Operator: Greetings, and welcome to the Alliance Resource Partners First Quarter 2026 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Cary Marshall, Chief Financial Officer of Alliance Resource Partners. Thank you, sir. You may begin.

Cary Marshall: Thank you, operator. Good morning, and welcome, everyone. Earlier today, Alliance Resource Partners released its first quarter 2026 financial and operating results. We will review the quarter, discuss our perspective on current market conditions and outlook for 2026 and then open the call to answer your questions. Before beginning, a reminder that some of our remarks today may include forward-looking statements, which are 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-K. With that, I will begin with a review of our first quarter 2026 results and discuss our updated outlook for 2026 before turning the call over to Joe Craft, our Chairman, President and Chief Executive Officer, for his comments.

Overall, the quarterly results came in higher than expected due to record BOE volumes and higher commodity prices that increased oil and gas royalties revenues. Tons produced from our coal operations were on target. However, temporary weather-related disruptions caused approximately 200,000 tons of scheduled shipments to be delayed. For the first quarter of 2026, which we refer to as the 2026 quarter, adjusted EBITDA was $155 million, which was higher than expected but 3.1% lower compared to the first quarter of 2025, which we refer to as the 2025 quarter and down 18.9% compared to the fourth quarter of 2025, which we refer to as the sequential quarter. Net income attributable to ARLP in the 2026 quarter was $9.1 million or $0.07 per unit as compared to $74 million or $0.57 per unit in the 2025 quarter.

Net income in the 2026 quarter reflected lower coal sales revenue, higher depreciation, an $11.6 million decrease in the fair value of our digital assets and a $37.8 million noncash asset impairment charge at our Mettiki mine following our decision to cease longwall production on account of uncertainty regarding future operations as discussed in our January 29 press release. We continue to evaluate the appropriate path forward for Mettiki though meaningful uncertainty remains and greater clarity is not expected until later this year. In the interim, our priority at Mettiki is to reduce costs while preserving the flexibility and optionality needed to align future operations with customer demand. In the 2026 quarter, total revenues were $516 million, down 4.5% compared to the 2025 quarter and down 3.6% compared to the sequential quarter.

Lower coal sales pricing and volumes sequentially primarily drove the decline, which was partially offset by higher oil and gas royalty revenues. During the quarter, weather-related river disruptions delayed certain committed deliveries, however, we expect our delayed shipments will be recovered over the balance of the year. Our average coal sales price per ton for the 2026 quarter was $56.40, a 6.5% decrease versus the 2025 quarter and a 2% decrease sequentially. As noted during prior calls, pricing is normalizing as higher-priced legacy coal contracts entered into during the 2022 energy crisis, continue to roll off and are being replaced at coal pricing levels consistent with our current guidance ranges. Total coal production in the 2026 quarter was 8 million tons compared to 8.5 million tons in the 2025 quarter.

Coal sales volumes were 7.9 million tons in the 2026 quarter up from 7.8 million tons in the 2025 quarter and down from 8.1 million tons in the sequential quarter. In the Illinois Basin, coal sales volumes were 6.1 million tons, up 0.4% compared to the 2025 quarter and down 5.9% compared to the sequential quarter. Volumes declined primarily due to decreased tons sold from our Hamilton Mine as a result of an extended longwall move scheduled during the 2026 quarter. While the longwall move at Hamilton reduced production and shipments during the quarter, increased productivity at River View and Gibson South helped to offset some of that impact. The longwall at Hamilton is currently anticipated to resume production in the first half of May 2026.

Illinois Basin coal sales price per ton was $51.05 in the 2026 quarter, a decrease of 7.4% versus the 2025 quarter and an increase of 0.4% compared to the sequential quarter. The decrease versus the 2025 quarter was the result of the expiration of higher-priced legacy [ contracts]. Segment adjusted EBITDA expense per ton in the Illinois Basin was $35.20, an increase of 1.3% compared to the 2025 quarter and up 3.4% sequentially due primarily to the extended longwall move at our Hamilton Mine this quarter. In our Appalachia region, coal sales volumes were 1.8 million tons in the 2026 quarter up 3.6% compared to the prior year due to a longwall move at our Tunnel Ridge mine in the 2026 quarter. Appalachia coal sales price per ton was $74.51, reflecting an expected decrease of 4.8% versus the 2025 quarter and 11.1% versus the sequential quarter as the percentage of higher-priced Mettiki sales volumes were lower and Tunnel Ridge sales volumes increased during the 2026 quarter.

