Alliance Resource ARLP Earnings Call Transcript

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Date

Monday, Feb. 2, 2026 at 10 a.m. ET

Call participants

• Senior Vice President and Chief Financial Officer — Cary Marshall
• Chairman, President, and Chief Executive Officer — Joseph Craft

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Takeaways

• Adjusted EBITDA -- $191.1 million, up 54.1% year over year and 2.8% sequentially, driven by lower expenses, lower impairments, and investment income.
• Net income attributable to ARLP -- $82.7 million, or $0.64 per unit, compared to $16.3 million, or $0.12 per unit, year over year, reflecting improved operating leverage and investment gains.
• Total revenues -- $535.5 million, down from $590.1 million year over year, primarily due to weaker coal sales and transportation revenues, partially offset by record oil and gas royalty volume.
• Coal sales price per ton -- $57.57, representing a decrease of 4% year over year and 2.1% sequentially as higher-priced legacy contracts roll off.
• Total coal production -- 8.2 million tons, up from 6.9 million tons year over year; wholesale volumes were 8.1 million tons, down from 8.4 million year over year and 8.7 million sequentially.
• Coal segment adjusted EBITDA expense per ton sold -- $40.24, decreasing 16.3% year over year and 1.8% sequentially, reflecting operational improvements.
• Illinois Basin coal sales volumes -- 6.5 million tons, down approximately 2% year over year and sequentially, mainly due to timing of committed deliveries.
• Illinois Basin segment adjusted EBITDA expense per ton -- Decreased 14.4% year over year and 3.8% sequentially, attributed to higher output at Hamilton and fewer longwall move days.
• Appalachia coal sales volumes -- 1.7 million tons, reflecting declines from both year over year (1.8 million) and sequential (2.1 million) periods, due to Metiki outages and Tunnel Ridge support block issues.
• Metiki mine customer impact -- "They are not in a position to commit to purchase any additional tons from Metiki for the foreseeable future," triggering WARN Act notices and the expectation that production will cease after March 2026.
• Coal inventory -- 1.1 million tons at quarter end, rising by 0.4 million and 0.1 million tons from year over year and sequential comparisons, reflecting production timing.
• Royalty segment revenue -- $56.8 million, up 17.2% year over year; the segment delivered record oil and gas BOE volumes and higher coal royalty tons.
• Oil and gas royalty BOE volumes -- Increased 20.2% year over year and 10% sequentially; segment adjusted EBITDA was $30 million.
• Oil and gas minerals acquisitions -- $14.4 million completed in the quarter, contributing to record annual BOE volumes.
• Coal royalty segment adjusted EBITDA -- $14.6 million, up from $10.5 million year over year, driven by Tunnel Ridge volumes.
• Net leverage ratios -- Debt to trailing-twelve-month adjusted EBITDA improved to 0.66x and 0.56x, supporting balance sheet strength.
• Total liquidity -- $518.5 million, including $71.2 million in cash and 592 Bitcoins valued at $51.8 million as of year-end.
• Free cash flow -- $93.8 million after $44.8 million in capital expenditures; distributable cash flow was $100.1 million, with $0.60 per unit quarterly cash distribution, covering 77.7% of distributable cash flow and yielding a distribution coverage ratio of 1.29x.
• 2026 coal sales volume guidance -- 33.75 million to 35.25 million tons, including the impact from reduced Metiki mine volumes but still reflecting an increase of 0.75 million to 2.25 million tons from the Illinois Basin and Tunnel Ridge year over year.
• 2026 pricing guidance -- Full-year average realized coal pricing is expected to be 3%-6% below fourth quarter 2025 levels; Illinois Basin projected at $50-$52 per ton and Appalachia at $66-$71 per ton for 2026.
• 2026 coal segment adjusted EBITDA expense per ton guidance -- Illinois Basin targeted at $33-$35 per ton, Appalachia at $49-$53 per ton; maintenance capital per ton assumed at $7.23.
• 93% of 2026 sales committed -- Over 93% of 2026 projected coal volumes are already committed and priced at the midpoint of guidance as of the call.
• Oil and gas royalty 2026 volume guidance -- Anticipated at 1.5 million to 1.6 million barrels of oil, 6.3 million to 6.7 million cubic feet natural gas, and 825,000 to 875,000 barrels of NGLs; segment adjusted EBITDA expense forecasted at approximately 14% of royalty revenues.
• 2026 capital expenditures -- Expected between $280 million and $300 million.

