Alliance Resource Partners, L.P.

Greetings. Welcome to Alliance Resource Partners' fourth quarter 2025 earnings conference call. At this time, all participants will be in listen-only mode. The question and answer session will follow the formal presentation. If anyone today should require operator assistance during the conference, please press star zero from your telephone keypad. Please note this conference is being recorded.

At this time, 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, 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 8K. 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 turned the call over to Joe Kraft, 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 64 cents per unit as compared to 16.3 million or 12 cents 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 revenues 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 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 to Hamilton, resulting from fewer long haul 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 and 2.1 million tons in the 2024 and sequential quarters, respectively. This decrease was caused primarily by timing of committed sales at our Metiki mine and Tunnel Ridge volumes that were impacted by December longwall junk necessitated by a block of support coal needed to be left beneath four 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 Metiki 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 Metiki, 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 plant expects additional outages during 2026, and they are not in a position to commit to purchase any additional tons from Metiki for the foreseeable future. Metiki 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. Medtiki 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 Medtiki was approximately $3.5 million. The anticipated impact of reduced sales volumes at Medtiki 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 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 the 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 segments, 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 and 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 31st, 2025, Our total and net leverage ratios improved to 0.66 and 0.56 times 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 60 cent per unit quarterly cash distribution, this represented us paying out 77.7% of distributable cash flow and resulting in a distribution coverage ratio of 1.29 times. 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 to 35.25 million tons. This guidance assumes the impact of reduced coal sales volumes at our Metiki mine and still represents an increase in sales volumes of 0.75 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 metiki 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 as compared to $63.82 in 2025, which included a larger mix of higher cost metiki 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 Riverview 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 and gas royalty segment, we expect volumes of 1.5 to 1.6 million barrels of oil, 6.3 to 6.7 million CF of natural gas, and 825 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 will 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 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, Kerry. Good morning, everyone. Thank you for joining the call today. Alliance delivered solid performance during the fourth quarter and full year of 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 Kerry 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 opting 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 warned notice at Metiki. At the same time, the strategic importance of Tunnel Ridge and 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 and gas royalty segment, as Kerry mentioned earlier, we acquired $14.4 million of additional mineral interest during the fourth quarter of 2025. While lower oil pricing has sidelined many sellers and reduced 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, a nationwide Arctic blast delivered some of the coldest temperatures in years across the Midwest, Mid-Atlantic, and Northeast, followed immediately by a winter storm fern. These events pushed electricity demand to record winter levels as natural gas deliverability tightened 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 25th, and regional hub pricing reached $100 for natural gas per 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 weather 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 25th article in the Wall Street Journal highlighted that coal supplied 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. that resources that appear adequate under normal conditions can quickly become insufficient 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 CERC, operators continue to project the strongest multi-year 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 at the FERC approved cap across all areas. but 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 two 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 timeline 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 in supporting policies to preserve coal units and recognize their contribution to grid reliability. From the first day President Trump was sworn into office one 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 America's 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 policy has 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 unit holders, 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?

Thank you. We'll now be conducting a question and answer session. If you'd like to ask a question at this time, please press star 1 on your telephone keypad, and a confirmation tone will indicate your line is in the question queue. You may press star 2 if you'd like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. One moment, please, while we poll for our first question. Thank you. Thank you. And the first question is from the line of Nathan Martin with Benchmark Company. Please proceed with your question.

Good morning. Thanks, operator. Good morning, Joe. Good morning, Kerry. Good morning, Nate.

Good morning.

Good morning. As 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?

Thanks. 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've 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 times 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 pricings to potentially increase. end up uh towards the end you know 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 you know at their base levels and doesn't factor in their optionality and i you know i don't 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 Illinois Basin. In Appalachia, we just don't have that many tons to sell. Tunnel Ridge is basically sold out. MC, like I said, is 200,000. 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 that many tons there to really influence what that price is going to be for our price ranges there for Appalachia, so I'd say they will probably come in at the midpoint level.

Joe, that was very helpful. I appreciate that.

Maybe a little bit bigger picture. If coal, thermal coal demands specifically continue to be supported, utilities look more and more to contract for a longer duration, as you mentioned in your prepared remarks, what would it take for Alliance to increase production I guess, where are you guys kind of capped today, and what could you increase to 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 Riverview. We could add a unit there, but we're not anticipating to do that. I think that if there's any incremental demand that we could potentially just work a little bit more overtime on the weekends and things of that nature. But I think our primary growth is going to 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 the infinite motor, and that's proving to be a very attractive improvement in our productivity, and we're rolling that out with new shuttle car rebuilds, so we do think that there could be an opportunity if things continue to progress on the trend line that they are, that we could show a little higher production in Illinois Basin for our continuous mine 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 lock up tons for a longer term, we would consider that. But at this moment, there's no plans to do so.

