HALLADOR ENERGY CO 10-Q

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS THE FOLLOWING DISCUSSION UPDATES THE MD&A SECTION OF OUR 2024 ANNUAL REPORT ON FORM 10-K AND SHOULD BE READ IN CONJUNCTION THEREWITH. We are pleased with our favorable results in the third quarter, during which time we generated $146.8 million of revenue with $23.9 million of net income, representing substantial improvement over the $105.2 million of revenue with $1.6 million of net income generated in the prior year period. For the nine months ended September 30, 2025, we generated $367.5 million of revenue with $42.1 million of net income both materially above prior year performance. ​ Traditional summer weather patterns coupled with higher energy demand and higher natural gas prices provided for a supportive energy-pricing environment during the quarter that led to higher revenue at our Hallador Power subsidiary. Following the completion of Unit 2’s annual maintenance outage in early July 2025, both units operated very well throughout the quarter. We also saw positive results in our Coal Operations resulting from solid coal production, increased shipments and consistent operating costs. The favorable power markets led to increased dispatch levels at both Merom and customer plants, which provided a boost to coal shipments and helped to decrease coal inventories at both the power plant and the mine. ​ During the third quarter 2025 , the Company entered into a $20.0 million prepaid forward power sales contract with scheduled deliveries throughout the first half of 2027. As we have previously noted, these firm forward sales allow us to improve liquidity from lower future price environments and also provides an advantage, as we saw in this instance, when pricing is stronger. These prepaid sales help us to lock in prices in the near term as we continue to focus on securing a long-term power purchase agreement in support of utility, data center and/or other large scale industrial development. The prepaid funds will be used to support company operations and capital expenditures. ​ We continue to see significant and accelerating interest in our capacity and energy offerings. As the third quarter progressed, we saw increased activity from both data center developers and load serving entities seeking the scarce inventory of large blocks of capacity and energy that we have available in the coming decade. We are in advanced discussions on both fronts and anticipate making positive progress towards a long-term agreement with a data center developer or load serving entity by early 2026. Each of the interested parties brings a unique perspective to the negotiations and each presents differentiated value creation opportunities and challenges to effectively monetize our capacity and energy offerings. We continue to believe that the evolving energy markets, specifically related to data center growth and favorable load serving entity demand, as well as the newly supportive regulatory environment, are providing us with opportunities that were not available when we began the request for proposal process. We also recognize that these opportunities have an undefined lifespan and we continue to work diligently to secure an agreement that will benefit the Company and our shareholders, both now and in the future. ​ While we still believe that an agreement with a load serving entity is intrinsically more straightforward to negotiate, can be implemented sooner and could result in greater sales volumes of energy and accredited capacity, we are beginning to see improving timelines on the developer side, especially where the developers had the foresight to speculatively acquire required infrastructure, such as step-down transformers, switch gear and other site-specific level electrical equipment. We anticipate favorable pricing in these potential opportunities, but, as we have highlighted before, data center arrangements are inherently more complex and involve multiple parties, which by its nature adds time and alignment challenges to the negotiation process. Notwithstanding those challenges, returning to non-exclusive negotiations reinforced our belief that we will forge a strategic partnership and create significant value for years to come. ​ Throughout the past several years, we have expressed our strong belief that the prevailing industry trend of retiring dispatchable generators in favor of non-dispatchable resources, such as wind and solar, will create and has created an unbalanced supply and demand equation, resulting in reduced availability and increased price of accredited capacity. It is our position that the enhanced reliability of dispatchable generation, like Merom, versus non-dispatchable generators will increase the value of the attributes of Hallador Power in the overall energy markets. With this in mind, we continue to evaluate the potential to enhance value through strategic growth initiatives such as the acquisition of retiring or retired generation assets and infrastructure. We are regularly evaluating potential acquisition opportunities to diversify and 21 Table of Contents increase our dispatchable generation as well as other