Risks

• Metiki mine's principal customer cannot commit to "any additional tons from Metiki for the foreseeable future," forcing WARN Act notices and a post-March 2026 production halt, with no clear replacement customer identified.
• "The anticipated impact of reduced sales volumes at Metiki is reflected in our 2026 guidance," and a potential impairment review is planned during 2026 due to the loss of this large customer contract.
• Extended longwall move at Hamilton mine started in late fourth quarter 2025, leading to higher segment adjusted EBITDA expense per ton by 6%-10% in first quarter 2026 and depressed early 2026 sales volumes.

Summary

Alliance Resource Partners (NASDAQ:ARLP) reported higher adjusted EBITDA and net income, with lower operating costs, reduced impairment charges, and investment income offsetting a year-over-year revenue decline from weaker coal sales and prices. Management stated that more than 93% of 2026 coal sales volumes are already contracted at guidance midpoints, and provided detailed pricing and cost guidance reflecting the transition from legacy contracts and the permanent loss of the Metiki mine's key customer. Oil and gas royalty volumes reached all-time highs, acquisitions continued, and both royalty segments contributed increased EBITDA, supporting substantial liquidity and low leverage metrics. Strategic commentary focused on continued capital discipline, production improvements—particularly in the Illinois Basin—and the support longer-term utility agreements provide in an evolving and constrained coal supply environment.

• Management indicated that additional upside in Illinois Basin pricing for 2026 is possible given current market trends and embedded contract optionality, stating, "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, 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."
• No new mine unit investments are planned, with volume increases expected primarily through productivity initiatives and equipment upgrades such as shuttle car technology.
• Recent coal contracts for 2027 and beyond have been signed above current guidance ranges, signaling incremental price strength in future delivery years.
• Export coal sales for 2026 are limited to small MC Mining volumes, with current domestic netbacks seen as more attractive; export netbacks referenced as "the netbacks have been around $83, I think, or $85 for the small tonnage that we did book this month."
• Quarterly coal sales volumes in 2026 will be lowest in the first quarter, increase modestly in the second, and peak in the back half as longwall move disruptions abate.

Industry glossary

• Longwall move: Temporary production stoppage in an underground mine during the repositioning of extraction equipment to a new panel, affecting output and cost metrics.
• BOE: Barrels of oil equivalent—a standardized unit for aggregating oil, natural gas, and condensate volumes.
• Netbacks: The per-ton or per-unit profit realized from coal sales after subtracting transportation and other direct costs.
• WARN Act notices: Advance notifications required under the Worker Adjustment and Retraining Notification Act when substantial workforce reductions are imminent due to lost customer commitments.

Full Conference Call Transcript

Operator: Greetings. Welcome to Alliance Resource Partners Fourth Quarter 2025 Earnings Conference Call. At this time, all participants will be in listen-only mode. A question and answer session will follow the formal presentation. 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.

Cary Marshall: 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, or 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-Ks. 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 2025, which we refer to as the 2025 quarter, adjusted EBITDA was $191.1 million, up 54.1% from the 2024, which we refer to as the 2024 quarter, and up 2.8% compared to the 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¢ per unit, as compared to $16.3 million, or 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 volume.