Segment adjusted EBITDA expense per ton in Appalachia was $62.19, a decrease of 10.8% versus the 2025 quarter and a decrease of 1.8% versus the sequential quarter. The year-over-year improvement was driven primarily by increased production at our Tunnel Ridge operation. ARLP ended the 2026 quarter, with total coal inventory of 1.2 million tons, down 0.2 million tons year-over-year and up 0.1 million tons sequentially. In our royalties segments, we delivered strong results during the 2026 quarter. Total royalty revenues were $61.2 million, up 16.1% year-over-year and up 7.7% sequentially. In our Oil & Gas Royalties segment, we achieved another record quarter. Oil and gas royalty revenues were $41.3 million in the 2026 quarter, up 14.6% year-over-year.

We reported record BOE volumes of $1 million, up 16.1% year-over-year and 3.3% sequentially. Commodity pricing increased sequentially and segment adjusted EBITDA for the Oil & Gas Royalty segment increased to $34.6 million in the 2026 quarter, up over 15% compared to both the 2025 quarter and sequential quarter. Segment adjusted EBITDA for our Coal Royalty segment was $12.3 million in the 2026 quarter, up 30.6% compared to the 2025 quarter due to higher royalty tons sold primarily from Tunnel Ridge. This was partially offset by lower average royalty rates per tons sold. Our balance sheet continues to be strong. As of March 31, 2026, total debt and finance leases were outstanding in the amount of $507.7 million, and our total and net leverage ratios were 0.73 and 0.69x debt to trailing 12 months adjusted EBITDA.

Total liquidity was $431.2 million, which included $28.9 million of cash and cash equivalents on hand and $402.3 million of borrowings available under our revolving credit and accounts receivable securitization facilities. We also held 618 Bitcoin valued at $42.2 million at quarter end based on $68,233 per coin. For the 2026 quarter, we invested $95.7 million in capital expenditures and $16.2 million in total oil and gas minerals acquisitions. We reported distributable cash flow of $77.8 million. Based on our $0.60 per unit quarterly cash distribution, distributions paid to partners were $78 million and our distribution coverage ratio for the quarter was 1x. Turning to our updated 2026 guidance. I will highlight 3 items. First, we are maintaining our overall guidance ranges for coal sales volumes, coal sales price and segment adjusted EBITDA expense per ton.

We will complete planned longwall move activity for the year during the upcoming quarter. And with no additional longwall moves anticipated until the first quarter of 2027, we expect better operational visibility in the second half of 2026. As usual, we plan to update investors again when we release second quarter earnings. Second, contracting activity has remained constructive. We layered on $2.6 million net contracted tons for delivery in 2026 and 2027. As a result, our 2026 expected coal sales volumes are now more than 95% committed and priced at the midpoint of our guidance ranges. The remaining open position is concentrated in the second half of 2026 and dependent upon summer burn and customer requirements. Finally, the most notable changes to our guidance are in the Oil & Gas Royalty segment, where year-to-date volumes have exceeded our initial expectations.

Based on that outperformance, we are increasing our 2026 volume guidance by approximately 5% on a BOE basis. We now estimate 1.6 million to 1.7 million barrels of oil, 6.6 million to 7 million MCF of natural gas and 875,000 to 925,000 barrels of natural gas liquids. Latest trends in crude oil pricing have improved the near-term outlook. And if current strip pricing is realized, we expect realized BOE prices to be higher than last year, supporting stronger segment adjusted EBITDA. And with that, I’ll turn the call back to Joe for his comments on the market environment in our outlook. Joe?

