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Date
Monday, Oct. 27, 2025 at 10 a.m. ET
Call participants
Chief Financial Officer — Cary P. Marshall
Chairman, President, and Chief Executive Officer — Joseph W. Craft
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Takeaways
Total Revenues -- $571.4 million in total revenues, primarily due to lower coal sales prices and reduced transportation revenues, partially offset by higher coal sales volumes.
Coal Sales Volumes -- 8.7 million tons, up 3.9% year-over-year and up 3.8% sequentially, with Illinois Basin coal sales volumes up 10.8% year-over-year and Appalachia down 13.3% year-over-year but up 21.8% sequentially in Appalachia.
Average Coal Sales Price per Ton -- $58.78 per ton average coal sales price, a decrease of 7.5% year-over-year but up 1.5% sequentially as legacy contracts rolled off.
Coal Production -- 8.4 million tons, up 8.5% year-over-year.
Total Coal Inventory -- 900,000 tons at quarter-end, down 1.1 million tons year-over-year.
Segment Adjusted EBITDA Expense per Ton (Appalachia) -- Improved 11.7% year-over-year for segment adjusted EBITDA expense per ton sold in Appalachia, and 12.1% sequentially, mainly from better operations at NC Mining and Tunnel Ridge.
Segment Adjusted Expense per Ton (Illinois Basin) -- Segment adjusted expense per ton in the Illinois Basin decreased 6.4% year-over-year, due to increased production, fewer longwall move days at Hamilton, and improved recoveries.
Contingent Consideration Liability (Hamilton Mine) -- $4.4 million unfavorable adjustment, tied to expectations for increased future production.
Royalty Segments Revenue -- $57.4 million in total royalty segment revenues, up 11.9% year-over-year, with coal royalty tons sold up 38.1% year-over-year and a 10.5% drop in average oil and gas sales price per BOE year-over-year.
Coal Royalty Segment Adjusted EBITDA -- Coal Royalty segment adjusted EBITDA was up 54.5% year-over-year, and up 44.6% sequentially, reflecting higher Tunnel Ridge volumes.
Adjusted EBITDA -- Adjusted EBITDA was $185.8 million, up 9% year-over-year and up 14.8% sequentially.
Net Income Attributable to ARLP -- Net income attributable to ARLP was $95.1 million, including a $3.7 million favorable fair value change in digital assets and $4.5 million in investment income from earlier growth investments.
Leverage Ratios -- Total and net leverage ratios at 0.75x and 0.6x debt to trailing-twelve-months adjusted EBITDA, respectively.
Total Liquidity -- $541.8 million in total liquidity, including $94.5 million in cash at quarter-end.
Bitcoin Holdings -- 568 Bitcoin valued at $64.8 million using $114,000 per Bitcoin at quarter-end.
Free Cash Flow -- Free cash flow was $151.4 million, after $63.8 million in investment in coal operations.
Distributable Cash Flow -- Distributable cash flow (non-GAAP) was $106.4 million, up 17% sequentially, supporting a 1.37x distribution coverage ratio on a quarterly distribution of 60¢ per unit ($2.40 annualized).
2025 Sales Guidance -- Tightened to 32.5–33.25 million tons, with the midpoint within 1% of prior guidance.
Contracted 2026 Sales Tons -- 29.1 million tons now contracted and priced for 2026, up 9% from last quarter; includes 29.8 million domestic and 3 million export tons for 2025.
Updated Coal Sales Pricing Guidance -- Raised low end for both Illinois Basin and Appalachia.
Full-Year 2025 Segment Adjusted EBITDA Expense per Ton Guidance -- Appalachia: segment adjusted EBITDA expense per ton is expected to be $60–$62; Illinois Basin segment adjusted EBITDA expense per ton is expected to be $34–$36.
Oil Volume Guidance Revision -- Deferred timing of a Delaware Basin multi-well pad to early 2026, reducing oil royalty volume guidance.
Fixed-Price Contracting Trend -- CEO Craft said, "most of the customers are coming out for two to three years. I would say. And of those, they prefer fixed pricing."
PJM Capacity Auction -- CEO Craft noted, "The recent PJM capacity auction cleared at maximum allowable prices with every megawatt of coal capacity selected."
Growth Capex -- ARLP invested $22.1 million, as part of a $25 million commitment to acquire a coal-fired plant in the PJM service area; sustaining coal capex expected to decline post-Q3 project completion.
M&A Priorities -- Focus remains on minerals and infrastructure investments, with no immediate plans for additional coal asset purchases.