strategic opportunities, which we believe would inherently diversify our generation portfolio, and provide an avenue to realize future growth opportunities. We believe that this approach has the potential to enhance our financial flexibility and strengthen our position in the evolving energy market. ​ We remain optimistic about the potential to add to our strategic generation portfolio and the long-term benefits that such a transaction could produce for the company, its shareholders and its customers. This model for growth enables us to capture value by providing accredited capacity and reliable energy. In connection with this belief, on November 3, 2025, Hallador Power submitted an application to MISO’s Expedited Resource Addition Study (ERAS) program to add an additional 525 MW of gas generation at the Merom site. Given the strong market signals that we are currently seeing for our product offerings and the robust interest in the types of long-term arrangements that we are currently evaluating, we believe that it is an appropriate time to explore increasing generation at Merom. While the application is only a first step in our growth process and does not guarantee that we will be able to add the full load which we applied for, or any additional generation as part of ERAS, we are excited to participate in the opportunity and for what it could mean to the future of Hallador. We are currently targeting the generation to come online late in 2028. The process is capital intensive and includes operational, financial, regulatory and legal risks that could impact the project’s viability and/or timeline. ​ Additionally, we see the potential of enhancing Merom’s reliability, resiliency and flexibility by incorporating natural gas and creating a dual fuel configuration should operational and financial conditions support it. While we remain in the evaluation process, by adding the capability to co-fire with gas or coal, we believe that it could provide Hallador Power and its customers the ability to take advantage of economic fluctuations in fuel cost and provide potential flexibility as we manage other operating expenses. We believe that the ability to co-fire with natural gas and coal will also provide increased resiliency in times where gas availability is limited and allow us to retain the economic advantages of operating our Sunrise Coal subsidiary and leveraging our own fuel supply to ensure competitively priced offerings from third party fuel providers. This evaluation is complex on a variety of levels, specifically customer preference and an evolving regulatory environment, each of which could materially impact the timing and economic benefits of undertaking such a change. ​ In 2024, we delivered 2.9 million MWh of energy during the first nine months at an average sales price of $50.97 per MWh. In 2025, we delivered 4.0 million MWh of energy during the first nine months at an average sales price of $48.88. As illustrated in the forward sales position table, below, following 2026, we are optimistic that we will be able to sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a strong forward energy pricing curve. ​ Shifting to our Coal Operations, during the quarter, we saw improvements in operational expenses and increased shipments. The improved dispatch levels at Merom and our customers’ plants helped to reduce our previously elevated inventories, while still allowing us adequate fuel inventory to position us well to meet industry needs if power plants, including Merom, dispatch at higher levels over the course of the upcoming Winter season. ​ With renewed support of coal mining and coal fired generation on both the federal and state level, we believe that we are well-positioned to take advantage of opportunities for strategic growth and/or organic expansion. We believe that current market dynamics remain stronger than they were in the past year, and we are actively assessing the timing and feasibility of expanding coal production in 2026. As we have previously said, our average contracted sales price in 2026 across all coal sales contracts is approximately $4.00 per ton higher than the average contracted sales price in 2025. ​ We currently expect to produce approximately 3.8 million tons of coal in 2025. In the first three quarters of 2025, we produced 3.1 million tons of coal at our Oaktown Mining Complex. We also use supplemental coal from third party suppliers at Merom, typically purchased at favorable prices to help diversify self-production supply risk and to provide us with additional flexibility in our ability to rapidly respond to customer demand if spot market pricing justifies doing so. This optionality to obtain low-cost fuel either internally or from third-parties while capturing upward swings in the commodity markets for coal should allow us to further maximize margins while optimizing fuel costs at Merom. ​ The continued transformation of Hallador from a commodity focused producer of coal to a vertically integrated IPP remains our primary focus. This allows us to leverage the ongoing impacts of the energy transition to capture the 22 Table of Contents expanding margins of the energy