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 positive results in the second quarter, which is especially encouraging given that energy pricing and demand in the spring season is typically lower due to milder weather. During the quarter we generated $102.9 million of revenue with $17.6 million of EBITDA margin, an improvement of $9.1 million of EBITDA margin over the same period a year ago. ​ One of our two generating units at Merom was out of service for planned maintenance during the majority of the quarter. We benefited from higher-than-expected energy prices and consistent energy volumes from the generating unit that was in operation. We also saw positive results in our Coal Operations segment, including improvements in our coal production, operating costs and recovery metrics at our Oaktown mining complex. These improvements, in addition to the planned outage at Merom, resulted in higher coal inventory levels companywide. We expect coal inventories to decrease in the second half of 2025 based on increased coal shipments and greater energy generation at Merom now that this year’s planned outage is completed. ​ The Company continued its strategy of supplementing periods of weaker pricing with limited sales of firm energy. These firm energy sales help to mitigate the impacts of inconsistent weather and fluctuating energy prices and allowed us to focus on maximizing the value of Merom in a way that balances challenging periods while also giving us flexibility to capture upside opportunity in periods of elevated pricing, like we saw in June. In late June, we expanded our relationship with one of our firm energy counterparties, entering into a $35.0 million prepaid forward power sales contract with energy to be delivered at various periods throughout 2025 and 2026. In connection with this agreement, we also entered into the Third Amendment to our Credit Amendment, which moved the required Term Loan payment from October 2025 to January 2026 and adjusted various covenants to provide additional operating flexibility throughout the summer and into the fourth quarter. The prepaid funds will be used in a variety of ways, including fully cash collateralizing the outstanding $19.0 million Term Loan principal balance under the Credit Agreement and to support company operations. ​ Turning to our negotiations in support of a long-term power purchase agreement with a utility or data center developer, we have seen significant interest in our capacity and energy offerings throughout the quarter. Following the termination of our exclusivity agreement with a leading global data center developer, we have seen a high level of engagement from third parties, including other data center developers and utilities. Each of the interested parties brings a different perspective to the negotiations and each presents opportunities and challenges to effectively monetize our capacity and energy offerings. While we remain in contact with our original counterparty, we are encouraged by our discussions with several of these newly interested parties. We believe that the evolving energy markets, specifically as related to data center growth and favorable utility demand, as well as the favorable regulatory environment, provide the potential to leverage opportunities that simply were not available when we began the request for a proposal process last summer. The utility discussions that we are currently engaged in are intrinsically more straightforward to negotiate, can be implemented sooner and could result in greater sales volumes of energy and accredited capacity. We anticipate pricing will be around the energy curve with terms of ten years or more. As we have highlighted in previous disclosures, many of the non-utility arrangements are inherently complex and involve multiple parties, which adds time and alignment challenges to the negotiation process. Notwithstanding those challenges, returning to non-exclusive negotiations has reinforced our belief that in the end, we will forge a strategic partnership that will create significant value for years to come. ​ Over the last several quarters, we have highlighted our belief that the prevailing industry