ARLP Q1 2026 Earnings Call Transcript

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DATE

Monday, April 27, 2026 at 10 a.m. ET

CALL PARTICIPANTS

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

TAKEAWAYS

• Adjusted EBITDA -- $155 million, 3.1% lower year over year and 18.9% lower sequentially, driven by softer coal sales, higher depreciation, digital asset fair value decreases, and a $37.8 million Metiki impairment.
• Net income attributable to Alliance Resource Partners (NASDAQ:ARLP) -- $9.1 million, or $0.07 per unit, compared to $74 million, or $0.57 per unit, a year prior, reflecting lower coal revenue and asset write-downs.
• Total revenues -- $516 million, down 4.5% year over year and 3.6% sequentially, as lower coal price and volume were partly offset by increased oil and gas royalty revenue.
• Coal sales volumes -- 7.9 million tons, up 100,000 tons year over year, but down 200,000 tons sequentially, as shipment delays moved deliveries to later in the year.
• Average coal sales price per ton -- $56.40, a decrease of 6.5% year over year and 2% sequentially, due to the roll-off of legacy contracts established in 2022.
• Illinois Basin segment highlights -- Coal sales volumes 6.1 million tons (up 0.4% year over year, down 5.9% sequentially), price per ton $51.05 (down 7.4% year over year, up 0.4% sequentially), and adjusted EBITDA expense per ton $35.20 (up 1.3% year over year, up 3.4% sequentially).
• Appalachia segment highlights -- Coal sales volumes 1.8 million tons (up 3.6% year over year), price per ton $74.51 (down 4.8% year over year, down 11.1% sequentially), and adjusted EBITDA expense per ton $62.19 (down 10.8% year over year, down 1.8% sequentially).
• Total coal production -- 8.0 million tons, compared to 8.5 million tons a year prior.
• Coal inventory -- 1.2 million tons at quarter-end, down 200,000 tons year over year and up 100,000 tons sequentially.
• Total royalty revenues -- $61.2 million, up 16.1% year over year and 7.7% sequentially, led by record oil and gas performance.
• Oil and gas royalty segment -- Revenues of $41.3 million (up 14.6% year over year), record BOE volumes of 1.0 million (up 16.1% year over year, up 3.3% sequentially), and adjusted EBITDA of $34.6 million (up over 15% year over year and sequentially).
• Coal royalty segment adjusted EBITDA -- $12.3 million, up 30.6% year over year, primarily from increased Tunnel Ridge royalty tons partly offset by lower unit royalty rates.
• Capital expenditures -- $95.7 million, including $15.5 million for coal reserves purchases; oil & gas minerals acquisitions totaled $16.2 million.
• Distributable cash flow -- $77.8 million, with $78 million distributions paid and a distribution coverage ratio of 1.0x.
• Balance sheet/liquidity -- Total debt and finance leases of $507.7 million, total liquidity $431.2 million (including $28.9 million cash and $402.3 million availability under credit/receivable facilities), with leverage ratio of 0.73x.
• Bitcoin holdings -- 618 bitcoin valued at $42.2 million using $68,233 per coin as of quarter-end.
• Guidance changes -- Overall full-year guidance for coal sales, price, and per-ton costs maintained; oil and gas volume outlook raised by 5% to 1.6–1.7 million barrels oil, 6.6–7.0 million MCF natural gas, and 875,000–925,000 barrels NGLs.
• Sales and contract position -- 2.6 million net contracted tons added for 2026–2027 delivery, resulting in over 95% of expected 2026 coal sales volumes now committed and priced at guidance midpoints.
• Metiki mine update -- Longwall production ceased, $37.8 million non-cash impairment booked; cost containment and future operational flexibility remain priorities amid ongoing uncertainty.

