# Hallador Energy Co: Form 10-Q for the period ended Mar 31, 2025

- Company: [Hallador Energy Co](/companies/hnrg.md) (CIK 788965)
- Form: 10-Q
- Filed: 2025-05-12
- Accepted by EDGAR: May 12, 2025, 21:20 ET
- Period: 2025-03-31
- Accession: 0001558370-25-007429
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/788965/000155837025007429/hnrg-20250331x10q.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/788965/000155837025007429/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2025-03-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2025-01-01 to 2025-03-31 | $117.8m | us-gaap:Revenues |
| Selling, general and administrative | 3 months, 2025-01-01 to 2025-03-31 | $6.8m | us-gaap:SellingGeneralAndAdministrativeExpense |
| Operating income | 3 months, 2025-01-01 to 2025-03-31 | $13.9m | us-gaap:OperatingIncomeLoss |
| Interest expense | 3 months, 2025-01-01 to 2025-03-31 | $3.7m | us-gaap:InterestExpense |
| Net income | 3 months, 2025-01-01 to 2025-03-31 | $10.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 3 months, 2025-01-01 to 2025-03-31 | $0.23 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 3 months, 2025-01-01 to 2025-03-31 | $0.23 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 3 months, 2025-01-01 to 2025-03-31 | 43,462,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 3 months, 2025-01-01 to 2025-03-31 | $38.4m | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Capital expenditure | 3 months, 2025-01-01 to 2025-03-31 | $11.7m | us-gaap:PaymentsToAcquirePropertyPlantAndEquipment |
| Cash and equivalents | at 2025-03-31 | $6.9m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2025-03-31 | $107.1m | us-gaap:AssetsCurrent |
| Total assets | at 2025-03-31 | $366.1m | us-gaap:Assets |
| Current liabilities | at 2025-03-31 | $177.1m | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2025-03-31 | $250.7m | us-gaap:Liabilities |
| Long-term debt | at 2025-03-31 | $4.0m | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2025-03-31 | $17.0m | us-gaap:LongTermDebtCurrent |
| Shareholders' equity | at 2025-03-31 | $115.3m | us-gaap:StockholdersEquity |

## Management's discussion and analysis

As filed, 40,076 characters.

**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. 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.

| ​ ​ ​ ​ ​ Power Capacity and Utilization | ​ ​ Three Months Ended March 31, 2025 | ​ ​ 2024 ​ |
| --- | ---: | ---: |
| Nameplate capacity (MW)(i) | 1,080 | 1,080 ​ |
| Accredited capacity for the period (MW)(ii) | 845 | 836 ​ |
| Accredited capacity utilization(iii) | 78% | 45% |

(i). Nameplate capacity for the Merom Power Plant refers to the maximum electric output generated by the plant in the period presented and may not reflect actual production. Actual production each period varies based on weather conditions, operational conditions, and other factors.

(ii). Accredited capacity is based on MISO’s average seasonal accreditations for the year. Average seasonal accreditations were 775 MW and 829 MW per day for 2025 and 2024, respectively. Accreditations are weighted and adjusted annually based on 3-year rolling performance metrics.

(iii). Accredited capacity utilization is measured as power produced (MWh) divided by accredited capacity for the period (MW) multiplied by 24, times the number of days for the period.

When forward selling Capacity, we target annual sales of around $65.0 million to offset our fixed annual costs at the plant of approximately $60.0 million. For 2025, we have contracted approximately $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. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability.

### OVERVIEW

The following is an overview our Electric Operations and Coal Operations for Q1 2025 compared to Q4 2024.

### I. Q1 2025 Net Income of $10.0 million.

a. 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).

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

ii. 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.

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

b. 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.

i. 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.

ii. 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.

iii. 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.