trend of retiring dispatchable generators, including coal, in favor of non-dispatchable resources such as wind and solar will create an unbalanced energy equation, reduce reliability and increase long-term volatility in the energy markets. It is our position that the enhanced reliability of dispatchable generation, like Merom, versus non-dispatchable generators will increase the value of the attributes of Hallador Power in the overall energy markets. In light of this, we continue to evaluate how to further enhance this value. As we have previously discussed, we are actively seeking acquisition opportunities for additional dispatchable generation, which we believe will help diversify our risk and provide opportunities to upsize strategic future 21 Table of Contents arrangements. We believe that this approach has the potential to enhance our financial flexibility and strengthen our position in the evolving energy market. ​ Additionally, we see the potential of enhancing the reliability, resiliency and flexibility of Merom by adding natural gas and creating a dual fuel scenario, if and when the opportunity makes operational and financial sense. While we are still in the evaluation process, by adding the capability to co-fire with gas or coal, we believe that it could provide Hallador Power the ability to take advantage of the best fuel cost scenario and better control our operating expenses. We believe that the ability to co-fire with natural gas and/or coal will also provide increased resiliency in times where gas availability is traditionally limited, as we have seen in various winter storms across the last several years. This co-firing also allows us to retain the advantage of operating our Sunrise Coal subsidiary and leveraging our own coal supply to prevent unreasonable price increases by third party providers while simultaneously supporting our workforce and the surrounding community. This evaluation is complex on a variety of levels, specifically customer preference and an evolving regulatory environment that could have material impacts on the timing and economic benefits of undertaking such a change. ​ We continue to invest in the future of the plant through extensive maintenance and capital expenditures. We had one unit out of service for planned maintenance for most of the quarter and extending into early third quarter. We typically choose the shoulder season periods for these planned maintenance outages as power demand and pricing in spring are traditionally lower than in other parts of the year. We also try to limit our firm energy sales during these periods to guard against any unforeseen or forced outages, which have the potential to expose us to spot market pricing. Despite the outage, we saw stronger than expected prices in June, which we were able to take advantage of with the unit that remained online. As illustrated in the solid forward sales position table below, in 2026, we currently have 4.0 million delivered energy MWh contracted at an average sales price of $43.05 per MWh. We continue to see higher demand and increase in our average contracted sales price. Our largest PPA contract will see an increase of more than $20.00 per MWh in 2026 as compared to 2025 on expected volumes of approximately 1.6 million MWh. Following 2026, we are optimistic that we will be able to sell energy at higher prices in support of data center development and/or to traditional wholesale customers in line with the indicators of a strong forward curve. ​ We believe that Hallador is uniquely positioned to transform retiring and/or underperforming assets into future opportunities. This will enable us to supply high demand end users, such as data centers and on-shored industrial customers, with minimal impact to retail consumers, unlike a traditional utility siphoning off consumer power to serve these types of large load end-users. By continuing the operations of the dispatchable plants to support large load industrial users as the utilities transition to non-dispatchable generation, the new generation becomes additive to the already struggling grid rather than cannibalizing the overall reliability of what exists today. We remain