Staffing and Production Scalability -- CEO Craft confirmed, "No. I think with the capital, that we've committed over the last two, three years, we're fully capitalized. I think we would not be bringing on any new units. It would just be taking advantage of the trend lines we've got being able to roll into those investments. So when you We've got the staffing there. At Riverview, when we transition to six units, we're just moving people over. We just have more favorable conditions. In the reserves that we're moving to compared to the reserves that we would have been mining. Had we stayed on the original plan. So we're able to achieve more with the existing headcount. Both at Hamilton and Tunnel Ridge."
Summary
Alliance Resource Partners (ARLP +4.12%) delivered year-over-year revenue and coal price declines, but grew coal sales volumes. The company significantly expanded its contracted sales book into 2026, with pricing floors raised on guidance for both core regions, and expects higher production capacity following recent infrastructure investments. Management highlighted strong term contracting activity, robust demand from data centers, and regulatory and market shifts supporting ongoing utilization of the U.S. coal fleet, while confirming no net headcount increases needed to deliver planned production growth.
Chairman and CEO Craft said, "Compared to last year, year-to-date utility coal consumption has increased by 15% in MISO and 16% in PJM."
ARLP increased its contracted and priced sales tons for 2026 by 9% quarter-over-quarter, citing higher customer demand visibility and the inclusion of escalation terms in contracts extending two to three years.
The company clarified that a delayed high-royalty oil pad in the Delaware Basin drove the downward revision to full-year 2025 oil royalty volume guidance.
Capital projects completed at core mines are expected to meaningfully lower sustaining capex needs and enhance free cash flow visibility starting in 2026.
Industry glossary
Contingent Consideration Liability: Balance sheet item reflecting the expected future payments related to the performance of an acquired asset, adjusted as actual performance outlooks change.
Longwall Move: The process of relocating specialized mining equipment within an underground coal mine to a new production area, often impacting output and expenses during transition.
PJM: PJM Interconnection, a regional transmission organization coordinating the movement of wholesale electricity in parts of the Eastern U.S.
MISO: Midcontinent Independent System Operator, a regional transmission organization that manages the electricity grid in the Midwest and parts of the South.
Met: Metallurgical coal, a type of coal used for steelmaking rather than power generation.
Full Conference Call Transcript
Cary P. Marshall: Thank you, operator. And welcome, everyone. Earlier this morning, Alliance Resource Partners released its third quarter 2025 financial and operating results, and we will now discuss those results as well as our perspective on current market conditions and outlook for the remainder of 2025. Following our prepared remarks, we will open the call to answer your questions. Before beginning, a reminder that some of our remarks today may include forward-looking statements subject to a variety of risks, uncertainties, and assumptions contained in our filings from time to time with the Securities and Exchange Commission and are also reflected in this morning's press release.
While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize, or if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected. In providing these remarks, the partnership has no obligation to publicly update or revise any forward-looking statement whether as a result of new information, future events, or otherwise, unless required by law to do so.
Finally, we will also be discussing certain non-GAAP financial measures. Definitions and reconciliations of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures are contained at the end of ARLP's press release, which has been posted on our website and furnished to the SEC on Form 8-K. With the required preliminaries out of the way, I will begin with a review of our third quarter 2025 results, give an update of our 2025 guidance, then turn the call over to Joseph W. Craft, our Chairman, President, and Chief Executive Officer for his comments.
For the 2025, which we refer to as the 2025 quarter, total revenues were $571.4 million compared to $613.6 million in 2024, which we refer to as the 2024 quarter. The year-over-year decline was driven primarily by lower coal sales prices and lower transportation revenues, partially offset by higher coal sales volumes. Compared to the 2025, which we refer to as the sequential quarter, total revenues increased by 4.4% due to higher coal sales volumes and prices. Our average coal sales price per ton for the 2025 quarter was $58.78, a decrease of 7.5% versus the 2024 quarter but an increase of 1.5% on a sequential basis.
The year-over-year decline was primarily due to higher-priced legacy contracts entered into during the energy crisis of 2022. As it relates to volumes, total coal production in the 2025 quarter of 8.4 million tons was 8.5% higher compared to the 2024 quarter, while total coal sales volumes increased 3.9% to 8.7 million tons compared to the 2024 quarter. Compared to the sequential quarter, total coal sales volumes were up 3.8%. Total coal inventory at quarter-end was approximately 900,000 tons, down 1.1 and 0.2 million tons compared to the 2024 quarter and sequential quarter, respectively.