### II. Solid Forward Sales Position (unaudited)

| ​ ​ Power Energy | ​ | ​ ​ 2025 ​ ​ | ​ | ​ ​ 2026 ​ ​ | ​ | ​ ​ 2027 ​ ​ | ​ | ​ ​ 2028 ​ ​ | ​ | ​ ​ 2029 ​ ​ | ​ | ​ ​ Total ​ ​ |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: | --- | ---: | --- | --- |
| Contracted MWh (in millions) |  | ​ 3.04 |  | ​ 3.36 |  | ​ 1.78 |  | ​ 1.09 |  | ​ 0.27 |  | ​ 9.54 |
| Average contracted price per MWh | ​ | $37.20 | ​ | $44.43 | ​ | $54.66 | ​ | $52.94 | ​ | $51.33 |  | ​ ​ |
| Contracted revenue (in millions) | ​ | $113.09 | ​ | $149.28 | ​ | $97.29 | ​ | $57.70 | ​ | $13.86 | ​ | $431.22 |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **Capacity** | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  |
| Average daily contracted capacity MW | ​ | 784 | ​ | 733 | ​ | 623 | ​ | 454 | ​ | 100 | ​ | ​ |
| Average contracted capacity price per MWd | ​ | $211 | ​ | $230 | ​ | $226 | ​ | $225 | ​ | $230 | ​ | ​ |
| Contracted capacity revenue (in millions) | ​ | $45.45 | ​ | $61.54 | ​ | $51.40 | ​ | $37.33 | ​ | $3.47 | ​ | $199.19 |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **Total Energy & Capacity Revenue** | ​ |  | ​ |  | ​ |  | ​ |  | ​ | ​ | ​ |  |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Contracted Power revenue (in millions) | ​ | $158.54 | ​ | $210.82 | ​ | $148.69 | ​ | $95.03 | ​ | $17.33 | ​ | $630.41 |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **Coal** | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  | ​ |  |
| Priced tons - 3rd party (in millions) | ​ | 2.21 | ​ | 2.50 | ​ | 2.50 | ​ | 0.50 | ​ | — | ​ | 7.71 |
| Avg price per ton - 3rd party | ​ | $50.95 | ​ | $55.49 | ​ | $56.74 | ​ | $59.00 | ​ | $— | ​ | ​ |
| Contracted coal revenue - 3rd party (in millions) | ​ | $112.60 | ​ | $138.73 | ​ | $141.85 | ​ | $29.50 | ​ | $— | ​ | $422.68 |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED** | ​ | $271.14 | ​ | $349.55 | ​ | $290.54 | ​ | $124.53 | ​ | $17.33 | ​ | $1,053.09 |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| Priced tons - Intercompany (in millions) | ​ | 1.82 | ​ | 2.30 | ​ | 2.30 | ​ | 2.30 | ​ | — | ​ | 8.72 |
| Avg price per ton - Intercompany | ​ | $51.00 | ​ | $51.00 | ​ | $51.00 | ​ | $51.00 | ​ | $— | ​ | ​ |
| Contracted coal revenue - Intercompany (in millions) | ​ | $92.82 | ​ | $117.30 | ​ | $117.30 | ​ | $117.30 | ​ | $— | ​ | $444.72 |
| ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ | ​ | ​ ​ |
| **TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT** | ​ | $363.96 | ​ | $466.85 | ​ | $407.84 | ​ | $241.83 | ​ | $17.33 | ​ | $1,497.81 |

- Actual revenue related to solid forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events.

### LIQUIDITY AND CAPITAL RESOURCES

### I. Liquidity and Capital Resources

a. 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.

b. 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.

c. 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.

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

### II. Material Off-Balance Sheet Arrangements

a. Other than our surety bonds for reclamation, we have no material off-balance sheet arrangements. We have recorded the present value of reclamation obligations of $17.1 million, including $5.8 million at Merom, presented as asset retirement obligations (“ARO”) and accounts payable and accrued liabilities in our accompanying condensed consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.9 million to cover ARO.

### CAPITAL EXPENDITURES (capex)

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

| ​ | ​ | ​ ​ |
| --- | --- | ---: |
| Oaktown – maintenance capex |  | $4.0 |
| Oaktown – investment | ​ | 2.2 |
| Merom Plant | ​ | 5.5 |
| Capex per the Condensed Consolidated Statements of Cash Flows | ​ | $11.7 |