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RISKS

• Metiki mine -- Significant operational uncertainty remains following the decision to cease longwall production, with Cary P. Marshall stating, “meaningful uncertainty remains and greater clarity is not expected until later this year.”
• Distribution coverage -- Distribution coverage ratio at 1.0x, with management indicating no distribution increase or unit repurchase plans until coverage improves to a 1.2x–1.4x range.
• Coal pricing -- Ongoing normalization and lower average prices as high-priced contracts continue to roll off, with management cautioning this will impact second-half revenue as “the lack of that higher-priced contract being in the market in the second half of the year.”
• Digital assets value fluctuation -- $11.6 million fair value decrease in digital assets reflected in earnings, with management acknowledging volatility but currently choosing to hold based on their outlook.

SUMMARY

Alliance Resource Partners announced quarterly results marked by lower coal pricing and shipment delays, sharply reducing net income but offset by record oil and gas royalty performance which drove higher segment revenues and adjusted EBITDA. Despite a $37.8 million non-cash impairment at Metiki and a decrease in digital asset values, management reiterated full-year guidance for coal operations and increased oil and gas royalty volume targets by 5% citing outperformance year-to-date. The company secured over 95% of expected 2026 coal sales volumes under contract at guided pricing, completed all major planned longwall moves for the year, and reported a leverage ratio below 0.75x, supporting ongoing investments in minerals acquisitions while pausing on distribution increases or buybacks until coverage improves.

• Commitments of 2.0 million export tons were secured during a temporary window of opportunity amid geopolitical disruptions, as CEO Craft stated, “traders reacted quickly to dislocations in API2 pricing, allowing Alliance Resource Partners, L.P. to capitalize on a narrow window for export sales by securing 2.0 million tons of commitments to be delivered over 2026 and 2027.”
• Management described market conditions for power generation as tightening, citing data center-driven load growth and recent policy actions that lower coal plant compliance costs, supporting longer-term coal fleet utilization.
• CEO Craft explained, “are going to continue for the next several years because the demand is such that we must keep every coal plant, every gas plant, all generation online to meet that demand.”
• The company confirmed no expectation for further outside coal purchases in 2026 as that activity was exclusively tied to previous Metiki operations.
• Favorable adjustments to the valuation of the Infinitum investment and black lung actuarial liabilities drove a $10 million “Other Income” line, which management does not expect to recur at comparable levels.
• All major longwall moves are now completed for 2026, with Tunnel Ridge restarted and Hamilton anticipated to resume in May, supporting management’s expectation of materially lower Appalachian per-ton costs and sales volume growth by approximately 15% for the remainder of the year.

INDUSTRY GLOSSARY

• Longwall move: The process of relocating longwall mining equipment to a new section, temporarily pausing coal production at the affected mine.
• BOE (Barrels of Oil Equivalent): A standardized metric to aggregate oil, gas, and natural gas liquids volumes for royalty and production reporting.
• API2: The benchmark index for European coal export pricing, often used in international contract negotiations.
• MCF: Thousand cubic feet, a unit of measurement for natural gas volumes.
• NGLs (Natural Gas Liquids): Hydrocarbon products (like ethane, propane, butane) separated from natural gas streams and sold separately.

Full Conference Call Transcript

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 Joseph W. 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 2026 quarter, adjusted EBITDA was $155 million, which was higher than expected but 3.1% lower compared to the 2025 quarter, and down 18.9% compared to the sequential quarter.

Net income attributable to Alliance Resource Partners, L.P. 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 Metiki 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 Metiki, though meaningful uncertainty remains and greater clarity is not expected until later this year.

In the interim, our priority at Metiki 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 volume 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-price 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 8.0 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 Riverview and Gibson South helped to offset some of that impact. The longwall at Hamilton is currently anticipated to resume production in 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 2025 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 Metiki 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. Alliance Resource Partners, L.P. ended the 2026 quarter with total coal inventory of 1.2 million tons, down 200,000 tons year over year and up 100,000 tons sequentially. In our royalty 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 and gas royalty 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 1.0 million, up 16.1% year over year and 3.3% sequentially.

Commodity pricing increased sequentially and segment adjusted EBITDA for the oil and 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 ton sold. Our balance sheet continues to be strong.