Joseph Craft: Thank you, Cary. Good morning, everyone. Thank you for joining the call today. Alliance delivered a solid first quarter with adjusted EBITDA exceeding our internal target due to record BOE volumes and higher commodity prices that increased oil and gas royalty’s revenues. Our coal operations results were generally in line with our expectations despite weather-related shipment disruptions and the planned extended longwall move at Hamilton. As Cary said earlier, we expect the first quarter shipment disruptions tied to winter storm burn and subsequent high water conditions to be recovered over the balance of the year. During the quarter, our teams executed well across the portfolio, including health and safety results that rank as one of our best quarters over the past 5 years.

In the Illinois Basin, increased production at River View and Gibson South helped offset the lower production we expected at Hamilton as a result of the planned extended longwall move. In late March, we also successfully completed the final phase of our multiyear River View to Henderson County minor unit transition, bringing the Henderson County mine up to its planned full production capacity of 6 super sections and River View is now positioned to operate 3 super sections moving forward. In Appalachia, Tunnel Ridge returned to steady longwall production with production increasing approximately 28% compared to both the 2025 quarter and the sequential quarter. Operationally, these results reflect the value of the recapitalization work we’ve done across the portfolio over the past several years.

Those investments are helping us realize productivity gains access new reserves efficiently and maintain a low-cost operating base to serve our customers’ needs well into the next decade. Looking more broadly at the market, several themes shaped conditions during the quarter. First, Winter Storm Fern and the extended feeding weather across the Eastern United States, once again highlighted the critical role coal plays in maintaining grid reliability during extreme weather. According to Americas Power, coal-fired generation in several Eastern regions operated at capacity factors approaching 80% during peak periods, materially outperforming natural gas and renewable resources when electricity demand was highest. While storm-related incremental coal burn didn’t fully offset milder conditions throughout the quarter, utility stockpiles generally remain aligned with our burn projections entering the year.

And summer weather will ultimately drive spot market activity for the balance of 2026. Second, the conflict involved in Iran briefly improved a previously quiet export market. In the weeks following the complex, traders reacted quickly to dislocations in API 2 pricing allowing Alliance to capitalize on a narrow window for export sales by securing 2 million tons of commitments to be delivered over 2026 and 2027. While API 2 prices have since softened, the complex test contributed to higher global oil prices, which continues to be supportive of our Oil & Gas Royalty segment. Beyond these shorter-term market dynamics, we continue to see longer-term structural support for coal-fired generation. Load growth remains one of the most significant forces reshaping U.S. power markets.

And importantly, it is becoming more tangible. According to S&P, over 100 gigawatts of data center demand is now under contract with a significant concentration in the Eastern United States. Execution and timing remain the key variables. The magnitude of this commitment represents a clear inflection point. The need for reliable fuel secure generation is becoming better understood across the grid, emphasizing the importance of cogeneration capacity and justifying the decisions to invest capital in the existing coal fleet to keep that capacity running for much longer than anticipated 3 years ago. Additionally, I would highlight that we are encouraged by a few recent policy developments that also improved the outlook for coal-fired generation.

EPA actions on CCR and [ Mats ] during the quarter, moved the regulatory framework in a more practical direction, lowering compliance costs, increasing operating flexibility and reducing uncertainty for coal plants. We believe these changes support the reliability and affordability of dispatchable power and are constructive for our utility customers and for ARLP. We applaud these and the administration’s continued deregulation efforts. Turning our attention to our Royalty segments. Our oil and gas business delivered another record quarter driven by growth in volumes from increased drilling and completion activity by our operating partners and contributions from recent acquisitions, with the portfolio unhedged, changes in commodity prices directly impact our realized pricing, underscoring the segment’s operating leverage and cash flow potential.

We also continue to grow the portfolio through disciplined capital deployment investing $16.2 million in acquisitions during the 2026 quarter, and we remain encouraged by a constructive pipeline of additional opportunities. Taken together, these factors continue to support demand for reliable, dispatchable generation, an environment that favors coal producers with scale, contracted volumes and low-cost reserves. Importantly, our Oil & Gas Royalty segment gives us a second earnings engine that’s not weighed down by drilling and operating capital cost and benefits directly from changes in commodity prices. Demand growth for natural gas and stable demand for domestic oil production continue to reinforce our strategy of reinvesting all after-tax cash generation by our oil and gas royalties into expanding our minerals position.