markets and capitalize on the rising demand for reliable electricity. As described above, we continue to see very strong interest from data center developers and load serving entities with respect to our energy and accredited capacity offerings. This interest and the number of inquiries accelerated throughout the quarter and we are encouraged by the variety of interested parties and the varied deal structures that we are seeing with respect to our offerings. We continue to believe that our business is well positioned to take advantage of opportunities for growth and cash flow generation as they arise. ​ Like our competitors, Hallador’s business is affected by various macroeconomic factors, including tariffs and inflationary trends. The U.S. has implemented, or is considering implementing, higher tariffs on imports into the U.S. While such tariffs could potentially result in reduced economic activity, increased costs in operating our business including potential supply chain disruptions, and changes in purchasing behaviors for thermal coal or other potentially adverse economic outcomes, tariffs (or retaliatory trade measures imposed by other countries on U.S. goods) have not yet had a significant impact on our business or results of operations. ​ Our goal is for Hallador Power to generate up to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below), if the markets and energy pricing support that level of generation. During the first nine months of the year, Hallador Power generated approximately 3.7 million MWh, or roughly 82.0% of our year-to-date target and economically purchased 0.3 million MWh. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ 2025 2024 2025 2024 Power Capacity and Utilization ​ Nameplate capacity (MW) (i) 1,080 1,080 1,080 1,080 ​ Accredited capacity for the period (MW) (ii) 748 828 821 858 ​ Accredited capacity utilization (iii) 93 % 59 % 69 % 47 % ​ (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 $58.1 million or 89.4% of our target. We believe our forward Capacity sales goals are attainable as illustrated in our “Forward Sales Position” table below. Our condensed consolidated financial statements should be read in conjunction with this discussion. This analysis includes a discussion of metrics on a per mega-watt hour (MWh) and a per ton basis as derived from the condensed consolidated financial statements, which are considered non-GAAP measurements. These metrics are significant factors in assessing our operating results and profitability. OVERVIEW The following is an overview our Electric Operations and Coal Operations results for Q3 2025 compared to Q2 2025. I. Q3 2025 Net Income of $23.9 million. a. Electric Operations: 23 Table of Contents i. In Q3 2025, Total Electric Sales were $93.2 million, or $59.09 per MWh sold, an increase of $33.2 million or 55.3% from Q2 2025. ii. In Q3 2025, Total Electric Operations expenses on a segment basis were $75.2 million or $47.64 per MWh sold an increase of $23.7 million or 46.0% from Q2 2025. iii. Q3 2025 Electric Operations net income was $18.3 million an increase of $6.7 million or 57.8% from Q2 2025. Key drivers in Q3 2025 Electric Operations results were: (1) During the third quarter of 2025, we sold 1.6 million MWh representing a 100.0% increase in total MWh sold from the second quarter of 2025. This increase was expected as Q2 2025 typically has lower demand for power and we had a planned maintenance outage on one of our units at Merom for approximately two months during the second quarter. On a per MWh basis, Q3 Electrics Sales were $59.09 per MWh sold compared to $72.44 per MWh sold in Q2 2025. The variance on a per MWh basis was primarily due to the allocation of capacity revenue over increased energy volumes. (2) In Q3 2025, significant operating costs including fuel, other operating and maintenance and cost of purchased power were $56.2 million, or $35.61 per MWh compared to $34.2 million, or $41.31 per MWh in Q2 2025. The increase in costs reflect the higher plant output and planned maintenance as also reflected in the decreased cost per MWh from Q2. (3) Q3 2025 Electric Operations income before income taxes was $18.3 million or $11.57 per MWh, an increase of $6.7 million and a decrease of $2.42 per MWh from Q2 2025. b. Coal Operations: i. In Q3 2025, Total Coal Sales on a segment basis were $68.8 million, or $50.79 per ton sold, an increase of $23.3 million or 51.2% from Q2 2025. ii. In Q3 2025, Total Coal Operations Expenses on a segment basis were $66.7 million, or $49.20 per ton sold, an increase of $21.1 million or 46.3% from Q2 2025. iii. Q3 2025 Coal Operations Net Income on a segment basis was $6.1 million an increase of 335.7% from Q2 2025. Key drivers in Q3 2025 Coal Operations results were: (1) In Q3 2025, tons sold were 1.4 million tons on a segment basis at an average price per ton of $50.79, with approximately 0.3 million tons of that being shipped to Merom for $17.6 million compared to 0.9 million tons sold in Q2 2025 at an average price of $51.16, with approximately 0.1 million tons of that being shipped to Merom for $7.4 million. This increase was expected as Q2 is the shoulder season and typically has lower demand for coal at both Merom and third-party customers. (2) In Q3 2025, Other operating and maintenance costs were $35.0 million, or $25.86 per ton, compared to $18.2 million, or $20.50 per ton, on a segment basis, in Q2 2025. This increase is mainly attributable to an increase of sales related royalties of $3.0 million and an increase of $14.9 million in coal cost of sales directly related to the increase in sales. (3) Q3 2025 Coal Operations income before income taxes was $6.1 million or $4.53 per ton on a segment basis. This is an increase of $4.7 million or $2.95 per ton from Q2 2025. 