As of 03/31/2026, 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 0.69 times debt to trailing twelve 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 1.0x. Turning to our updated 2026 guidance, I will highlight three 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 2027, we expect better operational visibility in 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 2026 and dependent upon summer burn and customer requirements. Finally, the most notable changes to our guidance are in the Oil and 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 to 1.7 million barrels of oil, 6.6 to 7.0 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 will turn the call over to Joseph W. Craft for his comments on the market environment and our outlook.

Joseph W. Craft: Thank you, and good morning, everyone. Thank you for joining the call today. Alliance Resource Partners, L.P. 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 royalties 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 five years. In the Illinois Basin, increased production at Riverview 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 Riverview to Henderson County minor unit transition, bringing the Henderson County mine up to its planned full production capacity of six super sections, and Riverview is now positioned to operate three 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 have 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 firm and the extended freezing weather across the Eastern United States once again highlighted the critical role coal plays in maintaining grid reliability during extreme weather.

According to America’s 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 did not fully offset milder conditions throughout the quarter, utility stockpiles generally remain aligned with our burn projection entering the year, and summer weather will ultimately drive spot market activity for the balance of 2026. Second, the conflict involving Iran briefly improved the previously quiet export market.

In the weeks following the conflict, traders reacted quickly to dislocations in API2 pricing, allowing Alliance Resource Partners, L.P. to capitalize on a narrow window for export sales by securing 2.0 million tons of commitments to be delivered over 2026 and 2027. While API2 prices have since softened, the conflict has contributed to higher global oil prices which continues to be supportive of our oil and 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 three years ago. Additionally, I would highlight that we are encouraged by a few recent policy developments that also improve the outlook for coal-fired generation.

EPA actions on CCR and MAT 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 Alliance Resource Partners, L.P. 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 and gas royalty segment gives us a second earnings engine that is 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 Resource Partners, L.P. is well positioned as we invest in this growing energy landscape. Reliable baseload generation, disciplined capital allocation, and operational execution remain 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?

Operator: Thank you. We will now open the call for questions. If you would like to ask a question, please press 1 on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press 2 if you would 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 questions.

Cary P. Marshall: Thank you.

Operator: Our first question comes from the line of Nathan Pierson Martin with The Benchmark Company. Please proceed with your question.

Nathan Pierson Martin: Joe, you noted the Iran conflict briefly opened the U.S. export thermal valve. Alliance Resource Partners, L.P. contracted nearly 2.0 million tons, I think. So should we assume now that valve is closed, or could there be more opportunity? And then maybe can you remind us what API2 price range Alliance Resource Partners, L.P. needs to incentivize sales to that export market? Thanks.

Joseph W. Craft: Yes. Currently, I would say that the domestic opportunities are preferred over the export market. So when we contracted for these volumes, API2 was in a minimum $130 up to $140. It, you know, 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, knowing exactly what is going to happen there, that there still could be possibilities of increased export opportunities. You know, we are sort of in a shoulder period.

So when we get to the summer and we have higher demand for cooling demand, there is a potential that we could see that window open again. Our current posture though is to really focus on opportunities that are available to us in the domestic market. So at this moment in time, that is where our guidance is projecting us to be for 2026 and 2027.

Nathan Pierson Martin: Okay. 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 fern and, you know, the deep freeze that followed. You know, what are you hearing from your customers as far as potential demand as we head into the summer? You made the comment that those evaluations are occurring 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 is not very hot? Would be great to just get some additional thoughts there.

Joseph W. Craft: I think that right now, we are seeing our customers pretty much—you know, we have four or five 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. We have 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 position to where we should be in a position to be able to sell our production. Weather will be dependent.

I think most projections I am seeing or 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 Pierson Martin: Got it. Thank you for that. And then finally, PJM was in the headlines a couple times over the last few months regarding a possibility that the region could experience a 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 in an emergency backstop there to address potential shortages as early as summer ’27, I think it was. So, Joe, would just be great to get your thoughts around what you are hearing there, conversations maybe that are occurring within that arena, how Alliance Resource Partners, L.P. could possibly participate.