In closing, we believe Alliance is well positioned as we invest in this growing energy landscape, reliable baseload generation, disciplined capital allocation and operational execution remained at the heart of our strategy. We are committed to investing in opportunities that are strategic to our core businesses, maintaining a strong balance sheet and returning capital to our unitholders. That concludes our prepared comments, and I will now ask the operator to open the call for questions. Operator?

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Operator: [Operator Instructions] Thank you. Our first question comes from the line of Nathan Martin with The Benchmark Company.

Nathan Martin: Joe, you noted the Iran conflict briefly opened the U.S. export thermal valve ARLP contracted nearly 2 million tons, I think. So should we assume now that, that valve is closed? Or could there be more opportunity? And then maybe can you remind us what API 2 price range ARLP needs to incentivize sales to that export market?

Joseph Craft: Yes. Currently, I would say that the domestic opportunities are preferred over the export market. So when we contracted for these volumes, API 2 is in minimum 130 up to 140 peaked historically and really currently, even with domestic prices and really it depends a lot on transportation. But primarily, that number is around 120 is where our preferred option would be on how the export market would compare to the domestic market that we see. So I would say the answer is 120. We do believe that with the uncertainty, not knowing exactly what’s going to happen there, that there still could be possibilities of increased export opportunities. We’re sort of shoulder period. So when we get to the summer and we have higher demand for both — for cooling demand that there is a potential that we could see that window open again.

Our current posture though is to really focused on opportunities that are available to us in the domestic market. So at this moment in time, that’s where our guidance is projecting, that’s what the — for 2026 and 2027.

Nathan Martin: Okay. I appreciate that, Joe. And that kind of gets into my next question. We talked about largely a more mild winter year-over-year despite winter storm firm and the deep 3s that followed. What are you hearing from your customers as far as potential demand as we head into the summer? And you made the comment that those evaluations are current now. I think you said summer weather will drive spot activity likely. So could we be in a position where utilities could even flex down if the summer isn’t very hot? It would be great to just get some additional thoughts there.

Joseph Craft: I think that right now, we’re seeing our customers pretty much we’ve got 4 or 5 different solicitations that are currently either in the process of being evaluated or RFPs that are going to happen this month that we anticipate. So we are seeing our customers going out and looking to add to their position for 2026 and then going forward on a longer-term basis. So we’ve reflected in our guidance what we believe any downside optionality would present itself. So right now, we do believe that there is demand for our unsold positioned to where we should be in a position to be able to sell our production. Weather will be dependent. I think most things projections I’m seeing our most forecasts are projecting that the summer would be warmer than normal, which would be constructive for demand in the second half of the year.

Nathan Martin: Got it. And then finally, the PJM was in the headlines a couple of times over the last few months. And regarding your possibility that the region could experience the power shortage over the next decade or so as data center growth accelerates demand there. More near term, though, I believe PJM was seeking 15 gigawatts of new power supplies and emergency backstop there to address potential shortages as early as the summer ’27, I think it was. So Joe, it would just be great to get your thoughts around what you’re hearing there conversations maybe that are occurring within that arena and how RLP could possibly participate.

Joseph Craft: Yes. As you said, there’s a lot of discussion going on in PJM on trying to understand what the markets can do to ensure that we have reliable capacity on a going-forward basis, at the same time, trying to lower costs as much as possible. So there’s been a lot of different ideas that have been floated relative to how to ensure that the data center demand is — and the increase of generation capacity is paid for by the data centers. As we try to understand that dynamic, the PJM primarily is trying to weigh how do we detect that cost structure, but at the same time, make the economy sure we keep the existing capacity, cocapacity, viable and available for future demand. So it’s hard to predict. I think that we still are of the view that the capacity payments that we’ve seen recently are going to continue for the next several years because the demand is such that we must keep every coal plant, every natural gas plant, all generation online to meet that demand because trying to build new construction to meet that demand is just — it’s not moving as fast as it needs to.