24 Table of Contents II. Forward Sales Position (unaudited)* ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Q4 2025 2026 2027 2028 2029 Total Power ​ ​ ​ ​ ​ ​ Energy ​ ​ ​ ​ ​ ​ Contracted MWh (in millions) ​ 1.15 ​ 4.00 ​ 2.31 ​ 1.09 ​ 0.27 ​ 8.82 Average contracted price per MWh ​ $ 38.07 ​ $ 43.09 ​ $ 50.78 ​ $ 52.94 ​ $ 51.33 ​ ​ Contracted revenue (in millions) ​ $ 43.78 ​ $ 172.36 ​ $ 117.30 ​ $ 57.70 ​ $ 13.86 ​ $ 405.00 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capacity ​ ​ ​ ​ ​ ​ Average daily contracted capacity MW ​ 668 ​ 733 ​ 623 ​ 454 ​ 100 ​ ​ Average contracted capacity price per MWd ​ $ 211 ​ $ 230 ​ $ 226 ​ $ 225 ​ $ 230 ​ ​ Contracted capacity revenue (in millions) ​ $ 12.98 ​ $ 61.54 ​ $ 51.40 ​ $ 37.33 ​ $ 3.47 ​ $ 166.72 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Energy & Capacity Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Contracted Power revenue (in millions) ​ $ 56.76 ​ $ 233.90 ​ $ 168.70 ​ $ 95.03 ​ $ 17.33 ​ $ 571.72 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal ​ ​ ​ ​ ​ ​ Priced tons - 3rd party (in millions) ​ 0.51 ​ 2.72 ​ 2.50 ​ 0.50 ​ — ​ 6.23 Avg price per ton - 3rd party ​ $ 53.08 ​ $ 55.72 ​ $ 56.74 ​ $ 59.00 ​ $ — ​ ​ Contracted coal revenue - 3rd party (in millions) ​ $ 27.07 ​ $ 151.56 ​ $ 141.85 ​ $ 29.50 ​ $ — ​ $ 349.98 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED ​ $ 83.83 ​ $ 385.46 ​ $ 310.55 ​ $ 124.53 ​ $ 17.33 ​ $ 921.70 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Priced tons - Intercompany (in millions) ​ 1.33 ​ 2.30 ​ 2.30 ​ 2.30 ​ — ​ 8.23 Avg price per ton - Intercompany ​ $ 51.00 ​ $ 51.00 ​ $ 51.00 ​ $ 51.00 ​ $ — ​ ​ Contracted coal revenue - Intercompany (in millions) ​ $ 67.83 ​ $ 117.30 ​ $ 117.30 ​ $ 117.30 ​ $ — ​ $ 419.73 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT ​ $ 151.66 ​ $ 502.76 ​ $ 427.85 ​ $ 241.83 ​ $ 17.33 ​ $ 1,341.43 ​ * Actual revenue related to forward sales positions may differ materially for various reasons, including price adjustment features for coal quality and cost escalations, volume optionality provisions and potential force majeure events. ​ 25 Table of Contents 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 $73.0 million and $27.0 million for the nine months ended September 30, 2025 and 2024, respectively. b. On a net basis, bank debt did not change during the nine months ended September 30, 2025. As of September 30, 2025, our bank debt was $44.0 million. c. We expect cash generated from operations to primarily fund our capital expenditures and our debt service. As of September 30, 2025, we also had an additional borrowing capacity of $33.8 million. d. Total liquidity as of September 30, 2025 was $46.4 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 $17.7 million, including $6.1 million at Merom, presented as asset retirement obligations (“ARO”) and “accounts payable and accrued liabilities” in our accompanying condensed consolidated balance sheets. In the event we are not able to perform reclamation, we have surety bonds in place totaling $30.9 million to cover ARO. CAPITAL EXPENDITURES (“Capex”) For the nine months ended September 30, 2025, capex was $44.3 million allocated as follows (in millions): ​ ​ ​ ​ ​ Oaktown – maintenance capex $ 11.5 Oaktown – investment ​ 7.4 Merom Plant ​ 25.4 Capex per the Condensed Consolidated Statements of Cash Flows ​ $ 44.3 ​ 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. ​ ​ 26 Table of Contents Electric Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (in thousands) ​ (in thousands) Delivered Energy $ 77,776 ​ $ 56,256 ​ $ 194,044 ​ $ 148,490 Capacity Revenue ​ ​ 15,459 ​ ​ 15,860 ​ ​ 45,110 ​ ​ 44,506 Electric Sales ​ $ 93,235 ​ $ 72,116 ​ $ 239,154 ​ $ 192,996 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (44,751) ​ $ (30,181) ​ $ (104,150) ​ $ (79,532) Other Operating Costs (1) ​ ​ (1) ​ ​ (36) ​ ​ (10) ​ ​ (22) Other Operating and Maintenance Costs (2) ​ ​ (9,368) ​ ​ (5,561) ​ ​ (24,602) ​ ​ (22,926) Cost of Purchased Power ​ ​ (2,074) ​ ​ (3,149) ​ ​ (11,086) ​ ​ (7,694) Utilities ​ ​ (1,873) ​ ​ (492) ​ ​ (3,932) ​ ​ (1,451) Labor ​ ​ (7,949) ​ ​ (7,360) ​ ​ (23,731) ​ ​ (22,203) General and Administrative ​ ​ (1,308) ​ ​ (1,252) ​ ​ (3,972) ​ ​ (3,760) EBITDA Margin ​ ​ 25,911 ​ ​ 24,085 ​ ​ 67,671 ​ ​ 55,408 Other Operating Revenue ​ ​ 192 ​ ​ 187 ​ ​ 3,413 ​ ​ 518 Depreciation, Depletion and Amortization ​ ​ (5,131) ​ ​ (4,802) ​ ​ (15,456) ​ ​ (14,197) Asset Retirement Obligations Accretion ​ ​ (126) ​ ​ (115) ​ ​ (369) ​ ​ (339) Interest expense ​ ​ (2,585) ​ ​ (181) ​ ​ (6,208) ​ ​ (515) Income before Income Taxes ​ $ 18,261 ​ $ 19,174 ​ $ 49,051 ​ $ 40,875 ​ (1) Other operating costs include costs for limestone, dibasic acid, ammonia, lime dust and soda ash. (2) Other operating and maintenance costs include all other operating and maintenance costs with the exceptions of those costs considered variable as discussed above in (1). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (per MWh) ​ (per MWh) MWh Generated (in thousands) ​ ​ 1,530 ​ ​ 1,074 ​ ​ 3,706 ​ ​ 2,670 MWh Purchased (in thousands) ​ ​ 48 ​ ​ 109 ​ ​ 264 ​ ​ 243 MWh Sold (in thousands) ​ ​ 1,578 ​ ​ 1,183 ​ ​ 3,970 ​ ​ 2,913 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delivered Energy $ 49.29 ​ $ 47.55 ​ $ 48.88 ​ $ 50.97 Capacity Revenue ​ ​ 9.80 ​ ​ 13.41 ​ ​ 11.36 ​ ​ 15.28 Electric Sales ​ $ 59.09 ​ $ 60.96 ​ $ 60.24 ​ $ 66.25 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (28.36) ​ $ (25.51) ​ $ (26.23) ​ $ (27.30) Other Operating Costs (1) ​ ​ — ​ ​ (0.03) ​ ​ — ​ ​ (0.01) Other Operating and Maintenance Costs (2) ​ ​ (5.94) ​ ​ (4.70) ​ ​ (6.20) ​ ​ (7.87) Cost of Purchased Power ​ ​ (1.31) ​ ​ (2.66) ​ ​ (2.79) ​ ​ (2.64) Utilities ​ ​ (1.19) ​ ​ (0.42) ​ ​ (0.99) ​ ​ (0.50) Labor ​ ​ (5.04) ​ ​ (6.22) ​ ​ (5.98) ​ ​ (7.62) General and Administrative ​ ​ (0.83) ​ ​ (1.06) ​ ​ (1.00) ​ ​ (1.29) EBITDA Margin ​ ​ 16.42 ​ ​ 20.36 ​ ​ 17.05 ​ ​ 19.02 Other Operating Revenue ​ ​ 0.12 ​ ​ 0.16 ​ ​ 0.86 ​ ​ 0.18 Depreciation, Depletion and Amortization ​ ​ (3.25) ​ ​ (4.06) ​ ​ (3.89) ​ ​ (4.87) Asset Retirement Obligations Accretion ​ ​ (0.08) ​ ​ (0.10) ​ ​ (0.09) ​ ​ (0.12) Interest expense ​ ​ (1.64) ​ ​ (0.15) ​ ​ (1.56) ​ ​ (0.18) Income before Income Taxes ​ $ 11.57 ​ $ 16.21 ​ $ 12.37 ​ $ 14.03 ​ (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). ​ 27 Table of Contents Q3 2025 vs. Q3 2024 i. In Q3 2025, Total Electric Sales were $93.2 million or $59.09 per MWh sold compared to $72.1 million or $60.96 per MWh sold for Q3 2024, an increase of $21.1 million or 29.3%. ii. In Q3 2025, Total Electric Operations expenses on a segment basis were $75.2 million or $47.64 per MWh compared to $53.1 million or $44.91 per MWh in Q3 2024, an increase of $22.1 million or 41.6%. iii. Q3 2025 Electric Operations income before income taxes was $18.3 million or $11.57 per MWh compared to $19.2 million or $16.21 per MWh in Q3 2024, a decrease of $0.9 million or $4.64 per MWh or 28.6%. Key drivers in Electric Operations Q3 results were: (1) Delivered Energy revenue increased $21.5 million, or 38.3%, and $1.74 per MWh from the same period in the prior year. During 2025, (i) we sold 0.4 million more MWh of Delivered Energy, or 33.4%, (ii) we began delivery on two additional PPA contracts resulting in a $14.4 million increase, or 41.7%, (iii) MISO pricing during the quarter was in excess of 2024 prices, with July 2025 average price of $55.37 per MWh compared to $33.54 per MWh in July of 2024 and (iv) we sold 0.3 million MWh during the quarter to MISO at these elevated prices compared to 0.1 million in Q3 2024. (2) Capacity Revenues were $15.5 million or $9.80 per MWh sold for Q3 2025 and $15.9 million or $13.41 per MWh sold for Q3 2024. Capacity revenues are not impacted by the MWh generated at the plant therefore the price per MWh sold decreased due to the allocation of revenue over increased energy volumes. (3) Fuel costs increased $14.6 million, or 48.3%, compared to the third quarter of 2024. On a per MWh basis, fuel costs increased $2.85, or 11.2%. This change was due to increased energy production as noted above resulting in 0.2 million tons, or 37.5%, more tons of coal used. The average purchase price per ton of coal used in the plant on a segment basis, was $54.22 in the third quarter of 2025 up from $53.33 per ton in the third quarter of 2024. We also made an adjustment to coal inventory during the third quarter of 2025 as part of the Company’s routine inventory reconciliation process resulting in an increase in fuel costs of $2.6 million. (4) Other operating and maintenance costs increased $3.8 million, or 68.5%, and increased $1.24, or 26.4%, on a MWh basis. These increases were due to $3.4 million in additional planned maintenance costs compared to 2024. (5) Electric interest expense increased $2.4 million, or 1328.2%, compared to the third quarter of 2024. On a per MWh basis, interest expense increased $1.49, or 993.3%. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024, June 2025 and September 2025. (6) Income before income taxes decreased $0.9 million, or 4.8%, compared to the third quarter of 2024. The main drivers of this change in income before income taxes are described in the discussion above. YTD 2025 vs. YTD 2024 i. Total Electric Sales for YTD 2025 were $239.2 million or $60.24 per MWh compared to $193.0 million or $66.25 per MWh YTD 2024, an increase of $46.2 million or 23.9%. ii. Total Electric Operations expenses on a segment basis YTD 2025 were $193.5 million or $48.73 per MWh compared to $152.6 million or $52.40 per MWh YTD 2024 an increase of $40.9 million or 26.8% iii. Electric Operations income before income taxes for YTD 2025 was $49.1 million or $12.37 per MWh compared to $40.9 million or $14.03 per MWh for YTD 2024 an increase of $8.2 million or 20.0%. 