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. Wholesale 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 16.31.8% 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 and 2.1 million tons in the 2024 and sequential quarters, respectively. This decrease was caused primarily by timing of committed sales at our Metiqui mine and Tunnel Ridge volumes that were impacted by December longwall jump necessitated by a block of support pole 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 Metiqui 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 plan 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. Metiqui 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 Metiqui was approximately $3.5 million. The anticipated impact of reduced sales volumes at Metiki is reflected in our 2026 guidance. Additionally, the partnership will evaluate any potential impairment related to this decision during the 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 May 2026. Our royalty segments 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 add 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 12/31/2025, our total on net leverage ratios improved to 0.66 and 0.56x debt to trailing twelve 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¢ per unit quarterly cash distribution, this represented us paying out 77.7% of the 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, be in the range of 33.75 to 35.25 million tons.

This guidance assumes the impact of reduced coal sales volumes at our Metiqui 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 US 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 twelve 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 Metiqui tons.

On the cost side, we expect full year segment 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 Metiqui 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 2026, supporting our efforts to preserve operating margins, 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 liquid. 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.

Cary Marshall: Additionally, at the midpoint of our 2026 guidance, coal royalty tons sold are expected to be 6 million tons higher or 25% above 2025 level, reflecting higher volumes at our Hamilton and Tunnel Ridge mine. 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.

Joseph Craft: Thank you, Cary, and 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 US power markets. As Cary mentioned, we closed out the year with strong contracting activity. As we move into 2026, we have committed and priced 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 price cycles. Before turning to the broader market, I do want to briefly discuss a few areas as I reflect on 2025. First, 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 warrant notice at Metiki. 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 and gas royalty segment, as Cary mentioned earlier, we acquired $14.4 million of additional mineral interest during 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 25, and regional hub pricing reached $100 for natural gas, 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 25 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 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 significant long-term forces shaping US power markets. Across PJM, MISO, and SERC, operators continue to project the strongest multiyear demand growth in decades, driven by a rapidly expanding data center, AI computing loads, and industrial development. These fundamentals are showing up most clearly in PJM's auction capacity markets.

In December 2025, the base residual auction for 2027, 2028 delivery 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 is becoming 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 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: Thank you. We'll now be conducting a question and answer session. If you like to ask a question at this time, please press 1 on your telephone keypad, and a confirmation tone will indicate your line is in the question queue. You may press 2 if you'd like to remove your question from the queue. For participants who are 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.

Nathan Martin: Morning. Thanks, operator. Good morning, Joe. Good morning, Cary.

Joseph Craft: Morning, Nate. Morning.

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

Joseph Craft: Thanks. Yeah. So 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, 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 their base levels and doesn't factor in their optionality.

And I, you know, 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. And Appalachia, we just don't have that many tons to sell. Tunnel Ridge is basically route. MC, like I said, it's 200,000. And 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. 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 gonna be for our price ranges for Appalachia. So I'd say they will probably come in at the midpoint level.

Nathan Martin: And so that was very helpful. I appreciate that. Maybe a little bit bigger picture. If coal thermal coal demand specifically continued to be supported, utilities look, you know, 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, you know, where are you guys kinda capped today? And what could you increase into with, you know, approximately how much investment?

Joseph Craft: 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 doing that. And 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 just being improved productivity. We're very focused on improving our productivity and specifically in Illinois Basin. We're encouraged by some of the investments we've made in our equipment.

You know, 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 a very attractive improvement in our productivity, and we're rolling that out with new, you know, 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, 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 lock up tons for a longer term, we would consider that. But at this moment, there's no plans to do so.

Nathan Martin: Okay. Got it. Thank you for that. 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 gonna be lumpy? And then maybe any updates on other potential investment opportunities like that you guys see in the marketplace today? Thank you.

Cary Marshall: Yeah. Sure. Sure, Nate. On that, I think when you look at that equity investment income, you know, I think, yeah, taking out the part associated with the increase in the fair value of the equity method investment, you know, is fair to do. I think as you look at it on a going forward basis, you know, we were at $17 million here. You know, I think a lower run rate on that, you know, more along the lines of, you know, $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 that deliver the results that the Gavin plant has afforded us. It's been a very good investment.

