Alliance Resource Partners, L.P. (ARLP) Q4 FY2025 Earnings Call Transcript & Summary

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

Thank you, operator. Good morning, and welcome, everyone. Earlier today, Alliance Resource Partners released its fourth 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 2026. 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, for 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 statements, 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 fourth quarter 2025 results, discuss our 2026 guidance then turn the call over to Joe Craft, our Chairman, President and Chief Executive Officer, for his comments. For the fourth quarter of 2025, which we refer to as the 2025 quarter, adjusted EBITDA was $191.1 million, up 54.1% from the fourth quarter of 2024, which we refer to as the 2024 quarter, and up 2.8% compared to the third quarter of 2025, which we refer to as the sequential quarter. Our net income attributable to ARLP in the 2025 quarter was $82.7 million or $0.64 per unit as compared to $16.3 million or $0.12 per unit in the 2024 quarter. This was the result of lower operating expenses, lower impairment charges and higher investment income, including $20 million in investment income in the 2025 quarter of which $17.5 million was related to our share of an increase in the fair value of a coal-fired power plant indirectly owned and operated by an equity method investee. This helped offset a $15.4 million decrease in the fair value of our digital assets. Total revenues were $535.5 million in the 2025 quarter compared to $590.1 million in the 2024 quarter. This year-over-year decline was driven primarily by lower coal sales and transportation revenues, partially offset by record oil and gas royalty volumes. Compared to the sequential quarter, total revenue decreased 6.3% due to lower coal sales volumes and prices. Average coal sales price per ton for the 2025 quarter was $57.57, a 4% decrease versus the 2024 quarter and a 2.1% decrease sequentially. As noted during prior calls, higher-priced legacy coal contracts entered into during the 2022 energy crisis continue to roll off and are being replaced at coal pricing levels assumed in our 2026 guidance ranges. Total coal production in the 2025 quarter was 8.2 million tons compared to 6.9 million tons in the 2024 quarter. Coal sales volumes were 8.1 million tons down from 8.4 million and 8.7 million tons compared to the 2024 and sequential quarters. Segment adjusted EBITDA expense per ton sold for our coal operations was $40.24 per ton in the 2025 quarter, a decrease of 16.3% and 1.8% versus the 2024 and sequential quarters. In the Illinois Basin, coal sales volumes were 6.5 million tons in the 2025 quarter down approximately 2% compared to both the 2024 and sequential quarters, primarily due to timing of committed deliveries. I would like to highlight the outstanding performance at our Hamilton Mining Complex where we achieved record production volumes and saleable yield during the 2025 full year. Segment adjusted EBITDA expense per ton in the Illinois Basin decreased 14.4% compared to the 2024 quarter due primarily to increased production at Hamilton, resulting from fewer longwall move days and improved recoveries. Compared to the sequential quarter, Illinois Basin expense per ton decreased 3.8%. In our Appalachia region, coal sales volumes were 1.7 million tons in the 2025 quarter, down from 1.8 million and 2.1 million tons in the 2024 and sequential quarters, respectively. This decrease was caused primarily by timing of committed sales at our Mettiki mine and Tunnel Ridge volumes that were impacted by December longwall jump necessitated by a block of support coal needed to be left beneath for gas pipelines. Segment adjusted EBITDA expense per ton decreased 17.5% versus the 2024 quarter due primarily to increased production at our MC Mining and Mettiki operations and higher recoveries at Tunnel Ridge. Compared to the sequential quarter, segment adjusted EBITDA expense increased 9.7% primarily due to lower production and recoveries across the region. As I mentioned earlier, at Mettiki, a series of outages at a key customer's plant negatively impacted our shipments in the 2025 quarter. We have recently been informed that the plan expects additional outages during 2026, and they are not in a position to commit to purchase any additional tons from Mettiki for the foreseeable feature. Mettiki depends on this customer purchasing a minimum of 1 million tons per year and with no clear alternative customer to absorb production issuing Warren Act notices became unavoidable. Mettiki expects to fulfill its existing contractual commitments, which are scheduled to conclude in March 2026, primarily from existing inventory. For the 2025 full year, segment adjusted EBITDA less capital expenditures at Mettiki was approximately $3.5 million. The anticipated impact of reduced sales volumes at Mettiki is reflected in our 2026 guidance. And additionally, the partnership will evaluate any potential impairment related to this decision during the first quarter of 2026. ARLP ended the 2025 quarter with 1.1 million tons of coal inventory representing an increase of 0.4 million and 0.1 million tons compared to the 2024 quarter and sequential quarter, respectively. In the 2025 quarter, Hamilton continued to produce record levels, accelerating completion of District 3, which we felt was necessary due to deterioration in the active leader entries. This will result in an extended longwall move that started last week while the first longwall panel in District 4 awaits completion scheduled for the first week of May 2026. In our Royalty segment, we delivered strong results during the 2025 quarter. Total revenue was $56.8 million, up 17.2% year-over-year due to higher coal royalty tons, higher revenue per ton sold and record oil and gas BOE volumes, which helped offset lower benchmark oil prices. For the full year 2025, our Oil & Gas Royalty segment achieved another