In the Illinois Basin, coal sales volumes increased by 10.8% as compared to the 2024 quarter, led by increased volumes from our Hamilton, Warrior, and Riverview mines but were down 0.8% versus the sequential quarter due to timing of delivery for contracted tons. Coal sales volumes in Appalachia were down 13.3% compared to the 2024 quarter, due to lower production year-to-date at our Tunnel Ridge mine but were up 21.8% versus the sequential quarter as we successfully transitioned the longwall at Tunnel Ridge to a new longwall district during the 2025 quarter, which was the primary driver for the increased volumes.
As anticipated, the new district has delivered improved geology and mining conditions compared to the challenges we experienced over the last several quarters. Segment adjusted EBITDA expense per ton sold in Appalachia improved 11.7% compared to the 2024 quarter as all mines in Appalachia achieved lower cost in the 2025 quarter. And sequentially, better results from NC Mining and Tunnel Ridge contributed to a 12.1% improvement in the 2025 quarter. In the Illinois Basin, segment adjusted expense per ton decreased 6.4% compared to the 2024 quarter, primarily as a result of increased regional production, lower longwall move days at Hamilton, and improved recoveries at our Riverview and Hamilton mining operations.
Expenses in the 2025 quarter included a $4.4 million unfavorable contingent consideration liability adjustment at our Hamilton mine related to our original acquisition based upon a revised outlook that anticipates increased production in the future at Hamilton. But for this adjustment, segment adjusted EBITDA expense per ton in the 2025 quarter in the Illinois Basin would have been flat with the sequential quarter. Turning to our royalty segments, total revenues were $57.4 million in the 2025 quarter, up 11.9% compared to the 2024 quarter. The year-over-year increase in revenues primarily reflects higher coal royalties tons and revenue per ton sold partially offset by lower average oil and gas price per BOE.
Specifically, coal royalty tons sold during the 2025 quarter increased 38.1% compared to the prior year, and 28.5% sequentially primarily due to higher Tunnel Ridge volumes, which drove Coal Royalty segment adjusted EBITDA up 54.5% compared to the 2024 quarter and 44.6% higher compared to the sequential quarter. Oil and gas royalty BOE volumes during the 2025 quarter increased 4.1% year over year. However, a lower mix of oil volumes and lower realized crude oil pricing resulted in a 10.5% decline in average oil and gas sales price per BOE compared to the 2024 quarter. Our net income attributable to ARLP in the 2025 quarter was $95.1 million.
This included a $3.7 million favorable increase in the fair value of our digital assets and $4.5 million in investment income from previous growth investments. Adjusted EBITDA for the quarter was $185.8 million, up 9% from the 2024 quarter and up 14.8% sequentially. Now turning to our balance sheet and uses of cash. As of 09/30/2025, our total and net leverage ratios were 0.75 times and 0.6 times debt to trailing twelve months adjusted EBITDA, respectively.
Total liquidity was $541.8 million at quarter-end, which included $94.5 million of cash on the balance sheet. Additionally, we held approximately 568 Bitcoin on our balance sheet, valued at $64.8 million at the end of the 2025 quarter, based upon a price of approximately $114,000 per Bitcoin. For the 2025 quarter, Alliance generated free cash flow of $151.4 million after investing $63.8 million in our coal operation. Distributable cash flow for the 2025 quarter was $106.4 million, up 17% sequentially leading to a calculated distribution coverage ratio of 1.37 times based on a quarterly cash distribution of 60¢ per unit or $2.40 per unit on an annualized basis.
Turning to our updated 2025 guidance, detailed in this morning's release, favorable weather for most of this past cooling season, and rising electricity demand drove increased coal consumption in the Eastern United States helping further reduce customer inventories. Long-term demand forecasts continue to be revised higher across the country, and as the more favorable regulatory environment continues, we are observing a steady stream of domestic customer solicitations for long-term supply contracts. During the 2025 quarter, and subsequent to its end, ARLP has remained active in domestic utility solicitations for 2026 and beyond.
Our teams have been successful in securing additional contract commitments as customers continue to value our product quality, reliability of service, and financial strength. Our contracted position for 2025 is up slightly to 32.8 million tons committed in price, including 29.8 million tons for the domestic market and 3 million tons for export. We have elected to tighten our full-year sales guidance to 32.5 to 33.25 million tons with the midpoint coming in within 1% of our previous guidance in July. Perhaps more importantly, strong demand for our supply allowed us to add to our 2026 order book once again.