So when we think of the power capacity we need everything that we’ve got available today. And I’m speaking more from an Eastern coal producers perspective is selling coal to the Eastern markets. And we do believe that the existing capacity must stay online. We’re seeing announcements continue to try to extend the life of these plants beyond some plants were designed to close in 2028, and we’re hearing more and more that are announcing, saying open to 2034 as a minimum. So we just think that’s going to continue and the pricing construct that PJM comes up with is going to have to support that conclusion in our view.

Operator: Our next question comes from the line of Matthew Key with Texas Capital Bank.

Matthew Key: I wanted to start just kind of on costs in Appalachia. Obviously, the current guidance improves — implies an improvement over the remainder of the year. However, I know you have the longwall move at Tunnel Ridge. So how should we be thinking about costs in the second quarter? And then I imagine the majority of the improvement would be more back weighted to the second half of ’26. Is that fair?

Cary Marshall: Yes, Matt, that is fair. In terms of your question around Appalachia, in particular, out at Tunnel Ridge, we did have a longwall move this quarter. We’ve already completed that longwall move. So that was accomplished in first week in April for the most part. So that longwall move is done. So it will modestly impact what the quarter is around Appalachia overall. But for the most part, all the longwall moves, well, all the longwall moves in Appalachia are completed. And so as we look at the balance of the year, we do expect those operations to continue to run well throughout the balance of the year. The longwall has started up well since then, and so productivity and production has been good as a result of that.

So we do anticipate, as you mentioned, costs coming down they will be a little bit higher. As we look at Q2 than Q3 and Q4, but you should see a fairly meaningful reduction in cost because you’re going to have quite a bit more of Tunnel Ridge sales volumes in this quarter versus what we had in Q1. And so we are anticipating if you just kind of take a look at the volume cadence for the rest of the year from where we were versus the first quarter. We do expect volumes to jump up maybe around 15% or so just in Appalachia and that should remain fairly consistent for the final 3 quarters of the year. And so you will see a positive benefit on cost that will be coming down. So we do anticipate a fairly meaningful cost reduction in Appalachia to the tune of it could be somewhere in that neighborhood 15%, 20% quarter-over-quarter.

Matthew Key: Got it. That’s super helpful. And I want to just touch on major capital allocation priorities in 2026. Obviously, you expect a more investment in the oil and gas royalty business this year than maybe the last couple of years. But obviously, Gavin has been a major success for you guys. So I wanted to just see if you could provide any color on what you’re seeing in potential acquisitions on the power side. And obviously, as you mentioned in your prepared remarks, there’s been a lot of positive changes with the mass adjustments in that. So does that incentivize you to make potentially a shot on goal there on the power? And how are you balancing kind of those 2 major initiatives?

Joseph Craft: Yes, we are continuing to look at the oil and gas segment. And as I mentioned, we’re committed to returning our capital, whatever after cash tax or after-tax cash deployment is there. And the last couple of years, we’ve actually been short of that. So there is the potential to invest more in the oil and gas, the right underwriting standards can be met for that. On the power side, we have been very pleased with our investment in Gavin. We continue to believe that demand for energy from coal-fired generation is necessary like I mentioned a few minutes ago. So if there are those owners of coal plants that are interested in divesting those. We are definitely interested in participating in that on a going-forward basis. So if there are opportunities, yes, we would allocate capital to those 2 areas of opportunities within as we look at those being opportunities for us to grow our business.

Operator: Our next question comes from the line of Mark Reichman with NOBLE Capital Markets.

Mark La Reichman: Just a follow-up on that last question. on the capital allocation. When you think of your coal operations, your royalties expansion and then your emerging investments, whether that be Gavin or Matrix or some of the others. How are you thinking about that in terms of do you think you would go beyond just reinvesting the oil and gas minerals cash flow to fund growth? Do you think you would go beyond that? And just — how do you kind of think about the returns across those different areas? Or maybe the way to frame it would be what is your hurdle rate or your criteria for each of those areas?