optimistic about the potential to add to our strategic portfolio and the long-term benefits that such a transaction could produce for the company, its shareholders and its customers. This model for growth enables us to capture value from the critical factors limiting artificial intelligence and data center growth, accredited capacity and reliable and affordable energy. Importantly, the positive momentum that we continue to see from the current administration on both the federal and state levels should make transactions of this sort more feasible than they would have been under the prior administration. ​ Shifting to our Coal Operations, we continue to see the benefits of our 2024 organizational restructuring. While much of the last year was focused on optimizing production, headcount, and strategy to best support our Electric Operations and our existing third-party coal contracts, we have seen improved operational expenses, more efficient recoveries and accelerating shipments. As we have said before, this organizational restructuring should provide us with greater flexibility to quickly scale if we see coal prices increase to a point that justifies restarting production at higher cost units. Additionally, while our coal inventories are elevated, we believe that we are well-positioned to meet industry needs in the event that coal plants, including Merom, continue to dispatch at higher levels. ​ With renewed support of coal mining and coal fired power generation on both the federal and state level, we believe that we are well positioned to take advantage of opportunities for growth and/or expansion. Current market dynamics remain stronger than they have been in the past year, and we continue to evaluate if and when it makes sense to bring on additional coal production in the back half of 2025 and/or 2026. Starting in 2026 our average contracted sales price across all contracts is approximately $4.00 per ton higher than the average contracted sales price in 2025. 22 Table of Contents Notwithstanding this potential to increase production, we currently expect to produce approximately 3.7 million tons of coal in 2025. In the first half of 2025, we produced approximately 2.1 million tons of coal at our Oaktown Mining Complex. We use supplemental coal from third party suppliers at Merom, typically purchased at favorable prices to help diversify self-production supply risk and to provide us additional flexibility in our sales portfolio if prices increase on the spot market. This optionality to obtain low-cost tons either internally or from third-parties while capturing upward swings in the commodity markets for coal should allow us to further maximize margins while optimizing fuels costs at Merom. ​ The continued transformation of Hallador from a commodity focused producer of coal to an IPP remains our primary focus, while leveraging this transition to capture the expanding margins of the energy markets and capitalize on the soaring demand for reliable electricity. The strong and varied interest that we have experienced following the end of our exclusivity period has been encouraging and we are steadfast in our belief of the value that our strategic transition in support of the economy’s desire for reliable energy will bring. We continue to believe that our business is well positioned to take advantage of opportunities for growth and cash flow generation as they arise. ​ Our goal is for Hallador Power to generate on average 1.5 million MWh on a quarterly basis, which equates to 6.0 million MWh annually (see Hallador Power’s capacity and utilization information below). During the first six months of the year, Hallador Power generated 2.2 million MWh, or 73.3% of our quarterly target and purchased 0.2 million MWh. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, ​ Six Months Ended June 30, ​ 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) 921 911 857 874 ​ Accredited capacity utilization (iii) 37 % 39 % 60 % 42 % ​ (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. 