We have now contracted and priced 29.1 million sales tons for 2026, up 9% from last quarter, putting us in a good position for this time of year for prompt year shipments. With respect to pricing, we increased the low end of our coal sales pricing guidance ranges for both the Illinois Basin and Appalachia. And on the cost side, we expect full-year 2025 segment adjusted EBITDA expense per ton to be in a range of $60 to $62 per ton in Appalachia, and $34 to $36 per ton in the Illinois Basin.
In our oil and gas royalties business, we are adjusting our full-year 2025 oil volume guidance to account for a timing delay and a high royalty interest multi-well development pad in the Delaware Basin of the Permian, which is now expected to come online in early 2026. As it relates to all our other guidance ranges, they are largely unchanged from our previous expectation. And with that, I will turn the call over to Joseph W. Craft for comments on the market and his outlook for ARLP. Joe?
Joseph W. Craft: Thank you, Cary, and good morning, everyone. Our operations delivered another solid quarter performance, tracking consistently with our operating plans, thanks to the dedication and hard work of our entire team. As Cary described, the significant infrastructure investments we have made in our coal operations over the past three years are beginning to pay off. Our Illinois Basin operations are performing well, led by Hamilton, which benefited from new automated long wall shields, commencing operation immediately after a successful long wall move in early August. Looking forward, the combination of shield and shear automation is expected to enhance productivity, reduce the number of personnel required on the face, and minimize maintenance demands.
At our Riverview Complex, the Henderson County mine achieved a key infrastructure milestone in late August with the opening of its new portal facility. Equipment and personnel transitions to better mining conditions are planned to be in place early next year when six units are scheduled to be operating at the Henderson County Mine and three units are scheduled to remain operating at the Riverview mine. Our Appalachia operations improvements were led by Tunnel Ridge, which successfully transitioned to a new longwall district in the 2025 quarter. As expected, the move has resulted in significantly improved mining conditions, dropping the mine's cost per ton sold by 8.8% compared to the 2024 quarter and 19.3% to the sequential quarter.
With both regions performing well, our total cost expectations for 2025 are on track to fall within the updated guidance range. Looking at the coal market, US coal demand is continuing to experience strong fundamentals, supported by a combination of favorable federal energy and environmental policy to preserve America's coal fleet plus rapid electricity demand growth. Compared to last year, year-to-date utility coal consumption has increased by 15% in MISO and 16% in PJM. This surge reflects not only favorable natural gas pricing, but more importantly, a realization of the dramatic load growth required by artificial intelligence and data centers. Natural gas fundamentals remain supportive of coal dispatch economics.
Henry Hub has averaged over $3.50 per million BTU in 2025, and the current forward strip is averaging higher pricing in '26 and 2027. Rising electricity demand combined with expected growth of LNG export capacity should keep upward pressure on natural gas prices, further enhancing coal's competitiveness in power generation dispatch. Furthermore, utility coal stockpiles have normalized at healthy levels, supporting more robust term contracting activity. With normalized utility inventories and unprecedented demand growth from data centers, analysts we follow are projecting 4% to 6% annual growth in electricity demand in PJM and other markets we serve over the next several years.
As a result, we believe Alliance is well-positioned to increase production at Tunnel Ridge and in the Illinois Basin in 2026 to meet this demand. Market signals are validating the need to keep base load power plants online to meet this anticipated electricity demand, including coal-fired power plants previously planned for decommissioning. The recent PJM capacity auction cleared at maximum allowable prices with every megawatt of coal capacity selected, while reserve margins fell below reliability targets, clearly demonstrating that the grid needs every available megawatt of dispatchable generation.
During the quarter, as I mentioned in our last earnings call, to assist in extending the lives of coal plants in our marketing footprint, we invested $22.1 million as part of a $25 million commitment and a limited partnership that indirectly acquired a coal-fired plant in the PJM service area, positioning Alliance to directly benefit from the tightening power market and growing demand for reliable, baseload generation. We expect this investment to generate attractive cash-on-cash returns during 2026 and beyond.
