notes to the Condensed Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana, which we account for using the equity method, and our held-for-sale wholly-owned subsidiary Summit Terminal LLC, a logistics transport facility located on the Ohio River.

The remainder of our operations, which are not significant enough on a stand-alone basis to warrant treatment as an operating segment, are presented as “Corporate and Other and Eliminations” within the Notes to the Condensed Consolidated Financial Statements and primarily are comprised of unallocated corporate costs and activities, including a 50% interest in Sunrise Energy, LLC, a private gas exploration company with operations in Indiana and Oaktown Gas, LLC, which we account for using the equity method.

Electric Operations

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

Three Months Ended March 31,

(in thousands)

Delivered Energy

OPERATING REVENUES:

Capacity Revenue

Electric Sales

Other Operating Costs (1)

Other Operating and Maintenance Costs (2)

Cost of Purchased Power

General and Administrative

EBITDA Margin

Other Operating Revenue

Depreciation, Depletion and Amortization

Asset Retirement Obligations Accretion

Exploration costs

General and administrative

Total operating expenses

INCOME (LOSS) FROM OPERATIONS

Three Months Ended September 30,

Nine Months Ended September 30,

(per MWh Sold)

Interest expense

Income (Loss) 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,

MWh Generated (in thousands)

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Delivered Energy

OPERATING REVENUES:

Capacity Revenue

Electric Sales

Other Operating Costs (1)

Other Operating and Maintenance Costs (2)

Cost of Purchased Power

General and Administrative

EBITDA Margin

Other Operating Revenue

Depreciation, Depletion and Amortization

Asset Retirement Obligations Accretion

General and administrative

Total operating expenses

INCOME (LOSS) FROM OPERATIONS:

2023 (third quarter)

Revenues from electric operations increased $4.4 million, or 6.5%, compared to the third quarter of 2023.

While the Merom Facility ran less hours in the third quarter of 2024 compared to 2023, the contracted hours were at higher prices.

We have new delivered energy contracts and capacity contracts with sales starting in 2024.

We entered into three new delivered energy contracts during the current year which increased revenues by $20.9 million.

We entered into three capacity contracts during 2023 that began delivery in 2024 and one new capacity contract that we entered into during the current year, which increased revenues by $10.9 million.

Revenue increases from new contracts were offset by suppressed MISO pricing (~66% of total energy hours at the Merom node being priced below our production cost at our Merom Facility), and reductions in demand for Power and higher demand for Gas as Gas inventories remained high, with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.59 during the same three-month period in 2023.

Fuel decreased $21.1 million, or 41.6%, compared to the third quarter of 2023.

Our MWh sold decreased by 124 MWh, or 9.5%, from the third quarter of 2023.

The decrease in fuel costs are primarily related to our decreased electricity sales and declines in coal market pricing.

We used 0.1 million less tons of coal in our electric production compared to the third quarter of 2023.

The average purchase price per ton of coal used in the plant on a segment basis, was $53.33 in the third quarter of 2024, decreasing from $76.94 per ton in the third quarter of 2023.

Cost of purchased power was $3.1 million during the third quarter of 2024.

As noted above, when energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.

Income from operations increased $22.0 million, or 823.3%, and increased $18.39 per MWh, from the three months ended September 30, 2023.

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

2023 (nine months)

Delivered energy revenues from electric operations decreased $37.3 million, or 20.2%, compared to the nine months ended September 30, 2023 due to suppressed MISO pricing (~75% of total energy hours at the Merom Hub being priced below our production cost at our Merom Facility), reductions in demand for Power and higher demand for Gas as Gas inventories remained high with a continued decline in average spot pricing per MBtu of $2.11 compared to $2.47 during the same nine-month period in 2023.

Fuel decreased $70.5 million, or 48.0%, compared to the nine months ended September 30, 2023.

Production decreased by 942 MWh, or 26.1%, from the first nine months of 2023.

The decrease in fuel costs are due to the expiration of a coal purchase contract in June of 2023 and declines in coal market pricing.

We used 0.5 million less tons of coal in our electric production compared to the nine months ended September 30, 2023.

The average purchase price per ton of coal used in the plant on a segment basis, was $54.83 for the nine months ended September 30, 2024, decreasing from $62.37 during the nine months ended September 30, 2023.

As discussed above, average spot prices for Gas were down per MMBtu decreasing the demand for Electric Power.

Cost of purchased power was $7.7 million during the first nine months of 2024.

As noted above, when energy hours at the Merom Hub are priced below our production cost at our Merom Facility, we make net hourly purchases of power in the MISO market.

Other operating and maintenance costs increased $9.3 million, or 56.0%, compared to the nine months ended September 30, 2023 primarily due to our planned maintenance outage during the second quarter of 2024 which resulted in $7.0 million in additional costs for the period.

Income from operations increased $16.1 million, or 63.7%, and increased $7.23 per MWh, from the nine months ended September 30, 2023.

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

Interest expense

Income (Loss) 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.