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. ​ ​ ​ ​ 23 Table of Contents OVERVIEW The following is an overview our Electric Operations and Coal Operations for Q2 2025 compared to Q1 2025. I. Q2 2025 Net Income of $8.2 million. a. Electric Operations: During the second quarter of 2025, we sold 0.8 million MWh representing a 50.0% decrease in total MWh sold from Q1 2025. This decrease was expected as Q2 typically has lower demand for power and we had a planned maintenance outage on one of our units at Merom for approximately two months during the quarter. Operating revenues increased $17.53 per MWh from the first quarter of 2025. This change was primarily due to the allocation of capacity revenue over lower energy volumes. i. In Q2 2025, Electric Sales were $60.0 million, or $72.44 per MWh sold, on a segment basis. ii. In Q2 2025, Electric Operations fuel, other operating and maintenance and cost of purchased power were $34.2 million, or $41.31 per MWh compared to $49.4 million, or $31.59 per MWh in Q1 2025. This increase in costs per MWh was due to lower energy volumes driven by the planned maintenance outage at Merom. iii. Q2 2025 Electric Operations income before income taxes was $13.99 per MWh, an increase of $1.72 from Q1 2025. b. Coal Operations: During the second quarter of 2025, 0.9 million tons of coal were shipped on a segment basis, with approximately 0.1 million tons of that being shipped to Merom for $7.4 million. This is a decrease of 0.2 million tons of coal shipped from Q1 2025, on a segment basis. This decrease in coal shipments is mainly driven by a 70.0% reduction in shipments to Merom due to the shoulder season and lower demand for power. i. In Q2 2025, Coal Operations operating revenues were $45.5 million, or $51.16 per ton, on a segment basis, an increase of $0.02 per ton from Q1 2025. ii. In Q2 2025, Hallador’s Coal Operations other operating and maintenance costs were $18.2 million, or $20.50 per ton, compared to $23.9 million, or $22.27 per ton, on a segment basis, in Q1 2025. iii. We recorded income before income taxes for the quarter of $1.58 per ton on a segment basis. This is an increase of $7.56 per ton from Q1 2025. 24 Table of Contents II. Solid Forward Sales Position (unaudited) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2025 2026 2027 2028 2029 Total Power ​ ​ ​ ​ ​ ​ Energy ​ ​ ​ ​ ​ ​ Contracted MWh (in millions) ​ 2.53 ​ 4.00 ​ 1.78 ​ 1.09 ​ 0.27 ​ 9.67 Average contracted price per MWh ​ $ 37.75 ​ $ 43.05 ​ $ 54.65 ​ $ 52.98 ​ $ 51.00 ​ ​ Contracted revenue (in millions) ​ $ 95.51 ​ $ 172.22 ​ $ 97.28 ​ $ 57.75 ​ $ 13.77 ​ $ 436.53 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capacity ​ ​ ​ ​ ​ ​ Average daily contracted capacity MW ​ 716 ​ 733 ​ 623 ​ 454 ​ 100 ​ ​ Average contracted capacity price per MWd ​ $ 224 ​ $ 230 ​ $ 226 ​ $ 225 ​ $ 230 ​ ​ Contracted capacity revenue (in millions) ​ $ 29.46 ​ $ 61.54 ​ $ 51.40 ​ $ 37.33 ​ $ 3.47 ​ $ 183.20 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total Energy & Capacity Revenue ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Contracted Power revenue (in millions) ​ $ 124.97 ​ $ 233.76 ​ $ 148.68 ​ $ 95.08 ​ $ 17.24 ​ $ 619.73 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal ​ ​ ​ ​ ​ ​ Priced tons - 3rd party (in millions) ​ 1.42 ​ 2.30 ​ 2.50 ​ 0.50 ​ — ​ 6.72 Avg price per ton - 3rd party ​ $ 50.96 ​ $ 55.58 ​ $ 56.74 ​ $ 59.00 ​ $ — ​ ​ Contracted coal revenue - 3rd party (in millions) ​ $ 72.36 ​ $ 127.83 ​ $ 141.85 ​ $ 29.50 ​ $ — ​ $ 371.54 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL CONTRACTED REVENUE (IN MILLIONS) - CONSOLIDATED ​ $ 197.33 ​ $ 361.59 ​ $ 290.53 ​ $ 124.58 ​ $ 17.24 ​ $ 991.27 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Priced tons - Intercompany (in millions) ​ 1.67 ​ 2.30 ​ 2.30 ​ 2.30 ​ — ​ 8.57 Avg price per ton - Intercompany ​ $ 51.00 ​ $ 51.00 ​ $ 51.00 ​ $ 51.00 ​ $ — ​ ​ Contracted coal revenue - Intercompany (in millions) ​ $ 85.17 ​ $ 117.30 ​ $ 117.30 ​ $ 117.30 ​ $ — ​ $ 437.07 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ TOTAL CONTRACTED REVENUE (IN MILLIONS) - SEGMENT ​ $ 282.50 ​ $ 478.89 ​ $ 407.83 ​ $ 241.88 ​ $ 17.24 ​ $ 1,428.34 ​ ● 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. ​ 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 $49.8 million and $39.9 million for