### RESULTS OF OPERATIONS

### Presentation of Segment Information

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

### Electric Operations

*(in thousands)*

| ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 | ​ ​ | ​ ​ 2024 |
| --- | --- | --- | --- | --- |
| Delivered Energy |  | $72,136 | ​ | $48,908 |
| Capacity Revenue | ​ | ​ 13,807 | ​ | ​ 11,773 |
| Electric Sales | ​ | $85,943 | ​ | $60,681 |
| ​ | ​ | ​ ​ | ​ | ​ ​ |
| Fuel | ​ | $(38,071) | ​ | $(24,435) |
| Other Operating Costs (1) | ​ | ​ (8) | ​ | ​ (493) |
| Other Operating and Maintenance Costs (2) | ​ | ​ (4,527) | ​ | ​ (4,886) |
| Cost of Purchased Power | ​ | ​ (6,840) | ​ | ​ (1,926) |
| Utilities | ​ | ​ (676) | ​ | ​ (302) |
| Labor | ​ | ​ (8,143) | ​ | ​ (7,683) |
| General and Administrative | ​ | ​ (1,535) | ​ | ​ (1,058) |
| EBITDA Margin | ​ | ​ 26,143 | ​ | ​ 19,898 |
| Other Operating Revenue | ​ | ​ 87 | ​ | ​ 157 |
| Depreciation, Depletion and Amortization | ​ | ​ (5,161) | ​ | ​ (4,697) |
| Asset Retirement Obligations Accretion | ​ | ​ (120) | ​ | ​ (111) |
| Interest expense | ​ | ​ (1,732) | ​ | ​ (148) |
| **Income (Loss) before Income Taxes** | ​ | $19,217 | ​ | $15,099 |

(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, 2025 (per MWh) | ​ ​ | ​ ​ 2024 |
| --- | --- | --- | --- | --- |
| MWh Generated (in thousands) | ​ | ​ 1,422 | ​ | ​ 816 |
| MWh Purchased (in thousands) | ​ | ​ 143 | ​ | ​ 75 |
| MWh Sold (in thousands) | ​ | ​ 1,565 | ​ | ​ 891 |
| ​ | ​ | **​** **​** | ​ | **​** **​** |
| Delivered Energy |  | $46.09 | ​ | $54.89 |
| Capacity Revenue | ​ | ​ 8.82 | ​ | ​ 13.21 |
| Electric Sales | ​ | $54.91 | ​ | $68.10 |
| ​ | ​ | ​ ​ | ​ | ​ ​ |
| Fuel | ​ | $(24.33) | ​ | $(27.42) |
| Other Operating Costs (1) | ​ | ​ (0.01) | ​ | ​ (0.55) |
| Other Operating and Maintenance Costs (2) | ​ | ​ (2.89) | ​ | ​ (5.48) |
| Cost of Purchased Power | ​ | ​ (4.37) | ​ | ​ (2.16) |
| Utilities | ​ | ​ (0.43) | ​ | ​ (0.34) |
| Labor | ​ | ​ (5.20) | ​ | ​ (8.62) |
| General and Administrative | ​ | ​ (0.98) | ​ | ​ (1.19) |
| EBITDA Margin | ​ | ​ 16.70 | ​ | ​ 22.34 |
| Other Operating Revenue | ​ | ​ 0.06 | ​ | ​ 0.18 |
| Depreciation, Depletion and Amortization | ​ | ​ (3.30) | ​ | ​ (5.27) |
| Asset Retirement Obligations Accretion | ​ | ​ (0.08) | ​ | ​ (0.12) |
| Interest expense | ​ | ​ (1.11) | ​ | ​ (0.17) |
| **Income (Loss) before Income Taxes** | ​ | $12.27 | ​ | $16.96 |

(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).

### Q1 2025 vs. Q1 2024

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. We 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

*(in thousands)*

| ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 | ​ ​ | ​ ​ 2024 |
| --- | --- | --- | --- | --- |
| Coal Sales | ​ | $54,774 | ​ | $66,036 |
| ​ | ​ | ​ ​ | ​ | ​ ​ |
| Fuel | ​ | $556 | ​ | $1,235 |
| Other Operating and Maintenance Costs | ​ | ​ 23,854 | ​ | ​ 31,791 |
| Utilities | ​ | ​ 3,476 | ​ | ​ 4,292 |
| Labor | ​ | ​ 18,886 | ​ | ​ 27,485 |
| General and Administrative | ​ | ​ 2,313 | ​ | ​ 2,438 |
| EBITDA Margin | ​ | ​ 5,689 | ​ | ​ (1,205) |
| Other Operating Revenue | ​ | ​ 1,324 | ​ | ​ 810 |
| Depreciation, Depletion and Amortization | ​ | ​ (9,797) | ​ | ​ (10,728) |
| Asset Retirement Obligations Accretion | ​ | ​ (307) | ​ | ​ (288) |
| Exploration Costs | ​ | ​ (21) | ​ | ​ (70) |
| Gain (loss) on disposal or abandonment of assets, net | ​ | ​ 21 | ​ | ​ — |
| Interest expense | ​ | ​ (1,991) | ​ | ​ (3,209) |
| **Income (Loss) before Income Taxes** | ​ | $(5,082) | ​ | $(14,690) |