record year of volumes on a BOE basis. In the 2025 quarter, BOE volumes increased 20.2% year-over-year and 10% sequentially, resulting in segment adjusted EBITDA of $30 million. As discussed last quarter, a high royalty interest, multi-well development pad in the Permian Delaware Basin was awaiting completion. Those wells were brought online during the 2025 quarter, and we are now benefiting from flush production from those recent completions. Additionally, acquisition activity picked up in the 2025 quarter and we completed $14.4 million of oil and gas minerals acquisitions. Segment adjusted EBITDA for our Coal Royalty segment increased to $14.6 million in the 2025 quarter compared to $10.5 million in the 2024 quarter due to higher royalty tons sold, primarily from Tunnel Ridge. Turning now to our strong balance sheet as well as our cash flows as of December 31, 2025, our total net leverage ratios improved to 0.66 and 0.56x debt to trailing 12 months adjusted EBITDA. Total liquidity was $518.5 million, which included $71.2 million of cash and cash equivalents on hand. Additionally, we held 592 Bitcoins valued at $51.8 million at year-end. For the 2025 quarter, after $44.8 million in capital expenditures, Alliance generated free cash flow of $93.8 million. We reported distributable cash flow of $100.1 million. And based on our $0.60 per unit quarterly cash distribution, this represented us paying out 77.7% of distributable cash flow and resulting in a distribution coverage ratio of 1.29x. Looking now to our initial 2026 guidance detailed in this morning's release. There are a few notable areas that I would like to highlight. We anticipate ARLP's overall coal sales volumes for 2026 to increase and be in the range of 33.75 million to 35.25 million tons. This guidance assumes the impact of reduced coal sales volumes at our Mettiki mine and still represents an increase in sales volumes of 0.75 million to 2.25 million tons across the Illinois Basin and at Tunnel Ridge versus 2025. Demand fundamentals continue to strengthen, supported by higher natural gas prices and low growth from data centers and U.S. manufacturing, driving increased demand for our coal supply. Contracting activity has been robust with over 93% of expected volumes in 2026, already committed and priced at the midpoint of our guidance. This is materially better than where we were 12 months ago. In total, we anticipate 2026 full year average realized coal pricing to be approximately 3% to 6% below fourth quarter 2025 levels. In the Illinois Basin, we anticipate 2026 sales pricing to be in the range of $50 to $52 per ton as compared to $52.09 in 2025 and $66 to $71 per ton for 2026 in Appalachia as compared to $81.99 per ton in 2025 which included a larger mix of higher-priced Mettiki tons. On the cost side, we expect full year segment adjusted EBITDA expense per ton to be in a range of $33 to $35 per ton in the Illinois Basin as compared to $34.71 per ton in 2025 and $49 to $53 per ton in Appalachia for 2026 and as compared to $63.82 in 2025, which included a larger mix of higher cost Mettiki tons. On a quarterly basis for 2026, it is reasonable to assume first quarter 2026 segment adjusted EBITDA expense per ton to be 6% to 10% higher than the 2025 quarter as a result of the extended longwall outage in the Illinois Basin at our Hamilton mine. Across our mining portfolio, particularly at River View and Tunnel Ridge, we expect an improvement in segment adjusted EBITDA expense per ton in 2026 and the same for Hamilton in the back half of 2026, supporting our efforts to preserve operating margins with continued cost discipline and operational execution. In our Oil & Gas Royalty segment, we expect volumes of 1.5 million to 1.6 million barrels of oil, 6.3 million to 6.7 million MCF of natural gas and 825,000 to 875,000 barrels of natural gas liquids. Segment adjusted EBITDA expense is expected to be approximately 14% of oil and gas royalty revenues. We remain committed to investing in our oil and gas royalties business, and we'll continue to pursue disciplined growth in this segment in 2026. Additionally, at the midpoint of our 2026 guidance, coal royalty tons sold are expected to be 6 million tons higher or 25% above 2025 levels, reflecting higher volumes at our Hamilton and Tunnel Ridge mines. And finally, we're expecting 2026 capital expenditures to be $280 million to $300 million. And for distribution coverage purposes, estimated maintenance capital per ton produced has been updated and is assumed to be $7.23 per ton produced in 2026 versus $7.28 per ton produced in 2025. 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. Good morning, everyone. Thank you for joining the call today. Alliance delivered solid performance during the fourth quarter and full year 2025, highlighted by resilient coal generation across our core markets, consistent operating performance from our Illinois Basin mines and tightening fundamentals throughout U.S. power markets. As Cary mentioned, we closed out the year with strong contracting activity, as we move into 2026, we have committed in price more than 93% of our projected 2026 sales tons as reflected at the midpoint of our guidance range. Utilities are increasingly often for longer-term agreements to lock in volume with reliable suppliers like Alliance as we enter a period of favorable supply-demand dynamics. Customers are prioritizing reliability, and we believe this reflects a growing recognition that future supply will not be as flexible or abundant as in past cycles. Before turning to the broader market, I do want to briefly discuss a few areas as I reflect on 2025. First, the Illinois Basin delivered a stellar quarter and year, supported by robust customer demand and continued execution of our plan to enhance mine productivity and cost performance, solidifying our positioning as the premier mining operator in the basin. Hamilton set a new record for full year clean tons in 2025. Segment adjusted EBITDA expense per ton in the