Joseph W. Craft: Yeah. As you said, there is a lot of discussion going on in PJM on trying to understand what the markets can do to ensure we have reliable capacity on a going-forward basis at the same time trying to lower cost as much as possible. So there have been a lot of different ideas that have been floated relative to how to ensure that the data center demand and the increased generation capacity is paid for by the data centers. As we try to understand that dynamic, PJM primarily is trying to weigh how do we protect that cost structure but at the same time ensure we keep the existing capacity—coal capacity—viable and available for future demand.

So it is hard to predict. I think that we still are of the view that the capacity payments that we have seen recently are going to continue for the next several years because the demand is such that we must keep every coal plant, every gas plant, all generation online to meet that demand, because trying to build new construction to meet that demand is—it is just not moving as fast as it needs to. So when we think of the power capacity, we need everything that we have got available today. And I am speaking more from an eastern coal producer’s perspective that is selling coal to the Eastern markets.

We do believe that the existing capacity must stay online. We are seeing announcements continue to try to extend the life of these plants beyond—some plants were designed to close in 2028, and we are hearing more and more that are announcing staying open to 2034 as a minimum. So we just think that is going to continue, and the pricing construct that PJM comes up with is going to have to support that conclusion in our view.

Nathan Pierson Martin: All right. Very helpful, Joe. I will pass it on. Appreciate the time, and best of luck in the second quarter.

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

Matthew Key: Good morning, everyone, and thank you for taking my questions. I wanted to start just kind of on costs in Appalachia. Obviously, the current guidance 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 ’26. Is that fair?

Cary P. Marshall: Yeah, Matt, that is fair. In terms of your question around Appalachia, in particular at Tunnel Ridge, we did have a longwall move this quarter. We have already completed that longwall move, so that was accomplished in the first week in April for the most part. So that longwall move is done. It will modestly impact what the quarter is around Appalachia overall, but for the most part, all the longwall moves in Appalachia are completed, 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 fairly meaningful reduction in cost because you are 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 three 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 of 15–20% quarter over quarter.

Matthew Key: Got it. No, that is super helpful. And I want to just touch on major capital allocation priorities in 2026. Obviously, we expect 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 for you guys. So I want to just see if you could provide any color on what you are seeing in potential acquisitions on the power side. Obviously, as you mentioned in your prepared remarks, there have been a lot of positive changes with the MAT adjustments and that. So does that incentivize you to make, you know, potentially a shot on goal there on the power?

And how are you balancing kind of those two major initiatives?

Joseph W. Craft: Yes. We are continuing to look at the oil and gas segment. As I mentioned, we are committed to returning our capital—whatever after-tax cash deployment is there—and the last couple of years, we have actually been short of that. So there is the potential to invest more in oil and gas if 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 two areas of opportunities as we look at those being opportunities for us to grow our business.

Matthew Key: Got it. Well, I appreciate the color and best of luck moving forward.

Cary P. Marshall: Thank you, Matt.

Operator: Our next question comes from the line of Mark Reichman with Noble Capital Markets. Please proceed with your question.

Mark Reichman: Thank you. Just to 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 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 W. Craft: Yeah. 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 is sort of the opportunities that are presenting themselves in what we call the ground game. We have not seen very many packages for larger acquisitions come to the market. I think that it is difficult to understand—I think, from some of the sellers—it is 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 are not anticipating that. If you could factor in the past two years in addition to this year, if we just look at those cash flows that we have available to invest—what did you have another part of the question I did not answer?

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

Joseph W. Craft: Yeah. I think that they are totally two different investment time horizons. On the coal side, we would expect to try to get our cash flow back on a shorter time period—get a payback period at 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 is 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 the returns are anywhere from 15–20% depending on the risk profile and the timing of the cash flows that we evaluate on the mineral side.