| ​ ​ ​ ​ | ​ ​ ​ ​ | ​ ​ Three Months Ended March 31, 2025 (per ton) | ​ ​ | ​ ​ 2024 |
| --- | --- | --- | --- | --- |
| Tons Sold | ​ | **​** 1,071 |  | ​ 1,214 |
| ​ | ​ | **​** **​** | ​ | **​** **​** |
| Coal Sales | ​ | $51.14 | ​ | $54.40 |
| ​ | ​ | ​ ​ | ​ | ​ ​ |
| Fuel | ​ | $0.52 | ​ | $1.02 |
| Other Operating and Maintenance Costs | ​ | ​ 22.27 | ​ | ​ 26.19 |
| Utilities | ​ | ​ 3.25 | ​ | ​ 3.54 |
| Labor | ​ | ​ 17.63 | ​ | ​ 22.64 |
| General and Administrative | ​ | ​ 2.16 | ​ | ​ 2.01 |
| EBITDA Margin | ​ | ​ 5.31 | ​ | ​ (0.99) |
| Other Operating Revenue | ​ | ​ ​ | ​ | ​ ​ |
| Depreciation, Depletion and Amortization | ​ | ​ (9.15) | ​ | ​ (8.84) |
| Asset Retirement Obligations Accretion | ​ | ​ (0.29) | ​ | ​ (0.24) |
| Exploration Costs | ​ | ​ (0.02) | ​ | ​ (0.06) |
| Gain (loss) on disposal or abandonment of assets, net | ​ | ​ 0.02 | ​ | ​ — |
| Interest expense | ​ | ​ (1.86) | ​ | ​ (2.64) |
| **Income (Loss) before Income Taxes** | ​ | $(5.98) | ​ | $(12.77) |

27

### Q1 2025 vs. Q1 2024

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 $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):

| ​ All Mines | ​ | ​ ​ ​ 2nd 2024 | ​ ​ ​ 3rd 2024 | ​ ​ ​ 4th 2024 | ​ ​ ​ 1st 2025 | ​ ​ T4Qs | ​ |
| --- | --- | ---: | ---: | ---: | ---: | --- | --- |
| Tons produced |  | ​ 889 | ​ 873 | ​ 971 | ​ 1,020 | ​ 3,753 |  |
| Tons sold |  | ​ 849 | ​ 926 | ​ 875 | ​ 1,071 | ​ 3,721 |  |
| Wash plant recovery in % | ​ | 59% | 60% | 62% | 64% |  | ​ |
| Capex (Coal Operations) | ​ | $7,560 ​ | $6,810 ​ | $11,079 ​ | $6,244 ​ | $31,693 | ​ |
| Maintenance capex (Coal Operations) | ​ | $6,014 ​ | $4,208 ​ | $4,492 ​ | $4,000 ​ | $18,714 | ​ |
| Maintenance capex per ton sold (Coal Operations) | ​ | $7.08 ​ | $4.54 ​ | $5.13 ​ | $3.73 ​ | $5.03 | ​ |
| ​ | ​ | ​ ​ ​ | ​ ​ ​ | ​ ​ ​ | ​ ​ ​ | ​ ​ | ​ |
| Average cost per ton sold⁽ⁱ⁾ | ​ | $49.94 ​ | $52.22 ​ | $43.25 ​ | $43.65 ​ | ​ ​ | ​ |