region improved 14.4% quarter-over-quarter and 8.2% year-over-year driven by meaningful cost reductions at both Hamilton and Warrior. In Appalachia, we endured a number of challenges in 2025, including recent events that led to last week's difficult decision to issue a warn notice at Mettiki. At the same time, the strategic importance of Tunnel Ridge in the region continues to grow, and I am confident in our team's ability to improve execution and drive continued improvement in 2026. While Tunnel Ridge represented approximately 73% of Appalachia sales tons in 2025, it generated over 98% of the region's cash flow in 2025, underscoring its materiality and long-term value. Finally, in our Oil & Gas Royalty segment, as Cary mentioned earlier, we acquired $14.4 million of additional mineral interest during the fourth quarter of 2025, while lowering oil pricing -- while lower oil pricing as sideline many sellers and reduce the number of marketed acquisition opportunities, we remain committed to disciplined investment. Our focus is on proactively sourcing off-market bilateral opportunities and strengthening our targeted ground game efforts to expand our pipeline of attractive acquisition opportunities. Shifting to the macro. As we entered 2026, natural gas prices had softened in early January from the fourth quarter due to milder-than-normal weather. However, that softness proved short-lived. By mid-January, nationwide Arctic Blast delivered some of the coldest temperatures in years across the Midwest, Mid-Atlantic and Northeast followed immediately by a winter storm burn. These events pushed electricity demand to record winter levels as natural gas deliverability tighten and renewable output remained limited during the hours when generation was needed most. Wood Mackenzie reported that natural gas freeze-offs reached a single-day record high of 17 billion cubic feet on January 25, and regional hub pricing reached $100 per natural gas for proving once again that reliability goes hand-in-hand with affordability. By the way, our initial guidance, we have referenced today did not factor in this Arctic blast which whether experts are expecting will continue into mid-February, if not longer. During the most stressed periods over the past couple of weeks, coal-fired generation once again served as the backbone of reliability. A January 25 article in the Wall Street Journal highlighted the coal supply 40% of MISO's generation and 24% of PJM's generation during the winter event playing a critical stabilizing role across the Midwest and Mid-Atlantic. These developments mirrored exactly what NERC highlighted in its 2025-2026 Winter Reliability Assessment at resources appear adequate under normal conditions can quickly become and sufficient during widespread extreme cold, especially when fuel deliverability constraints emerge. Load growth remains one of the most significant long-term forces shaping U.S. power markets across PJM, MISO and SERC. Operators continue to project the strongest multiyear demand growth in decades, driven by the rapidly expanding data center and AI computing loads and industrial development. These fundamentals are showing up most clearly in PJM's auction capacity markets. In December '25, the base residual auction for 2027, 2028 delivered years cleared that the FERC-approved cap across all areas. The PJM still fell approximately 6.5 gigawatts short of its reliability targets as the temporary price caps limited how much capacity the market could attract. This follows 2 consecutive auctions with similarly elevated outcomes, underscoring that PJM's accredited capacity challenge is structural. Since then, FERC has begun evaluating reforms intended to curb volatility, better balance affordability and reliability and support the construction of new generation. Though the ultimate direction and time line of these reforms remain uncertain. These market developments reinforce what we have consistently communicated. Fuel secure dispatchable generation remains indispensable and coal's value to our nation's grid is increasingly being recognized by customers, energy markets and regulators. From a policy and planning perspective, these conditions underscore why a balanced resource mix that includes coal remains essential as the grid navigates rapid change to ensure the United States can win the global AI race. I want to acknowledge the Trump administration's foresight and supporting policies to preserve coal units and recognize their contribution to grid reliability. From the first day, President Trump was sworn into office 1 year ago, he understood the importance of preserving all existing base load generating units in order to protect our national security interest. Every day since the energy dominance council has worked tirelessly on this objective with particular focus on affordability, reliability and preserving the existing coal fleet as well as providing a regulatory framework that allows the operating lives of these plants to be extended. Fortunately, their leadership is making a difference. According to Americas Power, utilities in 19 states have reversed or delayed more than 31,000 megawatts of coal retirements based on low growth or reliability concerns, reinforcing that policies become increasingly aligned with real-world grid reliability needs. As we look to 2026 and beyond, we remain committed to a disciplined capital allocation framework by investing in high-return opportunities across our core operations and royalty platforms, returning capital to unitholders, all while maintaining a strong balance sheet. We believe this balanced approach positions Alliance to capitalize on strategic growth opportunities, while maintaining financial flexibility in a rapidly evolving energy landscape. I want to thank our employees for their outstanding performance throughout the year. We look forward to building on this momentum. That concludes our prepared comments, and I'll now ask the operator to open the call for questions. Operator?