28 Table of Contents Key drivers in Electric Operations YTD results were: (1) Delivered energy increased $45.6 million, or 30.7%, compared to the first nine months of 2024. During 2025, (i) we began delivery on two additional PPA contracts resulting in a $44.3 million, or 63.4%, increase in revenue compared to 2024, (ii) we increased Delivered Energy MWh sold by 1.1 million, or 36.3%, and (iii) the average MISO price for 2025 of $41.83 per MWh is above the average 2024 price of $30.91, or an increase of 35.3%. (2) Fuel increased $24.6 million, or 31.0%, compared to the first nine months of 2024. The increase in fuel costs were directly related to the increase in MWh generated, requiring the increased use of fuel by 0.4 million tons of coal, or 30.1%. On a per MWh basis, fuel decreased $1.07, or 3.9%, at an average cost of $53.88 per ton for 2025 compared to an average cost of $54.83 per ton for 2024. We also made an adjustment to coal inventory during the third quarter of 2025 as a part of the Company’s routine inventory reconciliation process resulting in an increase in fuel costs of $2.6 million. (3) The cost of purchased power increased $3.4 million, or 44.1%, compared to year-to-date 2024. When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market, which we record as cost of purchased power. (4) Utilities increased $2.5 million, or 171.0%, compared to the first nine months of 2024. This change was due to increased production at the Merom Plant described above as well as a change in meters for auxiliary power. (5) Other operating revenue increased $2.9 million, or 558.9%, compared to the first nine months of 2024. On a per MWh basis, other operating revenues increased $0.68, or 377.8%. These changes were due to revenue received related to contractual negotiations on the former exclusivity agreement. (6) Electric interest expense increased $5.7 million, or 1105.4%, compared to the first nine months of 2024. On a per MWh basis, interest expense increased $1.38, or 766.7%. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024, June 2025 and September 2025. (7) Income before income taxes increased $8.2 million, or 20.0%, compared to the first nine months of 2024. The main drivers of this change in income before income taxes are described in the discussion above. 29 Table of Contents Coal Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (in thousands) ​ (in thousands) Coal Sales ​ $ 68,814 ​ $ 48,320 ​ $ 169,117 ​ $ 160,066 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (574) ​ $ (572) ​ $ (1,564) ​ $ (2,557) Other Operating and Maintenance Costs ​ ​ (35,046) ​ ​ (27,031) ​ ​ (77,147) ​ ​ (80,419) Utilities ​ ​ (2,670) ​ ​ (3,094) ​ ​ (9,270) ​ ​ (10,639) Labor ​ ​ (19,625) ​ ​ (19,361) ​ ​ (57,671) ​ ​ (66,241) General and Administrative ​ ​ (2,062) ​ ​ (2,082) ​ ​ (6,290) ​ ​ (8,012) EBITDA Margin ​ ​ 8,837 ​ ​ (3,820) ​ ​ 17,175 ​ ​ (7,802) Other Operating Revenue ​ ​ 1,647 ​ ​ 721 ​ ​ 4,370 ​ ​ 2,028 Depreciation, Depletion and Amortization ​ ​ (3,992) ​ ​ (9,013) ​ ​ (14,148) ​ ​ (28,671) Asset Retirement Obligations Accretion ​ ​ (320) ​ ​ (295) ​ ​ (941) ​ ​ (869) Exploration Costs ​ ​ (38) ​ ​ (62) ​ ​ (157) ​ ​ (179) Gain on disposal or abandonment of assets, net ​ ​ 2,334 ​ ​ 290 ​ ​ 2,410 ​ ​ 536 Interest expense ​ ​ (2,342) ​ ​ (2,511) ​ ​ (6,261) ​ ​ (8,908) Income (Loss) before Income Taxes ​ $ 6,126 ​ $ (14,690) ​ $ 2,448 ​ $ (43,865) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended September 30, ​ Nine Months Ended September 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (per ton) ​ (in thousands) Tons Sold ​ ​ 1,355 ​ 926 ​ ​ 3,316 ​ ​ 2,989 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal Sales ​ $ 50.79 ​ $ 52.18 ​ $ 51.00 ​ $ 53.55 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (0.42) ​ $ (0.62) ​ $ (0.47) ​ $ (0.86) Other Operating and Maintenance Costs ​ ​ (25.86) ​ ​ (29.19) ​ ​ (23.27) ​ ​ (26.90) Utilities ​ ​ (1.97) ​ ​ (3.34) ​ ​ (2.80) ​ ​ (3.56) Labor ​ ​ (14.48) ​ ​ (20.91) ​ ​ (17.39) ​ ​ (22.16) General and Administrative ​ ​ (1.52) ​ ​ (2.25) ​ ​ (1.90) ​ ​ (2.68) EBITDA Margin ​ ​ 6.54 ​ ​ (4.13) ​ ​ 5.17 ​ ​ (2.61) Other Operating Revenue ​ ​ 1.22 ​ ​ 0.78 ​ ​ 1.32 ​ ​ 0.68 Depreciation, Depletion and Amortization ​ ​ (2.95) ​ ​ (9.73) ​ ​ (4.27) ​ ​ (9.59) Asset Retirement Obligations Accretion ​ ​ (0.24) ​ ​ (0.32) ​ ​ (0.28) ​ ​ (0.29) Exploration Costs ​ ​ (0.03) ​ ​ (0.07) ​ ​ (0.05) ​ ​ (0.06) Gain on disposal or abandonment of assets, net ​ ​ 1.72 ​ ​ 0.31 ​ ​ 0.73 ​ ​ 0.18 Interest expense ​ ​ (1.73) ​ ​ (2.71) ​ ​ (1.89) ​ ​ (2.98) Income (Loss) before Income Taxes ​ $ 4.53 ​ $ (15.87) ​ $ 0.73 ​ $ (14.67) ​ Q3 2025 vs. Q3 2024 i. In Q3 2025, Total Coal Sales on a segment basis were $68.8 million, or $50.79 per ton sold compared to $48.3 million or $52.18 per ton from Q3 2024, an increase of $20.5 million or 42.4%. ii. In Q3 2025, Total Coal Operations Expenses on a segment basis were $66.7 million, or $49.20 per ton sold, compared to $64.0 million or $69.14 per ton from Q3 2024, an increase of $2.7 