In conclusion, our priorities remained unchanged. Maintaining a strong balance sheet, investing prudently in our core operations, and positioning Alliance for long-term growth while delivering attractive after-tax returns to our unitholders. With the completion of several major capital projects at our mines, sustaining capital needs in our coal segment are expected to decline meaningfully, which enhances free cash flow visibility for 2026 and beyond. In our oil and gas royalties business, we continue to pursue disciplined accretive growth opportunities. Although lower commodity pricing has limited investment opportunities in 2025, the segment remains unlevered, and we strive to reinvest in internally generated cash flow to expand our minerals position where we see attractive economics and high-quality operator activity. Returning capital to our unitholders remains a key component of our strategy. During the 2025 quarter, we declared a quarterly distribution of 60¢ per unit, equating to an annualized rate of $2.40 per unit and unchanged from the sequential quarter. As Cary said, distributable cash flow for the 2025 quarter was $106.4 million, up 17% sequentially, leading to a calculated distribution coverage ratio of 1.37 times for the 2025 quarter. We expect the operating and financial results for the fourth quarter to equal our outstanding 2025 quarter results. At Alliance, we remain laser-focused on delivering what America needs most: reliable, affordable base load generation. With supportive policy, improving market fundamentals, and disciplined execution, we believe we are well-positioned for the balance of 2025 and beyond. That concludes our prepared comments, and I will now ask the operator to open the call for questions.
Operator: Thank you. We'll now be conducting a question and answer session. If you like to ask a question today, please press 1 on your telephone keypad, and a confirmation tone will indicate your line is in the question queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Thank you. And our first question coming from the line of Nathan Pierson Martin with Benchmark. Please proceed with your question.
Nathan Pierson Martin: Thanks, operator. Good morning, Joe. Good morning, Cary. Morning, Nick. You know, you guys talked about how domestic customer engagement has intensified, you know, as utilities seek reliable supply, and that's kinda given you greater demand visibility than you've experienced in several years. Could you guys give us a little more color on how long some of these supply contracts are being signed for now? Maybe what kind of structure is typical on the price side, whether that's fixed or if it's tied to a variable index, for example. Thanks.
Joseph W. Craft: Yeah. So most of the customers are coming out for two to three years. I would say. And of those, they prefer fixed pricing, and so we are looking at fixed pricing. We do have some understanding that there would be some reconsideration in the event that tariffs impact costs that aren't that are not anticipated or expected. So there is some tariff concept of the protection in those contracts, but primarily, they are fixed price for the two to three-year time period. Some are going a little shorter than that, just like a one year or even some are still staying in the spot market.
But typically within those contract structures, there is escalation years two and year three in terms of the pricing. Generally speaking.
Nathan Pierson Martin: Okay. That's helpful, guys. And then what index should we be paying attention to? Is it still the, you on a basin in this and, you know, northern cap type indices?
Joseph W. Craft: Yeah. But at the same time, I don't think the index, you know, based on the volume, it is being tracked precisely. So I think that you need to factor in each customer's a little different. But, I mean, I think those indexes are generally accurate, but we are seeing some pricing that's a little bit higher than what those index has been showing depending on what time you're looking at.
Nathan Pierson Martin: Okay. That works. That's very helpful too. Alright. You're starting to see the index go up. Over the last quarter, say. And I think that's reflective of where the where some of these contracts are trending into.
Joseph W. Craft: Got it. And that's actually where I was gonna go with my next question. Your pricing guidance also for full year '25, it gets a little bit higher. Now at the midpoint. As you look at '26, I believe you said last quarter that the expectation was for price per ton, you know, could decline around 5% year over year. And now that you've added some additional tonnage for '26, do you still feel like that down 5% is the right way to think about pricing for next year?
Joseph W. Craft: Yeah. I think we still have like we've mentioned, some of our contracts rolled off in 2024. We have some contracts in Appalachia that are rolling off in 2025. So that's the main reason for the suggestion that our overall pricing is likely to be down year over year because of the Appalachia contracts that are rolling off in 2025. They're having to be replaced at the '26 pricing. However, because of the movement of Tunnel Ridge into their favorable geology, we are expecting to pick up volume there. Back to levels that were more you know, that we were experiencing. Previous to the bad geology we experienced over the past several quarters.
So we do believe that the cost improvements that we see at Tunnel Ridge would allow our margins to be maintained. For '26 compared to '25.
Nathan Pierson Martin: Yeah. That's right, Nate. And, you know, depending upon what our volume guidance is for next year, you know, that could impact these numbers. A little bit as well. You know, typically, we provide that at you know, we'll we'll do that at our January meeting. You know? So we'll provide some volume guidance as well as updated pricing guidance based upon our experience from you know, entering into solicitations for this year and what that looks like in terms of you know, better guidance on volume when we come back and talk to you in February.
Nathan Pierson Martin: Alright. Perfect. Appreciate that. And then just maybe one final bigger picture question. You know, couple weeks back, administration, Department of Energy announced some additional investments in the coal-fired power plant space. Maybe, Joe, could you please talk about how you see that impacting your business and your customers? I know delayed retirements have been talked about a lot recently, but would be great to get your thoughts.