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

You guys said in your prepared remarks, more than 93% committed in price for '26 based at the midpoint of guidance. With such a large chunk price, what does it take to get you to the high or low end of your price per ton guidance? I guess, in other words, what portion of your tons is still exposed to the market and could either go up or down depending on how things progress from here?

Yes. I think that most of our tons that are remaining to be sold are in the Illinois Basin. We do have a little bit at MC Mining where we got about 200,000 tons to sell, but most is in the Illinois Basin, primarily Gibson South and Hamilton. We do believe that we're well positioned. I think that one thing that we have to factor in is that some of the tons that we have committed in those basins include optionality for our customers. So even though the price has increased this quarter because of the Arctic air that we've seen and now the natural gas price is rising like they have, there should be some upside that allows for the Illinois Basin pricing to potentially end up towards the end -- at the high end of the range, if not exceeded a little bit, but that really depends on how our customers flex up contracts that we have just basically assumed in our contracted position that those are at their base levels and doesn't factor in their optionality. And I don't know exactly precisely how that trends, but I do believe it's safe to assume that as we look at the markets right now that we would be at the high end of the range on the Illinois Basin. In Appalachia, we just don't have that many tons to sell. Tunnel Ridge is basically sold out. MC, like I said, it's 200,000. And we have seen an uptick in the export markets, which is positive for MC, but that hasn't materialized yet. We did book some tons just recently, but we're anticipating that price may go a little higher. So we feel pretty good there but we just don't have it many times there to really influence what that price is going to be for -- yes, for our price ranges for Appalachia. So I'd say they will probably come in at the midpoint level.

That was very helpful. I appreciate that. Maybe a little bit bigger picture, coal -- thermal coal demand specifically continue to be supported. Utilities look more and more to contract for longer duration, as you mentioned in your prepared remarks. What would it take for Alliance to increase production. I guess where you guys kind of capped today? And what could you increase it with approximately how much investment?