| ​ All Mines | ​ | ​ ​ ​ 2nd 2023 | ​ ​ ​ 3rd 2023 | ​ ​ ​ 4th 2023 | ​ ​ ​ 1st 2024 | ​ ​ T4Qs | ​ |
| --- | --- | ---: | ---: | ---: | ---: | --- | --- |
| Tons produced |  | ​ 1,723 | ​ 1,594 | ​ 1,331 | ​ 1,271 | ​ 5,919 |  |
| Tons sold |  | ​ 1,714 | ​ 2,054 | ​ 1,461 | ​ 1,214 | ​ 6,443 |  |
| Wash plant recovery in % | ​ | 67% | 65% | 62% | 60% | ​ | ​ |
| Capex (Coal Operations) | ​ | $14,445 ​ | $11,570 ​ | $17,867 ​ | $8,632 ​ | $52,514 | ​ |
| Maintenance capex (Coal Operations) | ​ | $9,754 ​ | $7,938 ​ | $13,567 ​ | $8,085 ​ | $39,344 | ​ |
| Maintenance capex per ton (Coal Operations) | ​ | $5.69 ​ | $3.86 ​ | $9.29 ​ | $6.66 ​ | $6.11 | ​ |
| ​ | ​ | ​ ​ ​ | ​ ​ ​ | ​ ​ ​ | ​ ​ ​ | ​ ​ | ​ |
| Average cost per ton sold⁽ⁱ⁾ | ​ | $41.52 ​ | $46.54 ​ | $53.78 ​ | $51.65 ​ | ​ ​ | ​ |

(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

| ​ ​ | ​ | ​ ​ 2nd 2024 | ​ | ​ ​ 3rd 2024 | ​ | ​ ​ 4th 2024 | ​ | ​ ​ 1st 2025 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Basic | ​ | $(0.27) | ​ | $0.04 | ​ | $(5.06) | ​ | $0.23 |
| Diluted | ​ | $(0.27) | ​ | $0.04 | ​ | $(5.06) | ​ | $0.23 |

| ​ ​ | ​ | ​ ​ 2nd 2023 | ​ | ​ ​ 3rd 2023 | ​ | ​ ​ 4th 2023 | ​ | ​ ​ 1st 2024 |
| --- | --- | ---: | --- | ---: | --- | ---: | --- | ---: |
| Basic | ​ | $0.51 | ​ | $0.49 | ​ | $(0.31) | ​ | $(0.05) |
| Diluted | ​ | $0.47 | ​ | $0.44 | ​ | $(0.31) | ​ | $(0.05) |

### INCOME TAXES

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

### RESTRICTED STOCK GRANTS

See “*Item 1. Financial Statements - Note 9 - Stock Compensation Plans”* for a discussion of RSUs.

### CRITICAL ACCOUNTING ESTIMATES

We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, and the estimates used in impairment analysis are our critical accounting estimates.

The reserve estimates are used in the depreciation, depletion, and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal.

SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations.

Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds.

Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled.

We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant.

Inventory is valued at a lower of cost or net realizable value (NRV). Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of 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. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. Management evaluates assets for impairment through an established process in which changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants. The expected future cash flows used for impairment reviews and related fair value calculations are typically based on judgmental assessments of future volumes, commodity prices, operating costs and capital investment plans, considering all available information at the date of review. Changes to any of the market-based assumptions can significantly affect estimates of undiscounted and discounted pre-tax cash flows and impact the recognition and amount of impairments.

## Controls and procedures

As filed, 8,209 characters.

### DISCLOSURE CONTROLS

We maintain a system of disclosure controls and procedures that are designed for the purpose of ensuring that information required to be disclosed in our SEC reports is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and that such information is accumulated and communicated to our CEO and CFO and as appropriate to allow timely decisions regarding required disclosure.

As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our CEO and CFO of the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective.