Joseph Craft: Yes. I think that as we look at the pipeline, we mentioned that we did $16 million. In the first quarter, we did $14 million in the fourth quarter. So that’s sort of the opportunities that are presenting themselves in what we call the ground game. We haven’t seen very many packages for larger acquisitions to come to the market. I think that it’s difficult to understand. I think from some of the sellers, it’s difficult to understand exactly where the war premium is going to be. And so a lot of people that have large portfolios are enjoying pretty high current pricing. So is it possible? Yes, it is possible. Do we anticipate that right now, we’re not anticipating that. If you factor in the past 2 years in addition to this year, if we just look at those cash flows that we have available to invest. Do you have another part of the question then, I didn’t answer.

Mark La Reichman: Well, I was just also thinking kind of your — when you think about beyond maintenance capital for coal operations. And then of course, you’ve kind of answered the oil and gas royalties piece, but then also the emerging investments. What is your kind of your criteria or your hurdle rate or maybe how should investors think about returns across those areas.

Joseph Craft: Yes, I think that there are totally 2 different investment time horizons. On the coal side, we would expect try to get our cash flow back on a shorter time period, get a payback period, a shorter time period than on oil and gas. On all our oil and gas opportunities that we look at, most of them are 15, 20 years economic life, whereas a coal asset, it’s probably 10%. So when you think of it that way, that requires you to get a higher return on a coal investment than typically what our hurdle rate would be on oil and gas. And oil and gas is just totally dependent on the amount of PDP near-term cash flows that are identified. So it’s the returns anywhere from 15 to 20 something percent depending on the risk profile of the timing of the cash flows that we evaluate on the mineral side.

Mark La Reichman: That’s helpful. The first quarter results actually came in above our expectations, but I want to ask on the digital assets. When Bitcoin is going up, that’s great. When it’s going down, it could be a bit of a distraction. And I was just wondering, I mean, it’s not hugely significant to your overall operations. But how are you thinking about that business strategically? I mean is there — are there some strategic intelligence or advantages that you gained from operating that business beyond the gains and losses that cause you to want to sustain those operations? Or just how are you thinking about the Bitcoin operations?

Joseph Craft: We do look at what the — what we believe the projected price will be. We’re seeing some rebound in that. There I think one of the catalysts could be the CLARITY Act that’s being considered by Congress this summer that we’re seeing. [ Kevin Warsh ] and his confirmation hearing talked about how Bitcoin is an asset and a class, it’s — that he’s — factors in. We’re seeing the administration being very supportive. So we do believe that the upside on pricing is significant enough that we should hold on to what we have. At the same time, it is opportunistic in one sense, but I think it is — as we look at what it costs us to mine and the position of where we are, we think there’s definitely more upside than there is downside, but…

Mark La Reichman: So you think, basically, argument to continue with it is you think Bitcoin is going to gain currency in the market become more widespread, gain in popularity, regulations are going to support it. And then, of course, you’ve got all that excess electricity to dedicate to it.

Joseph Craft: Well, going to see markets. And if you look at the cash flow that’s going into the EFT markets, we’ve seen more inflow of cash when it was dropping. You saw a lot of outflow, but you’re now seeing more inflow into those markets. And again, we’re of the view that it’s got more upside than downside, and therefore, we’re holding.

Mark La Reichman: Okay. And then just on the overall results. So you’re expecting a stronger second half. You’ve already kind of talked about the drivers of that, both on the revenue side and the cost side. Is the second quarter I mean, you’re not expecting quite as strong as to say, the third quarter, that’s just kind of a transition to the stronger second half?

Joseph Craft: Yes, Mark, that’s fair. If you look at our overall sales volume, second half should pick up Hamilton does come online, as I mentioned in my prepared remarks, kind of first half of May. And so then with no additional longwall moves either at Hamilton or Tunnel Ridge, certainly the back half of the year. we are anticipating to be quite a bit stronger than the first half. And so as you mentioned, the second quarter will kind of be a transition to that because we’ll have us Tunnel Ridge is beyond the longwall move. It will essentially be running virtually the entire quarter. And then Hamilton, as I mentioned, will transition and then begin operating kind of in that first half of May.

