ARLP - NASDAQ

Greetings. Welcome to Alliance Resource Partners Third Quarter 2025 Earnings Conference Call. Please note, this conference is being recorded. At this time, I'll turn the conference over to Cary Marshall, Senior Vice President and Chief Financial Officer. Thank you. You may now begin.

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 Joe Craft, our Chairman, President and Chief Executive Officer, for his comments. For the third quarter of 2025, which we refer to as the 2025 quarter, total revenues were $571.4 million compared to $613.6 million in the third quarter of 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 second quarter of 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 that expired in 2024. 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 950,000 tons, down 1.1 million 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 River View 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 MC 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 River View 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 segment. 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 September 30, 2025, our total and net leverage ratios were 0.75x and 0.6x debt to trailing 12 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 operations. Distributable cash flow for the 2025 quarter was $106.4 million, up 17% sequentially, leading to a calculated distribution coverage ratio of 1.37x based on a quarterly cash distribution of $0.60 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 and priced, 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 million 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 prompter 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 in 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 expectations. And with that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe?

Thank you, Cary, and good morning, everyone. Our operations delivered another solid quarter of performance, tracking consistently with our operating plan, 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 3 years are beginning to pay off. Our Illinois Basin operations are performing well, led by Hamilton, which benefited from new automated longwall shields commencing operation immediately after a successful longwall 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 River View 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 6 units are scheduled to be operating at the Henderson County mine and 3 units are scheduled to remain operating at the River View 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 was resulted -- 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, U.S. 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 2026 and 2027. Rising electricity demand, combined with the 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 baseload 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 in a limited partnership that indirectly acquired a coal-fired plant in the PJM service area, positioning Alliance to directly benefit from the tightening power markets and growing demand for a 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 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 $0.60 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 million, $106.4 million, up 17% sequentially, leading to a calculated distribution coverage ratio of 1.37x 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 baseload 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'll now ask the operator to open the call for questions. Operator?

[Operator Instructions] And our first question is coming from the line of Nathan Martin with Benchmark.

You guys talked about how domestic customer engagement has intensified as utilities seek reliable supply, and that's kind of given you greater demand visibility than you've experienced in several years. Can you guys give us a little more color on how long some of these supply contracts are being signed for now? And 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?

Yes. So most of the customers are coming out for 2 to 3 years, I would say. And of those, they prefer fixed pricing. 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 anticipated or expected. So there is some tariff concept of protection in those contracts, but primarily, they are fixed price for the 2- to 3-year time period. Some are going a little shorter than that, just like a 1 year or even some are still staying in the spot market. But typically, within those contract structures, there is escalation years 2 and year 3 in terms of the pricing, generally speaking.

Okay. That's helpful, guys. And then what index should we be paying attention to? Is it still the Io Basin index and your Northern cap type indices?

Yes. But at the same time, I don't think the index based on the volume is being tracked precisely. So I think that you need to factor in each customer is 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 indexes have been showing depending on what time you're looking at.

That's very helpful.

You're starting to see the index go up over the last quarter or so. And I think that's reflective of where the -- where some of these contracts are trending into.

Got it. And that's actually where I was going to go with my next question. Your pricing guidance also for full year '25, I guess, a little bit higher now at the midpoint. As you look to '26, I believe you said last quarter that the expectation was for price per ton 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?

Yes. I think we still have -- like we 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 '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 -- that we were experiencing previous to the bad geology we've 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.

Yes. That's right, Nate. And depending upon what our volume guidance is for next year, that could impact these numbers a little bit as well. Typically, we provide that -- we'll do that at our January meeting. So we'll provide some volume guidance as well as updated pricing guidance based upon our experience from entering into solicitations for this year and what that looks like in terms of better guidance on volume when we come back and talk to you in February.

All right. Perfect. Appreciate that. And then just maybe one final bigger picture question. A couple of 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 the late retirements have been talked about a lot recently, but it would be great to get your thoughts.

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, that -- the request for support will be greater than that number. So we are seeing 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 beyond -- 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.

Our next question is from the line of Mark Reichman with NOBLE Capital Markets.

So just was curious about the equity method investment income. So it was 2 losses for the first and the second quarter and then $4.5 million in the third quarter. And I was just kind of wondering, even though it doesn't really wag the dog here, have those investments kind of turned the corner? I mean, can we kind of expect positive numbers in the fourth quarter? I was just kind of curious for your thoughts on how those investments are playing out.

Yes, Mark, I think as it relates to that, I mean, I think you're right. I think from where we are right now, I think we can anticipate modestly positive numbers in the fourth quarter here going forward. We did have some of our equity investments that we did make. We have started receiving some 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 you're 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 what you say is modestly positive in the fourth quarter. And going forward, I think that's a fair position with where we are today.

And then on the multi-well pad in the Delaware Basin of the Permian, which is now expected to come online in early 2026. Would you say that, that's really the event that's most responsible for the change in guidance with respect to the oil and gas royalty volumes? And how early in 2026 do you think it would come online?

Yes. I think that is responsible for the changes that we've made in our guidance ranges there. There's no question that it will come online. It's just a matter of timing. Right now, our best guess on that is first quarter of 2026.