There have been no changes to our internal control over financial reporting during the quarter ended March 31, 2025, that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

### FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” These statements are based on our beliefs as well as assumptions made by, and information currently available to us. When used in this document, the words “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “may,” “project,” “will,” and similar expressions identify forward-looking statements. Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings and sources of funding are forward-looking statements. These statements reflect our current views with respect to future events and are subject to numerous assumptions that we believe are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ from those in the forward-looking statements are:

- changes in macroeconomic and market conditions and market volatility, and the impact of such changes and volatility on our financial position;
- fluctuations in weather, gas and electricity commodity costs, inflation and economic conditions impact demand of our customers and our operating results;
- the outcome or escalation of current hostilities in Ukraine and Israel;
- changes in competition in electricity or coal markets and our ability to respond to such changes;
- changes in coal prices, demand, and availability which could affect our operating results and cash flows;
- risks associated with the expansion of our operations and properties;
- legislation, regulations, administrative actions (e.g., Executive Orders), and court decisions and interpretations thereof, including those relating to the environment and the release of greenhouse gases, mining, miner health and safety, and health care, as well as those relating to data privacy protection;
- deregulation of the electric utility industry or the effects of any adverse change in the coal industry, electric utility industry, or general economic conditions;
- dependence on significant or long-term customer contracts, including renewing customer contracts upon expiration of existing contracts;
- changing global economic conditions or the geopolitical environment in industries in which our customers operate;
- anticipated changes in the U.S. political environment, including those resulting from the change in Presidential Administration and control of Congress, and to regulatory agencies;
- changes in attitude toward environmental, social, and governance (“ESG”) matters among regulators, investors and parties with which we do business;
- the effect of changes in taxes or tariffs and other trade measures;
- risks relating to inflation and increasing interest rates;
- liquidity constraints, including due to restrictions contained in our indebtedness and those resulting from any future unavailability of financing;
- customer bankruptcies, a decline in customer creditworthiness, or customer cancellations or breaches to existing contracts, or other failures to perform;
- customer delays, failure to take coal under contracts or defaults in making payments;
- adjustments made in price, volume or terms to existing coal supply and customer agreements;
- our productivity levels and margins earned on our coal or electricity sales;
- supply chain disruptions and changes in equipment, raw material, service or labor costs or availability, including due to inflationary pressures;
- changes in the availability of skilled labor;
- our ability to maintain satisfactory relations with our employees;
- increases in labor costs, adverse changes in work rules, or cash payments or projections associated with workers’ compensation claims;
- increases in transportation costs and risk of transportation delays or interruptions;
- operational interruptions due to geologic, permitting, labor, weather-related or other factors;
- risks associated with major mine-related or other accidents, mine fires, mine floods or other interruptions, including unanticipated operating conditions and other events that are not within our control;
- results of litigation, including claims not yet asserted;
- difficulty maintaining our surety bonds for mine reclamation;
- decline in or change in the coal industry’s share of electricity generation, including as a result of environmental concerns related to coal mining and combustion and the cost and perceived benefits of other sources of electricity, such as natural gas, nuclear energy, and renewable fuels;
- risks resulting from climate change or natural disasters;
- difficulty in making accurate assumptions and projections regarding post-mine reclamation;
- uncertainties in estimating and replacing our coal reserves;
- the impact of current and potential changes to federal or state tax rules and regulations, including a loss or reduction of benefits from certain tax deductions and credits;
- difficulty obtaining commercial property insurance;
- evolving cybersecurity risks, such as those involving unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;
- difficulty in making accurate assumptions and projections regarding future revenues and costs associated with equity investments in companies we do not control;
- the severity, magnitude and duration of any future pandemics, including impacts of the pandemic and of businesses’ and governments’ responses to the pandemic on our operations and personnel, and on demand for coal, the financial condition of our customers and suppliers, available liquidity and capital sources and broader economic disruptions; and
- other factors, including those discussed in “*Item 1A. Risk Factors”* in our Annual Report on Form 10-K.

If one or more of these or other risks or uncertainties materialize, or should underlying assumptions prove incorrect, our actual results may differ materially from those described in any forward-looking statement. When considering forward-looking statements, you should also keep in mind the risk factors described in “*Item 1A. Risk Factors”* in our Annual Report on Form 10-K. The risk factors could also cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments, unless required by law.

You should consider the information above when reading any forward-looking statements contained in this Quarterly Report on Form 10-Q; other reports filed by us with the U.S. Securities and Exchange Commission (“SEC”); our press releases; our website ***www.halladorenergy.com*** and written or oral statements made by us or any of our officers or other authorized persons acting on our behalf.

Filed May 12, 2025.
Source: SEC EDGAR, the filing index for accession 0001558370-25-007429. Last ingested by Listed: Oct 24, 2026, 14:56 ET. No prices; not investment advice.