Operator: [Operator Instructions] Our next question comes from the line of Michael Mathison with Sidoti.

Michael Mathison: Congratulations on the quarter, gentlemen. Turning to my questions. I noticed that the pricing for Appalachia coal came in above $74, which is above your guidance and yet guidance remains unchanged. So was pricing in Q1, just a reflection of rather your guidance for the remainder of the year, just a reflection of the roll-off of old contracts?

Joseph Craft: Yes. I think that on a going-forward basis, we had the Mettiki situation where those sales contracts are rolling off. We did extend — we anticipated when we issued the warn that the contract we had would be totally sold in the first quarter. Some of that’s gotten extended beyond the first quarter. But what you’re seeing is the lack of that higher-priced contract being in the market in the second half of the year, including the second quarter. So you’re seeing back what Cary said earlier, a larger percent of Tunnel Ridge production, which means lower cost, but it also means lower revenue compared to what we had in Mettiki, higher cost and higher revenue before the closure of that operation.

Michael Mathison: Got it. Looking at CapEx in the quarter, on a run rate basis, it ran about 25% higher than the high end of your guidance. Is that just seasonality? Or were there special factors involved?

Cary Marshall: When you look at the quarter, it was higher. CapEx came in a little bit over $95 million for the quarter. I will say, included within that, we did purchase about $15.5 million of coal reserves within that $95 million number there. So if you back that out, it is a little bit higher than what that run rate is. But if you normalize that out, Michael, I think that will account for quite a bit of that difference.

Michael Mathison: Great. Again, very helpful. One other question. I noticed that there were no outside coal purchases in this quarter, unlike much of 25 and 24. Can we expect the same for the balance of the year or with outside full purchases come back into play?

Cary Marshall: Yes. Our expectation is no additional outside coal purchases.

Joseph Craft: That tied directly to our Mettiki operation.

Michael Mathison: And one last question, if I could squeeze it in. The other income line — I’m sorry, go ahead. Yes. The other income line was $10 million in the quarter, unusually high for you. What drove the big increase? And what should we expect in other income going forward?

Joseph Craft: Yes. I think going forward, it’s a good question. I think going forward, essentially more in line with where we have been historically, which has just been very minimal other income flowing through that line item, if not a little bit on the expense side of it. For the quarter, we did have a favorable actuarial adjustment that’s flowing through that line item. That’s about half of what that total is. It’s associated with some of the liabilities — black lung liabilities, on our balance sheet. And so we did have a favorable adjustment there. The other piece of that relates to one of our other growth investments associated with infant item. We did have a favorable adjustment to the valuation of our holdings of infant item, just to under $4 million associated with that. So those 2 are the lion’s share of what you see there. So we don’t anticipate those occurring on a regular basis. So I would normalize those out going forward.

Michael Mathison: Great. Very helpful. Well, congratulations again, and good luck in the coming quarter.

Operator: Our next question comes from the line of [ Ed Easton ] with the Easton Group.

Unknown Analyst: Thank you very much for the way you run the business. I love the transparency and the way you conduct everything by just talking about it on the quarterly calls. My question is, it looks to me like most of our capital expenses, the big ones are kind of a little bit behind us, and the operational costs should be going down a little bit. What would you think about buying back stock? And what do you think about maybe increasing the dividend as that goes forward?

Joseph Craft: We’ve evaluated that over time. I think that right now, we’re focused on capital allocation. And as Cary mentioned, we were [ one to one ] this quarter. So we need to get our distribution coverage ratio more in line with an expectation of 1 2 to 1 4 on a going-forward basis before we would consider either of those an answer to do either buyback and/or an increase in distribution.

Unknown Analyst: Well, thank you. I’m very proud to be a shareholder. I like the way you run the business.

Operator: We have no further questions at this time. I’d like to turn the floor back over to Mr. Marshall for closing comments.

Cary Marshall: Thank you, operator. And to everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. We look forward to speaking with you again when we report second quarter financial and operating results. This concludes our call for the day. Thank you.

Operator: Ladies and gentlemen, this does conclude today’s teleconference. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.

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