And then with respect to the coal business, pricing came in ahead of our estimates 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 longwall move in July, which positively impacted Appalachia, and I believe you had the Henderson in the third quarter. So Illinois Basin, if I just kind of look at the expenses, $37 a ton. So that's kind of in line with your guidance. Appalachia, you're actually -- you were at $58 to $62 last quarter. And so now you're at $60 to $62 and you were at $57.74 for this quarter. So would you frame that? Would you say that maybe you maybe expected more improvement in the expense per ton in the third quarter? Or would you say that like 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 the -- most particularly to Appalachia.

I think that the guidance reflects that the fourth quarter for Mettiki we are anticipating costs to go up in the fourth quarter at Mettiki compared to the third quarter. So that's influenced it on a going-forward basis, we don't think that's systemic. It's just a certain circumstance of where our geology is right now for Mettiki. So going forward, '26 forward, we do believe we're going to be back on a path of having lower cost in Appalachia.

The next question is from the line of Matthew Key with Texas Capital.

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 '25? I know you can get potentially 1 million 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.

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. 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 the strong growth continuing in 2026 that there will be opportunities to be able to grow our total overall in a 2 million ton range. And how much of that is going to be Illinois Basin versus half. It could be a little higher in half versus Illinois Basin, but it's yet to be determined. But if we were to try to make a guess today what our sales would be in '26 versus '25, it would be about 2 million tons up.

Got it. That's super helpful. I appreciate that color. And I just wanted to touch briefly on M&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?

Yes. I would say it would be more focused on minerals. As we indicated, we're continuing to look at the infrastructure area. So 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 an M&A standpoint, there's really no real expectation that we would participate right now in expanding our coal operations.

The next question is from the line of Dave Storms with Stonegate.

Just wanted to start, you mentioned on the outlook that you're expecting to increase production at Tunnel Ridge in the Illinois Basin. Just would love to hear your thoughts around maybe the logistics of increasing that production that's going to require more staffing or anything of that nature?

No. I think with the capital that we've committed over the last 2, 3 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 of being able to roll into those investments. So when you -- we've got the staffing there at River View, when we transition those 6 units, we're just moving people over. We just have more favorable conditions and 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 second half of '26 will be in panels that could, in fact, 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 2 million tons of extra sales that I mentioned a few minutes ago.

Understood. That's very helpful. And then it was also mentioned they anticipate approximately 300,000 to 600,000 million tons of met to be sold in 2026 that's currently uncommitted. Can you just talk about your confidence that, that will get committed or your comfort with maybe potentially bringing that to the spot market in 2026?

Yes. 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 that we will be able to place those tons and the pricing right now is -- again, 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 the price is going to be.

Next question is coming from the line of [ Tim Snyder ] with [ Snyder Capital ].

Thanks for all the color on the power market. 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 a switching either from coal to gas or gas to coal? And then the other follow-up to that is how quickly does that occur? Is that something that can happen in 24 to 48 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?

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 coal on gas competition is just going to get to the winter. You have to have a winter. If you don't have a winter, 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 a 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 4% to 5%. So I don't see that as a direct major issue in trying to influence what spot pricing is going to be. Again, I do believe that the demand on the next 2 to 3 years is growing and they're going to need the coal supply. They need every coal plant open to meet the demand for data centers. So yes, gas prices are important, but it's not as significant as it's been in the past.

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?

Yes, that's fair. That's what I was trying to say.

Next question is from the line of Michael Mathison with Sidoti & Company.

Congratulations on the quarter. A 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?

Yes. Yes, it's hard to say on that. I think really probably closer to the midpoint of guidance is fair. We do anticipate fourth quarter CapEx to be higher than where we are. But typically, we do end up with some capital that carries over year-to-year. But I think it will be higher than where we were this quarter, whether we get to the top end of the guidance range, likely not there, but somewhere in between.

Great. Looking at depreciation expense, it was higher year-over-year in Q3, and I noted that you upped full year guidance. Were there onetime factors in play for that? Or does this level of depreciation feel like the new normal?

Yes. I think this level is probably the new norm for where we're at in terms of depreciation levels. We've had assets that we've placed in service here throughout the year that's led for us to kind of narrow that guidance range from where we are before and just kind of the fact that where we are right now, that's a pretty good rate as we look for the balance of this year, which kind of gets you to where our guidance ranges are.

Right. Then looking at some more big picture items, Joe mentioned that you were interested potentially in other transactions like Gavin. Do you see Cabin, 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?

It's more of the latter. I mentioned on the last call, maybe 5 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 Mississippi. 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 5 to 10 units and/or plants that would be interested in transacting and changing ownership as opposed to continuing to own those plants on a going-forward basis.

And just one more question back to coal operations. Expense per ton is down sharply in Appalachia. Do you feel like -- and you gave a lot of color around supporting why that would sort of endure. Do you feel like that lower expense level is something we can count on going forward? Or were there onetime factors in play?

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 2 units, but that looks to be sustainable. And then as we proceed into '26 where we Mettiki, we appear -- that appears to be consistent with what we've been seeing. So -- as I mentioned a few minutes ago, we do believe that the Mettiki situation is tied to a specific geologic issue in the fourth quarter. But going forward, we do believe Appalachia is going to show very sustainable lower cost than what we've seen over the last several quarters.

This now concludes our question-and-answer session. I'd like to turn the floor back over to Cary Marshall for closing comments.

Thank you, operator. And to everyone on the call today, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our fourth quarter 2025 financial 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.