Joseph W. Craft: We are seeing a very active engagement both by utilities and the Department of Energy on dispatching those resources. I think the number was around $625 million. Those bids are due in imminently. And there was a call recently among the various customers that were interested in taking advantage of that. And it was very robust. I believe that the request for support will be greater than that number. So we are seeing know, several, significantly more than several, I guess. Utilities are interested in taking advantage of that opportunity.
There has been indication depending upon demand and the attractiveness of the opportunities that are presented that could open the door for more funds being available to assist these utilities and investing in their coal plants to make sure that they do dispatch and run. You know, beyond, you know, basically run for their original determined life, what their anticipated life would be. We know several customers that are looking at investments that we sell to that it would benefit them by actually increasing the demand that they would have in the out years if they can get these grants. And or loans from the government.
Nathan Pierson Martin: Okay. Great. I'll leave it there. Appreciate the time, and best of luck in the fourth quarter.
Operator: Thank you, Nate. Our next question is from the line of Mark Reichman with Noble Capital Markets. Please proceed with your questions.
Mark Reichman: Thank you. So just was curious about the equity method investment income. So, you know, it was two losses for the first and the second quarter. And then, you know, $4.5 million in the third quarter. And I was just kinda wondering even though, you know, it doesn't really wag the dog here. Have those investments kinda turned the corner? I mean, can we kind of expect positive numbers in the fourth quarter? Was just kind of curious for your thoughts on how those investments are playing out?
Cary P. Marshall: Yeah. Mark, I think I think as it relates to that, I mean, I think I think you're right. I think, you know, from where we are right now, I think we can know, anticipate, you know, modestly positive numbers. In the fourth quarter. Here going forward. You know, we did have you know, some of our equity investments that we did make we you know, we have started receiving some you know, decent distributions in relationship to our investments that we've made in those. Which has led to some higher valuations for some of those investments, which seeing that reflected in this quarter's number there. So this quarter is probably a little bit higher than what typically would be.
On a normal going forward basis. I mean, we'll see depending upon how say, the Gavin investment may perform for us because we are anticipating cash on cash returns from there as well. So but I think I think what you say is, you know, positive, you know, in the in the fourth quarter and going forward. I think that's a that's a fair position with where we are today.
Mark Reichman: Thank you. Then on the multi-well pad in the Delaware Basin, of the Permian, which is now expected to come online and in early 2026. Would you say that's really the event that's most responsible for the for the change in guidance with respect to the oil and gas royalty volumes? And how early 2026 would do you think it would it would come online?
Cary P. Marshall: Yeah. I think I think that is that is responsible for the changes that we've we've made in our guidance ranges there. There's there's no question that, you know, we'll come online. It's just a matter of timing. Right now, our best guess on that is first quarter of 2026.
Mark Reichman: And then with respect to the coal business, you know, pricing came in ahead of our estimate and the segment adjusted EBITDA expense per ton came in lower. Than what we were looking for. So that's all very positive. So you had the you had the long wall move in July, which positively impacted Appalachia, and I believe you had the Henderson in the third quarter. So Illinois Basin, you know, if I just kinda look at the expenses, $35.37 a ton, So that's kind of in line with your with your guidance. You know, Appalachia, you're actually you were 58 to 62. Last quarter, and so now you're at 60 to 62, and you were $57.74. For this quarter.
So do would you frame that? Would you say that maybe you know, you did you maybe expected more improvement in the in the expense per ton in the third quarter or would you say that, fourth quarter going forward? It seems to me that the expenses could actually be kind of at the lower end of your guidance kind of from this point forward. So just kind of your thoughts on most particularly to Appalachia.
Joseph W. Craft: Yeah. I think that the guidance reflects that the fourth quarter for Metiki we are anticipating costs to go up in the fourth quarter at Metiki compared to the quarter. So that's influenced it. On a going forward basis, we don't think that's systemic. It's just a certain circumstance that we're our geology is right now. For Metiqui. So going forward, '26 forward, we do believe we're gonna be back on a path of having lower cost. In app in Appalachia.
Mark Reichman: Okay. Well, that answers most of my questions. So thank you very much.
Joseph W. Craft: Thank you, Mark.
Operator: The next question is from the line of Matthew Key with Texas Capital. Please proceed with your question.
Matthew Key: Good morning, and thank you for taking my questions. I wanted to talk about just initial expectations for volume in 2026. Given that you guys have made strong progress on the contracting front. What's your view of the best case scenario for shipments in '26 versus 'twenty five? I know you can get potentially $1,000,000 more out of Tunnel Ridge. So I was wondering if you could just walk me through what other opportunities are out there for increasing volumes. As we head into next year? Thanks.