million or 4.2%. iii. Q3 2025 Coal Operations Net Income on a segment basis was $6.1 million compared to a net loss of $14.7 million in Q3 2024, an increase of $20.8 million or 141.7%. ​ 30 Table of Contents Key drivers in Q3 2025 Coal Operations results were: (1) Coal sales increased $20.5 million, or 42.4%, compared to the third quarter of 2024. On a per ton basis, coal sales decreased $1.39, or 2.7%. These changes were primarily due to increased third-party contractual coal sales of 0.4 million tons during the period, partially offset by a decrease in coal prices per ton of $1.39. (2) Other operating and maintenance costs increased $8.0 million, or 29.7%, compared to the third quarter of 2024. On a per ton basis other operating and maintenance costs decreased $3.33, or 11.4%. These changes were the result of a $2.6 million increase in sales related royalties, an increase of $8.4 million related to coal cost of sales, $1.0 million decrease in group health insurance costs and a $1.0 million decrease in maintenance costs. (3) Depreciation, depletion and amortization decreased $5.0 million, or 55.7%, compared to the third quarter of 2024. On a per ton basis, depreciation, depletion and amortization decreased $6.78, or 69.7%. This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million. (4) Gain on disposal or abandonment of assets, net, increased $2.0 million, or 704.8%, and $1.41, or 454.8%, on a per ton basis compared to the third quarter of 2024. This change was due to the sale of land during the third quarter of 2025. (5) Income before income taxes increased $20.8 million, or 141.7%, compared to the third quarter of 2024. The main drivers of this change in income before income taxes are described in the discussion above. YTD 2025 vs. YTD 2024 i. Total Coal Sales on a segment basis YTD 2025 were $169.1 million or $51.00 per ton compared to $160.1 million or $53.55 per ton YTD 2024, an increase of $9.1 million or 5.7%. ii. Total Coal Operations expenses YTD 2025 were $173.4 million or $52.31 per ton $206.5 million or $69.08 per ton for YTD 2024, a decrease of $33.1 million or 16.0%. iii. Income before income taxes YTD 2025 was $2.4 million or $.74 per ton compared to a loss of $43.9 million or $14.68 per ton YTD 2024, an increase of $46.3 million or 105.6%. Key drivers in YTD 2025 Coal Operations results were: (1) Labor decreased $8.6 million, or 12.9%, compared to the first nine months of 2024. On a per ton basis, labor decreased $4.77, or 21.5%. This change was the result of the organizational restructuring that occurred in February 2024 which reduced the Coal Operations headcount to 626 as of September 30, 2025 from 924 prior to the restructuring. (2) Other operating revenue increased $2.3 million, or 115.5%, compared to the first nine months of 2024. On a per ton basis, other operating revenue increased $0.64, or 94.1%. This change was the result of increased utilization of our rail facility by a customer resulting in an increase in transloading fee revenue. (3) Depreciation, depletion and amortization costs decreased $14.5 million, or 50.7%, compared to the first nine months of 2024. On a per ton basis, depreciation, depletion and amortization decreased $5.32, or 55.5%. This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million. (4) Interest expense decreased $2.6 million, or 29.7%, compared to the first nine months of 2024. Interest expense on a per ton basis decreased $1.09, or 36.6%. Our decreased interest expense primarily relates to reductions of convertible debt of $11.0 million and related party debt of $5.0 million. (5) Income before income taxes increased $46.3 million, or 105.6%, compared to the first nine months of 2024. The main drivers of this change in loss before income taxes are described in the discussion above. 31 Table of Contents 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 4th 2024 1st 2025 2nd 2025 3rd 2025 T4Qs Tons produced ​ 971 ​ 1,020 ​ 1,059 ​ 1,034 ​ 4,084 Tons sold ​ 875 ​ 1,071 ​ 890 ​ 1,355 ​ 4,191 Wash plant recovery in % ​ 62 % 64 % 66 % 64 % Capex (Coal Operations) ​ $ 11,079 ​ $ 6,244 ​ $ 5,793 ​ $ 6,873 ​ $ 29,989 Maintenance capex (Coal Operations) ​ $ 4,492 ​ $ 4,000 ​ $ 3,691 ​ $ 3,846 ​ $ 16,029 Maintenance capex per ton sold (Coal Operations) ​ $ 5.13 ​ $ 3.73 ​ $ 4.15 ​ $ 2.84 ​ $ 3.82 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 43.25 ​ $ 43.65 ​ $ 46.03 ​ $ 42.74 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ All Mines 4th 2023 1st 2024 2nd 2024 3rd 2024 T4Qs Tons produced ​ 1,331 ​ 1,271 ​ 889 ​ 873 ​ 4,364 Tons sold ​ 1,461 ​ 1,214 ​ 849 ​ 926 ​ 4,450 Wash plant recovery in % ​ 62 % 60 % 59 % 60 % ​ Capex (Coal Operations) ​ $ 17,867 ​ $ 8,632 ​ $ 7,560 ​ $ 6,810 ​ $ 40,869 Maintenance capex (Coal Operations) ​ $ 13,567 ​ $ 8,085 ​ $ 6,014 ​ $ 4,208 ​ $ 31,874 Maintenance capex per ton (Coal Operations) ​ $ 9.29 ​ $ 6.66 ​ $ 7.08 ​ $ 4.54 ​ $ 7.16 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 53.78 ​ $ 51.65 ​ $ 49.94 ​ $ 52.22 ​ ​ ​ ​ (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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 4th 2024 1st 2025 2nd 2025 3rd 2025 Basic ​ $ (5.06) ​ $ 0.23 ​ $ 0.19 ​ $ 0.56 Diluted ​ $ (5.06) ​ $ 0.23 ​ $ 0.19 ​ $ 0.55 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 4th 2023 1st 2024 2nd 2024 3rd 2024 Basic ​ $ (0.31) ​ $ (0.05) ​ $ (0.27) ​ $ 0.04 Diluted ​ $ (0.31) ​ $ (0.05) ​ $ (0.27) ​ $ 0.04 ​ INCOME TAXES Our effective tax rate (ETR) is estimated at ~0% and ~24% for the nine months ended September 30, 2025 and 2024, respectively. For the nine months ended September 30, 2025, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. 