I think right now, we do not plan to add any units. So the one area where we could add units is at River View, we could add a unit there. But we're not anticipating to do that. And I think that if there's any incremental demand that we could potentially just work a little bit more over time on the weekends and things of that nature. But I think our primary growth is just be an improved productivity. We're very focused on improving our productivity and specifically in the Illinois Basin. We're encouraged by some of the investments we've made in our equipment. We had the joint development agreement with Infinitum, where we're converting some of our shuttle cars to the technology utilizing Infinitum motor, and that's proving to be very attractive improvement in our productivity, and we're rolling that out with new -- our shuttle car rebuilds. So we do think that there could be an opportunity things continue to progress on the trend line that they are that we could show a little higher production in the Illinois Basin or our continuous miner operations as we focus on productivity improvements. But we're not adding or planning to add any additional capital to increase with units and things of that nature. If a customer wants to come and lockup tons for a longer term, we would consider that. But at this moment, there's no plans to do so.

Okay. Got it. And then maybe one final more modeling question maybe for Cary. Equity method investments benefited from that $17.5 million in income from your previous investment at the Gavin coal-fired power plant. Cary, any thoughts on how to model that going forward? Is it just going to be lumpy? And then maybe any updates on other potential investment opportunities like that, that you guys see in the marketplace today?

Yes. Sure, Nate. On that, I think when you look at that equity investment income, I think taking out the part associated with the increase in the fair value of the equity method investment is fair to do. So I think as you look at it on a going-forward basis, we were at $17 million here. I think a lower run rate on that more along the lines of $3 million or so per quarter is probably a fair number to take a look at here from a modeling perspective going forward, Nate.

As far as looking at other opportunities, we are evaluating other opportunities to invest in existing coal-fired generation. So that is our -- on our radar and it would be great if we could find more opportunities to deliver the results at the Gavin plant has afforded us. It's been a very good investment.

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

I wanted to talk -- ask a little bit about expected sales cadence in 2026. Obviously, Mettiki expected to come offline in March 2026. And I think you mentioned that you'll have some catch-up sales and longwall moves as well. Just at a high level, how should we be thinking about cadence and quarterly sales as we go through this year?

I think when you look at the quarterly sales, first quarter is going to be the lowest level for us throughout the year. So first level or first quarter will be on the low end. I would anticipate probably somewhere in the neighborhood, slight growth from where we were in the fourth quarter, maybe 1% to 2% in terms of total sales growth for the quarter. Second quarter should be a little bit better. We do have the extended longwall move that I mentioned at Hamilton going on really throughout the first quarter. There is a longwall move schedule for Tunnel Ridge in the second quarter, early on in the second quarter. So you should gradually get better in the second quarter. And then the last half of the year, we don't have any additional longwall moves. So those longwalls will be running full out at that particular point in time. So back half of the year volumes will be the best volumes on a quarterly basis as we look quarterly throughout the year.

Got it. That's helpful color. And in regards to export sales for 2026, I see there's roughly 1.7 million tons committed. How do you expect export sales to compare to 2025 levels? And what type of netbacks are you currently seeing in that market?

Yes. I think going forward, right now, the only exposure we would have the export market will be the MC Mining tons. I mentioned the 200,000 tons. So there's not much that we're looking at export. We're -- as always, we're primarily focused on our domestic customers, and we do believe with the demand they're going to have that they're going to need all the production that we have that's available. We do have the ability of Gibson to ship into that export market. But currently, we see the domestic market as having a higher netback. So the only shipments we have are based on what we had contracted that we're really targeting in '26. Those were based on prices that we entered into a year ago. So actual netbacks that we're looking at right now, I can't give you a number because we're not actively looking at that market other than at MC where the netbacks have been around $83, I think, or $85 for the small tonnage that we did book this month.

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

It was interesting this morning the EIA had kind of a report out on the monthly wholesale electricity prices. And just like, for example, in the Mid-Atlantic and the Midwest regions, the total generation increased 3% or 49 billion-kilowatt hours. The natural gas declined while coal generation increased by 49 billion-kilowatt hours. And so it looks like you saw a pretty healthy increases in coal in the Midwest, the Mid-Atlantic Central and even in the Southeast to some extent. And I was just kind of curious, is it still kind of a horse race between the spark spread and the dark spread or have we reached a point where for utilities, the reliability, the deliverability is more important?