the six months ended June 30, 2025 and 2024, respectively. b. Bank debt increased by $1.0 million during the six months ended June 30, 2025. As of June 30, 2025, our bank debt was $45.0 million. c. We expect cash generated from operations to primarily fund our capital expenditures and our debt service. As of June 30, 2025, we also had an additional borrowing capacity of $32.8 million. d. Total liquidity as of June 30, 2025 was $42.0 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 $17.4 million, including $5.9 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 six months ended June 30, 2025, capex was $24.8 million allocated as follows (in millions): ​ ​ ​ ​ ​ Oaktown – maintenance capex $ 7.7 Oaktown – investment ​ 4.4 Merom Plant ​ 12.7 Capex per the Condensed Consolidated Statements of Cash Flows ​ $ 24.8 ​ 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 June 30, ​ Six Months Ended June 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (in thousands) ​ (in thousands) Delivered Energy $ 44,132 ​ $ 43,106 ​ $ 116,268 ​ $ 92,234 Capacity Revenue ​ ​ 15,844 ​ ​ 16,873 ​ ​ 29,651 ​ ​ 28,646 Electric Sales ​ $ 59,976 ​ $ 59,979 ​ $ 145,919 ​ $ 120,880 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (21,328) ​ $ (24,416) ​ $ (59,399) ​ $ (49,351) Other Operating Costs (1) ​ ​ (1) ​ ​ 7 ​ ​ (9) ​ ​ 14 Other Operating and Maintenance Costs (2) ​ ​ (10,707) ​ ​ (12,479) ​ ​ (15,234) ​ ​ (17,365) Cost of Purchased Power ​ ​ (2,172) ​ ​ (2,619) ​ ​ (9,012) ​ ​ (4,545) Utilities ​ ​ (1,383) ​ ​ (437) ​ ​ (2,059) ​ ​ (959) Labor ​ ​ (7,639) ​ ​ (7,160) ​ ​ (15,782) ​ ​ (14,843) General and Administrative ​ ​ (1,129) ​ ​ (1,450) ​ ​ (2,664) ​ ​ (2,508) EBITDA Margin ​ ​ 15,617 ​ ​ 11,425 ​ ​ 41,760 ​ ​ 31,323 Other Operating Revenue ​ ​ 3,134 ​ ​ 174 ​ ​ 3,221 ​ ​ 331 Depreciation, Depletion and Amortization ​ ​ (5,164) ​ ​ (4,698) ​ ​ (10,325) ​ ​ (9,395) Asset Retirement Obligations Accretion ​ ​ (123) ​ ​ (113) ​ ​ (243) ​ ​ (224) Interest expense ​ ​ (1,891) ​ ​ (186) ​ ​ (3,623) ​ ​ (334) Income before Income Taxes ​ $ 11,573 ​ $ 6,602 ​ $ 30,790 ​ $ 21,701 ​ (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 June 30, ​ Six Months Ended June 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (per MWh) ​ (per MWh) MWh Generated (in thousands) ​ ​ 754 ​ ​ 780 ​ ​ 2,176 ​ ​ 1,596 MWh Purchased (in thousands) ​ ​ 74 ​ ​ 59 ​ ​ 216 ​ ​ 134 MWh Sold (in thousands) ​ ​ 828 ​ ​ 839 ​ ​ 2,392 ​ ​ 1,730 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Delivered Energy $ 53.30 ​ $ 51.38 ​ $ 48.61 ​ $ 53.31 Capacity Revenue ​ ​ 19.14 ​ ​ 20.11 ​ ​ 12.40 ​ ​ 16.56 Electric Sales ​ $ 72.44 ​ $ 71.49 ​ $ 61.01 ​ $ 69.87 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (25.76) ​ $ (29.10) ​ $ (24.83) ​ $ (28.53) Other Operating Costs (1) ​ ​ — ​ ​ 0.01 ​ ​ — ​ ​ 0.01 Other Operating and Maintenance Costs (2) ​ ​ (12.93) ​ ​ (14.87) ​ ​ (6.37) ​ ​ (10.04) Cost of Purchased Power ​ ​ (2.62) ​ ​ (3.12) ​ ​ (3.77) ​ ​ (2.63) Utilities ​ ​ (1.67) ​ ​ (0.52) ​ ​ (0.86) ​ ​ (0.55) Labor ​ ​ (9.23) ​ ​ (8.53) ​ ​ (6.60) ​ ​ (8.58) General and Administrative ​ ​ (1.36) ​ ​ (1.73) ​ ​ (1.11) ​ ​ (1.45) EBITDA Margin ​ ​ 18.87 ​ ​ 13.63 ​ ​ 17.47 ​ ​ 18.10 Other Operating Revenue ​ ​ 3.79 ​ ​ 0.21 ​ ​ 1.35 ​ ​ 0.19 Depreciation, Depletion and Amortization ​ ​ (6.24) ​ ​ (5.60) ​ ​ (4.32) ​ ​ (5.43) Asset Retirement Obligations Accretion ​ ​ (0.15) ​ ​ (0.13) ​ ​ (0.10) ​ ​ (0.13) Interest expense ​ ​ (2.28) ​ ​ (0.22) ​ ​ (1.51) ​ ​ (0.19) Income before Income Taxes ​ $ 13.99 ​ $ 7.89 ​ $ 12.89 ​ $ 12.54 ​ (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 Q2 2025 vs. Q2 2024 Delivered Energy revenue on a dollar and per MWh basis remained flat quarter over quarter, however MWh generated decreased 0.1 million or 3.3% and MWh purchased increased 0.1 million MWh or 25.4% during the same periods. When energy hours at the Merom Hub are priced below our production cost or during outages at Merom, we have the option to make net hourly purchases of power in the MISO market, which we record as cost of purchased power. Cost of purchased power in Q2 2025 was $2.2 million at an average purchase price of $29.35 MWh compared to $2.6 