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. 32 Table of Contents CRITICAL ACCOUNTING ESTIMATES We believe that the estimates of coal reserves, asset retirement obligation liabilities, deferred tax accounts, valuation of inventory, and the estimates used in impairment analysis are our critical accounting estimates. The reserve estimates are used in the depreciation, depletion, and amortization calculations and our internal cash flow projections. If these estimates turn out to be materially under or over-stated, our depreciation, depletion and amortization expense and impairment test may be affected. The process of estimating reserves is complex, requiring significant judgment in the evaluation of all available geological, geophysical, engineering and economic data. The reserve estimates are prepared by professional engineers, both internal and external, and are subject to change over time as more data becomes available. Changes in the reserves estimates from the prior year were nominal. SMCRA and similar state statutes require, among other things, that surface disturbance be restored in accordance with specified standards and approved reclamation plans. SMCRA requires us to restore affected surface areas to approximate the original contours as contemporaneously as practicable with the completion of surface mining operations. Federal law and some states impose on mine operators the responsibility for replacing certain water supplies damaged by mining operations and repairing or compensating for damage to certain structures occurring on the surface as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. Obligations are reflected at the present value of their future cash flows. We reflect accretion of the obligations for the period from the date they are incurred through the date they are extinguished. The ARO assets are amortized using the units-of-production method over estimated recoverable (proven and probable) reserves. We use credit-adjusted risk-free discount rates ranging from 7% to 10% to discount the obligation, inflation rates anticipated during the time to reclamation, and cost estimates prepared by its engineers inclusive of market risk premiums. Activities include reclamation of pit and support acreage at surface mines, sealing portals at underground mines, and reclamation of refuse areas and slurry ponds. Accretion expense is recognized on the obligation through the expected settlement date. On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, changes in the timing and extent of reclamation activities, and revisions to cost estimates and productivity assumptions, to reflect current experience. Any difference between the recorded amount of the liability and the actual cost of reclamation will be recognized as a gain or loss when the obligation is settled. We have analyzed our filing positions in all of the federal and state jurisdictions where we are required to file income tax returns, as well as all open tax years in these jurisdictions. We identified our federal tax return and our Indiana state tax return as “major” tax jurisdictions. We believe that our income tax filing positions and deductions would be sustained on audit and do not anticipate any adjustments that will result in a material change to our consolidated financial position. We have not taken any significant uncertain tax positions, and our tax provisions and returns are prepared by a large public accounting firm with significant experience in energy related industries. Changes to the estimates from reported amounts in the prior year were not significant. Inventory is valued at a lower of cost or NRV. Anticipated utilization of low sulfur, higher-cost coal from our Freelandville, and Prosperity mines has the potential to create NRV adjustments as our estimated needs change. The NRV adjustments are subject to change as our costs may fluctuate due to higher or lower production and our NRV may fluctuate based on sales contracts we enter into from time to time. As of September 30, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively. Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. For impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The determination of the lowest level of cash flows is largely based on nature of production, common infrastructure, common sales points, common regulation and management oversight to make such determinations. These determinations could impact the determination and measurement of a potential asset impairment. Management evaluates 33 Table of Contents 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK No material changes from the disclosure in our 2024 Annual Report on Form 10-K .