Joseph W. Craft: I think that we do believe that Illinois Basin will also be able to yield some increase. It's yet to be determined exactly what that is. Know, we've had some early indications based off of the contracting that we've been discussing. That because of the timing of data centers that are coming online, and the just a strong growth continuing in 2026. That there will be opportunities to be able to grow our total overall in a 2,000,000 ton range. And how much of that's gonna be Illinois Basin versus half It could be a little higher in half versus Illinois Basin, but it's yet to be determined.
But know, if we were to try to make a guess today, what our sales would be in '26 versus '25, it would be about 2,000,000 tons out.
Matthew Key: Got it. That's super helpful. I appreciate that color. And I just wanted to touch briefly on M and A outlook in the current market. Any opportunities out there in coal or do you view it more likely more focused on the oil and gas royalty business or secondary business?
Joseph W. Craft: Yeah. I would say it would be more focused on minerals. As we indicated, we're continuing to look at the infrastructure area. So we're we would like to find more opportunities like Gavin. So we're considering that. There's a couple of other things that we're looking at small dollars. But that allow Matrix to be able to achieve its goals and the growth opportunities it sees beyond its own organic growth. That it's looking at. So I think those would be the areas that we'd be focused on. But on m and a standpoint, there's really no real expectation that we would participate right now in the expanding our coal operations.
Matthew Key: Got it. Thank you for the color, and great job in the quarter.
Operator: Thank you, Matt. Next question is from the line of Dave Storms with Stonegate. Please proceed with your questions.
Dave Storms: Morning. Thank you for taking my questions. Just wanted to start, you mentioned on the outlook that you're expecting increased production at Tunnel Ridge in the Illinois Basin. Just would love to hear your thoughts around maybe the logistics of increasing that production is that's gonna require more staffing or anything of that nature.
Joseph W. Craft: No. I think with the capital, that we've committed over the last two, three years, we're fully capitalized. I think we would not be bringing on any new units. It would just be taking advantage of the trend lines we've got being able to roll into those investments. So when you We've got the staffing there. At Riverview, when we transition to six units, we're just moving people over. We just have more favorable conditions. In the reserves that we're moving to compared to the reserves that we would have been mining. Had we stayed on the original plan. So we're able to achieve more with the existing headcount. Both at Hamilton and Tunnel Ridge.
We anticipate that our development in '26, say, the '26 will be in panels that could impact allow dropping a unit or so of development. So from a headcount perspective, we don't anticipate hiring. Or needing to add personnel to achieve that two main times of extra sales that I mentioned a few minutes ago.
Dave Storms: Understood. That's very helpful. Thank you. And then was also mentioned they anticipate approximately, you know, 300,000 to 600,000 million tons of met to be sold in 2026. That's currently uncommitted. You just talk about, your confidence that will get committed? Or your you know, comfort with potentially bringing that to the spot market? In 2026?
Joseph W. Craft: Yeah. So on the met side of the business, that typically is priced on a quarterly basis or committed on a quarterly basis. So historically, we've really not had committed met tons and we still don't, but we do anticipate since that we will be able to place those times and the pricing right now is again, they the pricing is based off index. At the moment in time that they actually commit. So we do believe that we can sell it. We can't really give you a prediction of what price is gonna be.
Dave Storms: That's very helpful. Thank you for taking my questions. Good luck. Next quarter.
Cary P. Marshall: Thank you, Dave.
Operator: Next question is coming from the line of Tim Snyder with Snyder Capital. Please proceed with your question.
Tim Snyder: Hey. Good morning, and thank you for taking my question. And thanks for all the color on the power markets. Super interesting. Question I had, at what kind of level of maybe either Henry Hub or intraday pricing for the basins that you guys are kind of active in terms of delivering coal to your power customers. Are we seeing switching either from coal to gas or cast gas to coal? And then the other quick follow-up to that is how quickly does that occur?
Is that, you know, something that can happen in twenty four to forty eight hours or so depending on what the front month does, or is this a more I guess, more of a paced switching on and off?
Joseph W. Craft: I would I would answer that by saying that we're seeing the actual competition of gas to coal being less of a factor as data centers come online. Than what it has in the past. I think the major question back to gas and colon gas competition is just gonna get to the winner. You know, you have to have a winner. If you don't have a winner, then your question is more relevant. And it would be more gradual as opposed to a day to day type decision. But I think weather dependency for winter is probably the one area where gas prices would be impacted that could have an influence on what coal demand would be.