million at an average price of $44.39 per MWh in Q2 2024. Fuel costs decreased $3.1 million, or 12.6%, compared to the second quarter of 2024. On a per MWh basis, fuel costs decreased $3.34, or 11.5%. This change was due to decreased production of energy as noted above resulting in 0.1 million tons or 11.4% less tons of coal used. The average purchase price per ton of coal used in the plant on a segment basis, was $53.38 in the second quarter of 2025, decreasing from $54.17 per ton in the second quarter of 2024. Other operating revenue increased $3.0 million, or 1701.1%, compared to Q2 2024. Other operating revenue on a per MWh basis increased $3.58, or 1704.8%. This change was due to revenue received related to contractual negotiations on the exclusivity agreement. Electric interest expense increased $1.7 million, or 916.7%, compared to the second quarter of 2024. On a per MWh basis, interest expense increased $2.06, or 936.4%. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024 and June 2025. Income before income taxes increased $5.0 million, or 75.3%, compared to the second quarter of 2024. The main drivers of this change in income before income taxes are described in the discussion above. YTD 2025 vs. YTD 2024 Delivered energy increased $24.0 million, or 26.1%, compared to the first six months of 2024. This increase is attributable to new PPA contracts starting in Q1 2025 that were not in effect during 2024. Total PPA hours delivered in the first six months of 2025 were 1.8 million at an average price of $36.63 per MWh compared to delivery of 1.0 million MWh at an average price of $34.42 for the same period in 2024. Fuel increased $10.0 million, or 20.4%, compared to the first six months of 2024. The increase in fuel costs were directly related to the increase in MWh generated, requiring the increased use of fuel by 0.2 million tons of coal or 21%. On a per MWh basis, fuel decreased $3.70, or 13.0% at an average cost of $53.65 per ton for 2025 compared to an average cost of $55.80 per ton for 2024. The cost of purchased power increased $4.5 million, or 98.3%, compared to year-to-date 2024. On a per MWh basis, cost of purchased power increased $1.14, or 43.3%. 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. Electric interest expense increased $3.3 million, or 984.7%, compared to the first six months of 2024. On a per MWh basis, interest expense increased $1.32, or 694.7%. The increase in our interest expense relates to accretion on our prepaid delivered energy contracts that were entered into in October 2024 and June 2025. Income before income taxes increased $9.1 million, or 41.9%, compared to the first six months of 2024. The main drivers of this change in income before income taxes are described in the discussion above. 28 Table of Contents Coal Operations ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, ​ Six Months Ended June 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (in thousands) ​ (in thousands) Coal Sales ​ $ 45,529 ​ $ 45,710 ​ $ 100,303 ​ $ 111,746 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (434) ​ $ (750) ​ $ (990) ​ $ (1,985) Other Operating and Maintenance Costs ​ ​ (18,247) ​ ​ (21,597) ​ ​ (42,101) ​ ​ (53,388) Utilities ​ ​ (3,124) ​ ​ (3,253) ​ ​ (6,600) ​ ​ (7,545) Labor ​ ​ (19,160) ​ ​ (19,395) ​ ​ (38,046) ​ ​ (46,880) General and Administrative ​ ​ (1,915) ​ ​ (3,492) ​ ​ (4,228) ​ ​ (5,930) EBITDA Margin ​ ​ 2,649 ​ ​ (2,777) ​ ​ 8,338 ​ ​ (3,982) Other Operating Revenue ​ ​ 1,399 ​ ​ 497 ​ ​ 2,723 ​ ​ 1,307 Depreciation, Depletion and Amortization ​ ​ (359) ​ ​ (8,930) ​ ​ (10,156) ​ ​ (19,658) Asset Retirement Obligations Accretion ​ ​ (314) ​ ​ (286) ​ ​ (621) ​ ​ (574) Exploration Costs ​ ​ (98) ​ ​ (47) ​ ​ (119) ​ ​ (117) Gain on disposal or abandonment of assets, net ​ ​ 55 ​ ​ 222 ​ ​ 76 ​ ​ 246 Interest expense ​ ​ (1,928) ​ ​ (3,188) ​ ​ (3,919) ​ ​ (6,397) Income (Loss) before Income Taxes ​ $ 1,404 ​ $ (14,509) ​ $ (3,678) ​ $ (29,175) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Ended June 30, ​ Six Months Ended June 30, ​ ​ 2025 ​ 2024 ​ 2025 ​ 2024 ​ ​ (per ton) ​ (in thousands) Tons Sold ​ ​ 890 ​ 849 ​ ​ 1,961 ​ ​ 2,063 