Nathan Martin: Okay. Great. I'll leave it on. Appreciate the time, Joe, and best of luck.

Joseph Craft: Thank you, Nate.

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

Matthew Key: I wanted to talk, ask a little bit about expected sales cadence in 2026. Obviously, Metiqui expects 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?

Cary Marshall: I think when you look at the quarterly sales, first quarter is gonna be the lowest level for us throughout the year. So first quarter will be, you know, on the low end. I would, you know, anticipate probably somewhere in the neighborhood of slight growth from where we were in the fourth quarter. You know, maybe 1% to 2% in terms of total sales growth for the quarter. You know, second quarter should be a little bit better. We do have the extended longwall move that I mentioned at Hamilton going on, you know, really throughout the first quarter. There is a longwall 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 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, you know, as we look quarterly throughout the year.

Matthew Key: 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 net are you currently seeing in that market?

Joseph Craft: Yeah. 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. We're, as always, you know, 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 higher netbacks. The only shipments we have are based on what we've had contracted that we're really targeting in 2026.

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.

Matthew Key: Got it. That's helpful. Thank you for your time, and best of luck moving forward.

Joseph Craft: Thank you, Matt.

Operator: Our next question is from the line of Mark Bickman with Noble Capital Markets. Proceed with your questions.

Mark Bickman: 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 that 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 pretty healthy increases in coal in the Midwest, the Mid-Atlantic, Central, and even in the Southeast to some extent.

And I was just kinda 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?

Joseph Craft: 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 numerous reasons that, you know, coal does have an advantage in winter storms, you know, because we have storage on-site, and I think that, you know, the freeze-off did play a role in that. I think as far as February, as I indicated earlier, you know, with the February pricing, we continue to believe that coal burns are gonna be strong in February. We are seeing March gas be very volatile. Gas prices have jumped 50¢ a day over the last week.

So it's hard to predict exactly where that's gonna go. But there was significant draw over the last week of natural gas in the regions where we market. So we believe that both demand for data centers and the winter that we have, we're in 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 energy demand or 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 that the demand in 2026, and as we mentioned there, 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 mid-year and start thinking about pricing for '27 going forward.

Mark Bickman: Yeah. I would think so. I may be looking at this wrong, but I was just kinda 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 the, say, the 2025 guidance and the 2026 guidance, you know, between those two segments. What was driving that?

Cary Marshall: So when we're looking at '26, you were kind of, I think you were for '26 for royalty tons, you're 30 to 30.8. I think 25 guidance is 23.5 to 24.5. So that's a pretty big delta, whereas the total sales tons, you know, was 32.5 to 33.25 last year. Now it's 33.75 and 35.25.

Joseph Craft: 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 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 two primary differences that are leading to the increase in the guidance range. The largest of which is gonna be at 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.

Mark Bickman: Okay. No. That's very helpful. Thank you very much.

Joseph Craft: Thank you, Mark.

Operator: Thank you. The next question is from the line of Michael Matheson with Sidoti and Company. Please proceed with your questions.

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

Joseph Craft: Thank you.

Michael Matheson: 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?

Joseph Craft: Well, the tons that we contracted, you know, 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've got right in the 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 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've 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.

Michael Matheson: Well, in trying to look at longer-term demand factors, inventory of coal held at power plants was significantly down in 2025. Big burn-off already here in Q1 2026. 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?

Joseph Craft: I think so. I think that, again, the supply is limited. I don't think we're gonna 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 gonna 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's gonna 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.

Michael Matheson: Well, great. That's very helpful. So thank you and good luck in coming quarters.

Joseph Craft: Thank you. Thank you.

Operator: At this time, we've reached the end of our question and answer session. I hand the call back to Cary for closing comments.

Cary Marshall: 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 and operating results is currently expected to occur in April. We hope everyone will join us again at that time. This concludes our call for the day.

Operator: 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.

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