Okay, got it. Thank you for that. And then maybe one final more modeling question maybe for Kerry. Equity method investments benefited from that $17.5 million in income. from your previous investment at the Gavin coal-fired power plant. Kerry, 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? Thank you.

Yeah, sure. Sure, Nate, on that. I think when you look at that equity investment income, you know, 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 on our radar, and it would be great if we could find more opportunities to deliver the results that the Gavin plant has afforded us.

It's been a very good investment. Okay, great. I'll pass it on. I appreciate the time, and best of luck. Thank you, Nate.

Our next question is from the line of Matthew Key with Texas Capital. Please proceed with your questions.

Good morning, everyone, and thanks for taking my questions. I wanted to talk... ask a little bit about expected sales cadence in 2026. Obviously, Metiki expected to come offline in March 2026, and I think you mentioned that you'll have some catch-up sales and long-haul 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 First quarter will be on the low end. I would anticipate probably somewhere in the neighborhood. Flight 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 long-run move that I mentioned at Hamilton going on. you know, really throughout the first quarter, there is a long wall move scheduled 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 long wall moves. So those long walls will be be running um full out at that particular point in time so back half of the year volumes will be will be the the best best volumes on a quarterly basis uh you know as we look quarterly throughout the year got it that's that's helpful color um 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?

I think going forward, right now, the only exposure we would have to 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. 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 of the production that we have that's available. We do have the ability at Gibson to ship into that export market, but currently we see the domestic market as having a higher net back, so the only shipments we have are based on what we've contracted that we're really targeting in 26, and those were based on prices that we entered into a year ago. So the 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.

gut it. That's helpful. Thank you for your time and best of luck moving forward. Thank you, Matt.

Our next question is in the line of Mark with Noble Capital Markets. Please proceed with your question.

Good morning. You know, it's 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 Toll generation increased 3% or 49 billion kilowatt hours. But natural gas declined while coal generation increased by 49 billion kilowatt hours. And so it looks like you saw 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... You know, is it still kind of a horse race between the spark spread and the dark spread, or have we reached a point where, you know, for utilities, the reliability, you know, the deliverability is more important?

Well, during this winter storm, it was definitely the reliability. There were freeze-offs. There were a lot of, you know, 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 because we have storage on site. 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 prices be very volatile. Gas prices have jumped 50 cents 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. I believe that both demand for data centers, the winner that we have, we're Good position relative to coal 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 and the 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. As we mentioned, we do believe that supply is pretty limited. I mean, supply increase is limited, so that should bode well on supply-demand balance as far as pricing as we roll into the midyear and start thinking about pricing for 27 going forward.

Yeah, I would think so. I may be looking at this wrong, but I was just kind of curious, you know, the guidance on the total sales tons for coal versus the royalty tons sold. I mean, there was a bigger delta. between, say, the 2025 guidance and the 2026 guidance, you know, between those two segments? What was driving that? So when we're looking at 2026, I think you were kind of, I think you were, for 2026 for royalty tons, you're 30 to 30.8. I think 2025 guidance was 23.5 to 24.50. So that's a pretty big delta, whereas the total sales tons, you know, it was 32.5 to 33.25 last year. Now it's $33.75 and $35.25.

Yeah, 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 Tonal Ridge into the new district is leading to higher prices. Higher coal royalty volumes associated with that 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 two 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 years ago of reserves in that district.

Okay. No, that's very helpful. Thank you very much. Thank you, Mark.

Thank you. The next question is from the line of Michael Matheson with Sidonian Company. Please proceed with your questions.

Good morning, you guys, and congratulations on all the visibility for coal over the past few weeks.

Thank you.

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?

tons that we contracted this year over this last quarter. I think we did contract 1.5 million tons in 2027, and that kind of 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 had one contract that actually was a five-year contract, so we are seeing increases on a yearly basis. For that contract, we had two other contracts that were three years, you know, 26, 27, 28 timeframe. 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. Now how long that sustains itself is totally dependent on energy demand and, you know, what gas prices do going forward.

Well, in 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 model?

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 three 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 trending down. for the domestic eastern markets, and I believe the demand's 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 in a favorable supply-demand perspective that would support higher pricing.

Well, great. That's very helpful. So, thank you, and good luck in 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 Kerry 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 of 2026 financial and operating results is 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. We disconnect your lines at this time and have a wonderful day.