Well, during this winter storm, it was definitely the reliability. There were freeze-offs. There were a lot of utilities that were curtailing some of our customers, but the coal plants were running flat out for the numerous reasons that coal does have an advantage in winter storms, we have storage on site and I think that the freeze-offs did play a role on that. I think as far as February, as I indicated earlier, with the February pricing. We continue to believe that coal burns are going to be strong in February. We are seeing March gas be very volatile. Gas prices have jumped $0.50 a day over the last week. So it's hard to predict exactly where that's going to go, but there was significant draw over the last week of natural gas in the regions where we market. So believe that both demand for data centers, the winter that we have, we're in a good position relative to coal oil and gas demand for 2026, at least through the first half of the year. And then we'll focus on the next half when we start anticipating what the weather demands in the energy demand or actual demand for electricity is in the second half of the year. But I think we're in very good shape from a coal perspective to see the demand in 2026. And as we mentioned, we do believe that supply is pretty limited. I mean, supply increase is limited. So that should bode well on a supply-demand balance as far as pricing. As we roll into the midyear and start thinking about pricing for '27 going forward.

Yes, I would think so. I may be looking at this wrong, but I was just kind of curious, the guidance on the total sales tons for coal versus the royalty tons sold, I mean, there was a bigger delta between the, say, the 2025 guidance and the 2026 guidance between those 2 segments? What was driving that?

So when we're looking at '26.

I think your -- for '26 for royalty tons, you're 30 million to 30.8 million. I think '25 guidance is 23.5 million to 24.50 million. So that's a pretty big delta, whereas the total sales tons was 32.5 million to 33.25 million last year, now it's 33.75 million and 35.25 million.

Yes. I think, Mark, I think what the biggest delta is in there in terms of coal royalty tons and the increase that you're seeing is the movement over at Tunnel Ridge into the new district is leading to higher coal royalty volumes associated with that new district. So that new district does have -- we do lease those -- Tunnel Ridge does lease those from our coal royalty division there. And then additionally, we've got higher volumes projected coming from our Hamilton operation as well. And so those are the 2 primary differences that are leading to the increase in the guidance range. The largest of which is going to be a Tunnel Ridge. Really, all of the Tunnel Ridge volumes now that we will be selling will flow into our coal royalties area.

That was based on an acquisition we did a couple of years ago that reserves and district.

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

Congratulations on all the visibility for coal over the past few weeks. Coming to my questions, you referred briefly to 2027 pricing. With demand increasing the way it's been, are you seeing firmer pricing? And could you put any color behind that?

Of the tons that we contracted this year over this last quarter, I think we did contract 1.5 million tons in 2027. And that tonnage did price a little bit higher than the high end of our range that we got right at the high end of the range for 2026. It was a little higher than what our fourth quarter sales prices were going in the out years, we have 1 contract that actually is a 5-year contract. So we are seeing increases on a yearly basis for that contract. We had 2 other contracts that were 3 years, '26, '27, '28 time frame. So those prices mostly -- they were all in the Illinois Basin and they were priced at the high end of our 2026 range in '27, and then they got a little higher than that in '28 going forward. So that, again, as I mentioned in our guidance, we really didn't reflect what we saw with the Arctic weather and the higher gas prices. So if we were to contract today, those prices would be higher, and how long that sustains itself is totally dependent on energy demand and what gas prices do going forward.

Well, and trying to look at longer-term demand factors, inventory of coal held at power plants was significantly down in '25, a big burn off already here in Q1 '26. Do you see inventories at this level just kind of making where you were last year almost a trough in pricing and we should look at just higher pricing going forward for the new normal?

I think so. I think that, again, the supply is limited. I don't think we're going to see supply growth. We're actually seeing some mines that will deplete over the next 3 years. I don't believe that those companies are going to recap to try to maintain that volume. So I do see supply pretty flat to trending down for the domestic Eastern markets. And I believe the demand is going to go up. We've seen the extra capacity, these coal units have available based off the coal burn we've seen in January and as demand goes up for data centers, and those data centers are completed. I expect that our energy demand for coal for data centers will, in fact, go up. So that should put us in a favorable supply/demand perspective that would support higher pricing.

Well, great. That's very helpful. So good luck on coming quarters.

Thank you.

Thank you.

Thank you. At this time, we've reached the end of our question-and-answer session. I'll hand the floor back to Cary Marshall for closing comments.

Thank you, operator. To everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our first quarter 2026 financial and operating results currently expected to occur in April, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you.

Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines at this time, and have a wonderful day.