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

Coal Operations

Three Months Ended September 30,

Nine Months Ended September 30,

(in thousands)

Three Months Ended March 31,

(in thousands)

OPERATING REVENUES:

Other Operating and Maintenance Costs

General and Administrative

EBITDA Margin

Other Operating Revenue

Depreciation, Depletion and Amortization

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Exploration Costs

General and administrative

Total operating expenses

INCOME (LOSS) FROM OPERATIONS

Three Months Ended September 30,

Nine Months Ended September 30,

Tons Sold (in thousands)

OPERATING REVENUES:

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

Interest expense

Income (Loss) before Income Taxes

Three Months Ended March 31,

Other Operating and Maintenance Costs

General and Administrative

EBITDA Margin

Other Operating Revenue

Depreciation, Depletion and Amortization

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Exploration Costs

General and administrative

Total operating expenses

INCOME (LOSS) FROM OPERATIONS:

2023 (third quarter)

Segment operating revenues from coal operations decreased $85.6 million, or 63.4%, from the third quarter of 2023.

Consolidated operating revenues from coal operations decreased $65.2 million, or 66.6%, from the third quarter of 2023.

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

Our average sales price, on a segment basis, decreased $12.40 per ton and we sold 1.1 million tons less compared to the third quarter of 2023.

Our average sales price on a consolidated basis decreased $7.91 per ton and we sold 1.0 million tons less compared to the third quarter of 2023.

Operating revenues for the third quarter of 2024 include $16.7 million in sales to the Merom plant which were eliminated in the consolidation.

Other operating and maintenance costs decreased $32.7 million, or 54.7%, and labor decreased $10.6 million, or 35.3%, from the third quarter of 2023.

These changes were driven by impacts from the Reorganization Plan disclosed in “Item 1.

Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements.

During the third quarter 2024, underground costs such as roof support and belt maintenance, fuel and utilities, as well as maintenance costs all had significant decreases in comparison to the third quarter of 2023.

We produced 0.7 million tons less in the third quarter of 2024 than the third quarter of 2023.

Depreciation, depletion, and amortization decreased $2.5 million, or 21.7%, from the third quarter of 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $36.9 million, or 149.2%, and decreased $25.22 per ton, from the three months ended September 30, 2023.

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

2023 (nine months)

Segment operating revenues from coal operations decreased $180.6 million, or 52.6%, from the nine months ended September 30, 2023.

Consolidated operating revenues from coal operations decreased $166.0 million, or 58.7%, from the nine months ended September 30, 2023.

Gain (loss) 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.

Consolidated coal sales decreased $19.4 million, or 39.2%, 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 $8.45 per ton and we sold 2.5 million tons less compared to the first nine months of 2023.

Our average sales price, on a consolidated basis, for the first nine months of 2024, decreased $4.63 per ton and we sold 2.6 million tons less compared to the first nine months of 2023.

Other operating and maintenance costs decreased $42.5 million, or 34.6%, and labor decreased $24.6 million, or 27.1%, from the nine months ended September 30, 2023.

These changes were driven by the Reorganization Plan disclosed in “Item 1.

Note 16 — Organizational Restructuring” to the Condensed Consolidated Financial Statements.

During the first nine months of 2024, we produced 2.3 million tons less on a segment basis than the first nine months of 2023.

Additionally, we went from 5 mines producing to 1 mine producing and reduced our coal employee headcount by 313 employees as part of the Reorganization Plan.

Depreciation, depletion, and amortization decreased $8.6 million, or 23.0%, from the nine months ended September 30, 2023 due to decreases in coal production and the remaining useful lives of the mine development assets.

Income (loss) from operations decreased $99.2 million, or 154.4%, and decreased $23.45 per ton, from the nine months ended September 30, 2023.

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

Our average sales price, on a segment basis, decreased $3.25 per ton and we sold 0.1 million tons less compared to 2024.

Our average sales price, on a consolidated basis, for 2025 decreased $4.22 per ton and we sold 0.3 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.

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

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

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Wash plant recovery in %

Maintenance capex

Maintenance capex per ton sold

Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton sold (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

Tons produced

Wash plant recovery in %

Maintenance capex

Maintenance capex per ton

Capex (Coal Operations)

Maintenance capex (Coal Operations)

Maintenance capex per ton (Coal Operations)

Average cost per ton sold⁽ⁱ⁾

(i) Average cost per ton sold is calculated as the sum of the Coal Operation’s “Fuel”, “Other Operating and Maintenance Costs”, “Utilities” and “Labor” costs.

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

Presentation of Consolidated Information

EARNINGS (LOSS) PER SHARE

Our effective tax rate (ETR) is estimated at ~24% and ~13% for the nine months ended September 30, 2024 and 2023, respectively.

For the nine months ended September 30, 2024, we recorded income taxes using an estimated annual effective tax rate 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 ~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 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 September 30, 2024, and December 31, 2023, coal inventory includes NRV adjustments of $1.8 million and $2.0 million, respectively.

As of March 31, 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.

Changes in anticipated activity levels, pricing or operating expenses can have significant effects on the ultimate value of the undiscounted cash flow analysis.

During the third quarter of 2024, the Company began a review of its Oaktown mining facilities and future mining plan related to this complex.

This review will continue through the fourth quarter of 2024.

Should the anticipated future mining activity related to the Company’s Oaktown mining facilities be reduced, an impairment of certain mining assets could occur.

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

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

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

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

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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What changed 10-Q

Item 2. Management’s Discussion and Analysis