Mark Reichman: Oh, that is helpful. You know, the first quarter results actually came in above our expectations, but I do want to ask on the digital assets. You know, when Bitcoin is going up, that is great. When it is going down, it could be a bit of a distraction. And I was just wondering—I mean, it is not hugely significant to your overall operations—but how are you thinking about that business strategically? I mean, are there some strategic intelligence or advantages that you gain 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 W. Craft: Yeah. We do look at what we believe that projected price will be. We are seeing some rebound in that. I think one of the catalysts could be the Clarity Act that is being considered by Congress this summer. We are seeing, you know, Chairman Worsch in his confirmation hearing talked about how Bitcoin is an asset and a class that he factors in. We are seeing the administration being very supportive. So we do believe that the upside 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 as we look at what it costs us to mine and the position of where we are, we think there is definitely more upside than there is downside. We are looking at the ETF markets, and if you look at the cash flow that is going into the ETF markets, we have seen more inflow of cash—when it was dropping, you saw a lot of outflow—but you are now seeing more inflow into those markets. And again, we are of the view that it has got more upside than downside and therefore we are holding.

Mark Reichman: Okay. And then just on the overall results, so you are expecting a stronger second half. You have 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 are not expecting quite as strong as say the third quarter. That is just kind of a transition to the stronger second half?

Cary P. Marshall: Yes, Mark. That is 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, in 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 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 in May.

Mark Reichman: That is very helpful. Thank you very much.

Operator: Our next question comes from the line of Michael Matheson with Sidoti. Please proceed with your question.

Michael Matheson: Morning, and congratulations on the quarter, gentlemen.

Joseph W. Craft: Thank you, Mike.

Michael Matheson: Turning to my questions, I noticed that the price 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—or rather your guidance for the remainder of the year just a reflection of—the roll off of old contracts?

Joseph W. Craft: Yes. I think that on a going-forward basis, we had the Metiki situation where those sales contracts are rolling off. We did anticipate when we issued the warrant that the contract we had would be totally sold in the first quarter. Some of that has gotten extended beyond the first quarter. But what you are 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 are seeing, back to 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 at Metiki—higher cost and higher revenue—before the closure of that operation.

Michael Matheson: Got it. Thank you. 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 P. 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. 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 Matheson: Okay. Great. Again, very helpful. One other question. I noticed that there were no outside coal purchases in this quarter, unlike much of 2024–2025. Can we expect the same for the balance of the year, or would outside purchases come back into play?

Cary P. Marshall: Yeah. Our expectation is no additional outside coal purchases. That tied directly to our Metiki operation.

Joseph W. Craft: Right. Okay.

Michael Matheson: And one last question if I could squeeze it in. 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?

Cary P. Marshall: Yeah. I think going forward—it is 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 is flowing through that line item. That is about half of what that total is. It is associated with some of the black lung liabilities on our balance sheet. So we did have a favorable adjustment there. The other piece of that relates to one of our other growth investments associated with Infinitum.

We did have a favorable adjustment to the valuation of our holdings of Infinitum—just a shade under $4 million associated with that. So those two are the lion’s share of what you see there. We do not anticipate those occurring on a regular basis, so I would normalize those out going forward.

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

Joseph W. Craft: Thank you, Michael.

Operator: Our next question comes from the line of Ed Easton with The Easton Group. Please proceed with your question.

Ed Easton: Good morning, gentlemen. 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 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 W. Craft: You know, we have evaluated that over time. I think that right now, we are focused on capital allocation and, as Cary mentioned, we are 1.0x this quarter. We need to get our distribution coverage ratio more in line with an expectation of 1.2x to 1.4x on a going-forward basis before we would consider either of those—an answer to do either a buyback and/or an increase in distribution.

Joseph W. Craft: Well, thank you.

Ed Easton: I am very proud to be a shareholder and I like the way you run the business.

Joseph W. Craft: Thank you. Appreciate it, Ed.

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

Cary P. 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 Resource Partners, L.P. 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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