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Coal Sales ​ $ 51.16 ​ $ 53.84 ​ $ 51.15 ​ $ 54.17 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fuel ​ $ (0.49) ​ $ (0.88) ​ $ (0.50) ​ $ (0.96) Other Operating and Maintenance Costs ​ ​ (20.50) ​ ​ (25.44) ​ ​ (21.47) ​ ​ (25.88) Utilities ​ ​ (3.51) ​ ​ (3.83) ​ ​ (3.37) ​ ​ (3.66) Labor ​ ​ (21.53) ​ ​ (22.84) ​ ​ (19.40) ​ ​ (22.72) General and Administrative ​ ​ (2.15) ​ ​ (4.11) ​ ​ (2.16) ​ ​ (2.87) EBITDA Margin ​ ​ 2.98 ​ ​ (3.27) ​ ​ 4.25 ​ ​ (1.93) Other Operating Revenue ​ ​ 1.57 ​ ​ 0.59 ​ ​ 1.39 ​ ​ 0.63 Depreciation, Depletion and Amortization ​ ​ (0.40) ​ ​ (10.52) ​ ​ (5.18) ​ ​ (9.53) Asset Retirement Obligations Accretion ​ ​ (0.35) ​ ​ (0.34) ​ ​ (0.32) ​ ​ (0.28) Exploration Costs ​ ​ (0.11) ​ ​ (0.06) ​ ​ (0.06) ​ ​ (0.06) Gain on disposal or abandonment of assets, net ​ ​ 0.06 ​ ​ 0.26 ​ ​ 0.04 ​ ​ 0.12 Interest expense ​ ​ (2.17) ​ ​ (3.76) ​ ​ (2.00) ​ ​ (3.10) Income (Loss) before Income Taxes ​ $ 1.58 ​ $ (17.09) ​ $ (1.88) ​ $ (14.14) ​ Q2 2025 vs. Q2 2024 Other operating and maintenance costs decreased $3.4 million, or 15.5%, compared to the second quarter of 2024. On a per ton basis other operating and maintenance costs decreased $4.94, or 19.4%. This change was the result of impacts related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as increased coal production of 0.2 million tons or 19.1% in Q2 2025 over Q2 2024 whereas coal sales increased 0.1 million tons or 4.8% increasing coal inventory. General and administrative costs decreased $1.6 million, or 45.2%, compared to the second quarter of 2024. On a per ton basis general and administrative costs decreased $1.96, or 47.7%. This change was related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as the retirement of an executive officer in 2024. 29 Table of Contents Depreciation, depletion and amortization decreased $8.6 million, or 96.0%, compared to the second quarter of 2024. On a per ton basis, depreciation, depletion and amortization decreased $10.11, or 96.2%. This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as a $4.8 million out-of-period adjustment recorded during the second quarter of 2025 due to an overestimate of depreciation, depletion and amortization expense in the first quarter 2025. Interest expense decreased $1.3 million, or 39.5%, compared to the second quarter of 2024. On a per ton basis, interest expense decreased $1.59, or 42.3%. Our decreased interest expense relates to reductions of convertible debt of $11.0 million and related party debt of $5.0 million. Income before income taxes increased $15.9 million, or 109.7%, compared to the second quarter of 2024. The main drivers of this change in loss before income taxes are described in the discussion above. YTD 2025 vs. YTD 2024 Coal sales decreased $11.4 million, or 10.2%, compared to the first six months of 2024. On a per ton basis, coal sales decrease $3.02, or 5.6%. Consolidated coal sales decreased $14.1 million, or 17.1% from 2024. These declines were due to reductions in volume and average sales price for our coal. Our average sales price, on a segment basis, decreased $2.99 per ton and we sold 0.1 million tons less compared to 2024. Our average sales price, on a consolidated basis for 2025 decreased $4.27 per ton and we sold 0.2 million tons less compared to 2024. Other operating and maintenance costs decreased $11.3 million, or 21.1%, compared to the first six months of 2024. On a per ton basis, other operating and maintenance costs decreased $4.41, or 17.0%. This change was partially the result of the organizational restructuring that occurred in February 2024 extending into Q2 2024 which led to an expected reduction in production costs related to the higher cost mining locations such as roof support and maintenance. Tons sold decreased 0.1 million tons or 4.9% which further decreased royalty expenses. Labor decreased $8.8 million, or 18.8%, compared to the first six months of 2024. On a per ton basis, labor decreased $3.32, or 14.6%. This change was the result of the organizational restructuring that occurred in February 2024 which reduced the Coal Operations headcount to 655 as of June 30, 2025 from 