But assuming a normal winter or winter like we had last year, we didn't experience in 2025. We haven't experienced true gas on coal competition like we had in the past. And, again, I think that's driven by the capacity utilization. And with the growth we're seeing. So we saw, as I mentioned in the prepared remarks, 15 to 16% growth year over year. In electricity demand and a lot of that is anticipated to grow again four to five. So I don't see that as a direct a major issue in trying to influence what spot price is gonna be.
Again, I do believe that the demand on the next two to three years is growing and they're gonna need the coal supply. They need every coal plant open to meet the demand for data centers. So gas is gas prices are important, but it's not as significant as it's been in the past.
Tim Snyder: Got it. So would it be fair to say then, basically, from your vantage point, it's kind of all of the electrons are needed going forward irrespective of kind of source. Sort of sensitivity just that was there historically just isn't there anymore going forward?
Joseph W. Craft: Yeah. That's fair. That's what I was trying to say.
Tim Snyder: Okay. Alright. Thank you.
Operator: Next question is from the line of Michael Mathison with Sidoti and Company. Please proceed with your questions.
Michael Mathison: Good morning, you guys, and congratulations on the quarter.
Cary P. Marshall: Thank you. Couple of things that I noticed going over your financials. CapEx is lower year over year and in line with the sequential quarter. Does that make you see full year CapEx is coming in toward the low point of guidance?
Cary P. Marshall: Yes. I you know, it's it's it's hard to say, you know, on that. You know, I think I think, you know, really probably closer to the midpoint of guidance is fair. Yeah. We do anticipate you know, fourth quarter CapEx to be higher than where we are. But you know, typically, we do end up with some capital that carries over year to year. But, you know, I think it'll be higher than where we were this quarter. You know, whether we get to the top end of the guidance range. You know, likely not there. But somewhere in between.
Michael Mathison: Great. Thank you. Looking at depreciation expense, it was higher year over year in Q3, and I noted that you upped full year guidance. Were there one time factors in play for that or does this level of depreciation feel like the new normal?
Cary P. Marshall: Yeah. I think this level is probably the new norm. For where we're at in terms of depreciation levels. We've had know, assets that we've we've placed in service here throughout the year that's led for us to kinda narrow that guidance range from where we are before and just kinda the fact that, you know, where we are right now, that's that's a pretty good rate, you know, as we look for the balance of this year, which kinda gets you to where our guidance ranges are.
Michael Mathison: Right. Then looking at some more big picture items, Joe mentioned that you were, interested potentially in other transactions like Gavin. Do you see Gavin as sort of the beginning of a trend of a lot of utilities wanting to sell off their coal-fired capacity, or does it look like one by one at a time?
Joseph W. Craft: It's more of the latter. I mentioned on the last call, may be five to 10 units or plants. And I haven't seen anything that would change that perspective. And I'm focused strictly on East Of The so there may be some things in the West that I'm not aware of. But as we look at the East Of The Mississippi, I could see five to 10 units or indoor plants that would be interested in transacting and changing ownership. As opposed to continuing to own those plants. On a going forward basis.
Michael Mathison: Well, thank you. And just one more question back to coal operations. Expense per ton is down sharply in Appalachia. You feel like and you gave a lot of color around supporting why that would sort of endure You feel like that lower expense level is something we can count on going forward? Or were there one time factors in play?
Joseph W. Craft: We do believe you can count on that going forward. And the primary reason is back to the new district we're going to in Tunnel Ridge. As we look at our MC mine, it's only two units, but that looks to be sustainable. You know? And then as we proceed into '26 for Med Tiki, we appear to that appears to be consistent with what we been seeing. So as I mentioned a few minutes ago, we do believe that the Metiki situation is folk you know, is tied to a specific geologic issue in the fourth quarter.
But going forward, the we do believe Appalachia is gonna show very sustainable low lower cost than what we've seen over the last several quarters.
Michael Mathison: Okay. Thank you for taking my questions, and good luck next quarter.
Cary P. Marshall: Thank you, Michael.
Operator: Thank you. This now concludes our question and answer session. I'd like to turn the floor back over to Cary P. Marshall for closing comments.
Cary P. Marshall: Thank you, operator. And to everyone on the call today, we appreciate your time this morning. And also your continued and interest in Alliance. Our next call to discuss our fourth quarter 2025 and operating results is currently expected to occur in February, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you.
Operator: Thank you. Ladies and gentlemen, thank you for your participation. Today's conference has concluded. You may disconnect your lines at this time, and have a wonderful day.