924 prior to the restructuring. General and administrative costs decreased $1.7 million, or 28.7%, compared to the first six months of 2024. On a per ton basis, general and administrative decreased $0.72, or 25.0%. This change was related to the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million as well as the retirement of an executive officer in 2024. Other operating revenue increased $1.4 million, or 108.3%, compared to the first six months of 2024. On a per ton basis, other operating revenue increased $0.76, or 119.2%. This change was the result of increased utilization of our rail facility by a customer resulting in an increase in transloading fee revenue. Depreciation, depletion and amortization costs decreased $9.5 million, or 48.3%, compared to the first six months of 2024. On a per ton basis, depreciation, depletion and amortization decreased $4.35, or 45.6%. This change was the result of the non-cash impairment charge recognized in Q4 2024 in the amount $215.1 million. Interest expense decreased $2.5 million, or 38.7%, compared to the first six months of 2024. Interest expense on a per ton basis decreased $1.10, or 35.6%. Our decreased interest expense primarily relates to reductions of convertible debt of $11.0 million and related party debt of $5.0 million. Loss before income taxes decreased $25.5 million, or 87.4%, compared to the first six months of 2024. The main drivers of this change in loss before income taxes are described in the discussion above. 30 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 3rd 2024 4th 2024 1st 2025 2nd 2025 T4Qs Tons produced ​ 873 ​ 971 ​ 1,020 ​ 1,059 ​ 3,923 Tons sold ​ 926 ​ 875 ​ 1,071 ​ 890 ​ 3,762 Wash plant recovery in % ​ 60 % 62 % 64 % 66 % Capex (Coal Operations) ​ $ 6,810 ​ $ 11,079 ​ $ 6,244 ​ $ 5,793 ​ $ 29,926 Maintenance capex (Coal Operations) ​ $ 4,208 ​ $ 4,492 ​ $ 4,000 ​ $ 3,691 ​ $ 16,391 Maintenance capex per ton sold (Coal Operations) ​ $ 4.54 ​ $ 5.13 ​ $ 3.73 ​ $ 4.15 ​ $ 4.36 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 52.22 ​ $ 43.25 ​ $ 43.65 ​ $ 46.03 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ All Mines 3rd 2023 4th 2023 1st 2024 2nd 2024 T4Qs Tons produced ​ 1,594 ​ 1,331 ​ 1,271 ​ 889 ​ 5,085 Tons sold ​ 2,054 ​ 1,461 ​ 1,214 ​ 849 ​ 5,578 Wash plant recovery in % ​ 65 % 62 % 60 % 59 % ​ Capex (Coal Operations) ​ $ 11,570 ​ $ 17,867 ​ $ 8,632 ​ $ 7,560 ​ $ 45,629 Maintenance capex (Coal Operations) ​ $ 7,938 ​ $ 13,567 ​ $ 8,085 ​ $ 6,014 ​ $ 35,604 Maintenance capex per ton (Coal Operations) ​ $ 3.86 ​ $ 9.29 ​ $ 6.66 ​ $ 7.08 ​ $ 6.38 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Average cost per ton sold⁽ⁱ⁾ ​ $ 46.54 ​ $ 53.78 ​ $ 51.65 ​ $ 49.94 ​ ​ ​ ​ (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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 3rd 2024 4th 2024 1st 2025 2nd 2025 Basic ​ $ 0.04 ​ $ (5.06) ​ $ 0.23 ​ $ 0.19 Diluted ​ $ 0.04 ​ $ (5.06) ​ $ 0.23 ​ $ 0.19 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 3rd 2023 4th 2023 1st 2024 2nd 2024 Basic ​ $ 0.49 ​ $ (0.31) ​ $ (0.05) ​ $ (0.27) Diluted ​ $ 0.44 ​ $ (0.31) ​ $ (0.05) ​ $ (0.27) ​ INCOME TAXES Our effective tax rate (ETR) is estimated at ~0% and ~23% for the six months ended June 30, 2025 and 2024, respectively. For the six months ended June 30, 2025, we estimated our annual ETR based upon projected annual income (loss), forecasted permanent tax differences, discrete items, and statutory rates in states in which we operate. Our ETR differs from the statutory rate due primarily to statutory depletion in excess of tax basis and changes in the valuation allowance. 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. 31 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 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 June 30, 2025, and December 31, 2024, coal inventory includes NRV adjustments of $0.1 million and $0.3 million, respectively. Long-lived assets used in operations are depreciated and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows is expected to be generated by an asset group. 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 32 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 .