Alliance Resource Partners, L.P. (NASDAQ:ARLP) Q2 2025 Earnings Call Transcript

Alliance Resource Partners, L.P. (NASDAQ:ARLP) Q2 2025 Earnings Call Transcript July 28, 2025

Alliance Resource Partners, L.P. misses on earnings expectations. Reported EPS is $0.55 EPS, expectations were $0.61.

Operator: Greetings. Welcome to Alliance Resource Partners Second Quarter 2025 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce Cary Marshall, Senior Vice President and Chief Financial Officer. Thank you. You may begin.

Cary P. Marshall: Thank you, operator, and welcome, everyone. Earlier this morning, Alliance Resource Partners released its second 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 2025. 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 if our underlying assumptions prove incorrect, actual results may vary materially from those we projected or expected.

In providing these remarks, the partnership has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise, unless required by law to do so. Finally, we will also be discussing certain non-GAAP financial measures. Definitions and reconciliations of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures are contained at the end of this morning’s press release, which has been posted on our website and furnished to the SEC on Form 8-K. With the required preliminaries out of the way, I will begin with a review of our second quarter 2025 results, give an update of our 2025 guidance, then turn the call over to Joe Craft, our Chairman, President and Chief Executive Officer, for his comments.

For the 2025 second quarter, which we refer to as the 2025 quarter, total revenues were $547.5 million compared to $593.4 million in the second quarter of 2024, which we refer to as the 2024 quarter. The year-over-year decline was driven primarily by lower coal sales prices and lower transportation revenues, partially offset by higher coal sales volumes. Compared to the sequential quarter, total revenues increased $7 million due primarily to increased coal sales volumes. Our average coal sales price per ton for the 2025 quarter was $57.92, a decrease of 11.3% versus the 2024 quarter and 3.9% on a sequential basis, driven by the continued roll-off of higher-priced legacy contracts from the 2022 energy crisis and revenue mix with a higher proportion of Illinois Basin tons in the 2025 quarter.

As it relates to volumes, total coal production in the 2025 quarter of 8.1 million tons was 3.9% lower compared to the 2024 quarter, while coal sales volumes increased 6.8% to 8.4 million tons compared to the 2024 quarter. Compared to the sequential quarter, coal sales volumes were up 7.9%. Total coal inventory at quarter end was 1.2 million tons or 200,000 tons lower than the sequential quarter. In the Illinois Basin, coal sales volumes increased 15.2% and 10.3% compared to the 2024 and sequential quarters, respectively, led by increased volumes from our River View and Hamilton mines who both delivered all-time record monthly shipments in June. Coal sales volumes in Appalachia were down 16.8% and 0.7% compared to the 2024 and sequential quarters due to continued challenging mining conditions at Tunnel Ridge, which led to lower recoveries.

Tunnel Ridge did start its longwall move to a new section of the mine late in the 2025 quarter. The longwall move was completed in mid-July and puts Tunnel Ridge in much more favorable mining conditions moving forward. As a result, we expect second half results from Appalachia to be much better than the first half. Turning to costs. Segment adjusted EBITDA expense per ton sold for our coal operations was $41.27, a decrease of 9% versus the 2024 quarter and 3.5% as compared to the sequential quarter. The Illinois Basin was the primary driver of the decrease year-over-year, resulting from lower maintenance and materials and supplies costs at several mines in the region, improved recoveries at our River View and Hamilton mines and reduced longwall move days at Hamilton.

In Appalachia, despite the challenging conditions at Tunnel Ridge, segment adjusted EBITDA expense per ton continued its improvement relative to recent quarters, declining 5.8% sequentially. In our royalty segment, total revenues were $53.1 million in the 2025 quarter, up 0.2% compared to the 2024 quarter. Specifically, oil and gas royalty volumes increased 7.7% year-over-year on a BOE basis due to increased drilling and completion activities on our royalty acreage. However, this was offset by 9.6% lower BOE pricing versus the 2024 quarter. Compared to the sequential quarter, total revenues increased 0.8% due to higher volumes from our Coal Royalty segment. Coal Royalty tons sold increased 10.4% and 8.3% compared to the 2024 quarter and sequential quarter, respectively.

Coal Royalty revenue per ton for the 2025 quarter was down 3.6% compared to the 2024 quarter and up 3.2% sequentially. Our net income in the 2025 quarter was $59.4 million as compared to $100.2 million in the 2024 quarter and $74 million sequentially. The decrease reflects the previously discussed variances plus higher depreciation expense and a $25 million noncash impairment on our July 2023 preferred stock investment in a battery materials company following the conversion of all of the company’s preferred stock to common stock as a part of a convertible note financing and recapitalization completed during the 2025 quarter. We elected to participate in the recapitalization, investing $2 million in the convertible note during the quarter to maintain a senior position within the capital structure, with the goal of recouping all or part of Alliance’s total invested capital upon a future liquidity event or repayment of the convertible note.

This charge was partially offset by a $16.6 million increase in the fair value of our digital assets compared to the end of the 2024 quarter. Adjusted EBITDA for the quarter was $161.9 million, which was down 10.8% compared to the 2024 quarter and up 1.2% sequentially. Now turning to our balance sheet and uses of cash. Total debt was $477.4 million at the end of the 2025 quarter. Our total and net leverage ratios finished the quarter at 0.77 and 0.69x, respectively, total debt to 12 months adjusted EBITDA. Total liquidity was $499.2 million at quarter end, which included $55 million of cash on the balance sheet. Additionally, we held approximately 542 Bitcoin on our balance sheet, valued at $58 million at the end of the 2025 quarter at a price of approximately $107,000 per Bitcoin.

At this morning’s price of $118,000 per Bitcoin, 542 Bitcoin would be valued at $63.9 million, or $5.9 million higher than the end of the 2025 quarter. For the 2025 quarter, Alliance generated free cash flow of $79 million after investing $65.3 million in our coal operations. Turning to our updated 2025 guidance detailed in this morning’s release. Favorable weather for most of this past season and increased demand for electricity drove natural gas prices higher and increased coal consumption in the Eastern United States, helping further reduce customer inventories and increased domestic coal burn compared to 2024. With long-term demand forecast being ramped up across the country in a more favorable regulatory environment, we are seeing multiple domestic customer solicitations for long-term supply contracts.

During the 2025 quarter and subsequent to its end, we have been active in several domestic utility solicitations for 2026 and beyond, having been mostly sold out for this year as customers continue to value our product quality, reliability of service and counterparty financial strength. During the 2025 quarter, we committed an additional 17.4 million tons over the 2025 to 2029 time period, which included 1.1 million option tons subject to our customers’ election. Our contracted position for 2025 is 32.3 million tons committed and priced and includes 29.5 million tons for the domestic market and 2.8 million tons for export. In the Illinois Basin, we are increasing our volume guidance ranges to 25 million to 25.75 million tons based on solid domestic demand.

In Appalachia, lower volumes at Tunnel Ridge and a customer-defaulted MC Mining during the first half of the year are leading us to reduce our volume expectations for the year to 7.75 million to 8.25 million tons. Looking at 2026. Strong demand for term supply and an active contracting season allowed us to add significantly to our order book. Assuming estimated full year sales of 33.4 million tons, which is the midpoint of our 2025 full year guidance range of 32.75 million to 34 million tons, we are now 97% committed for 2025 and 80% committed and priced for 2026, up from 61% committed last quarter for 2026, putting us in a good position for this time of year. We have the capacity to flex additional tons to domestic or export customers should market conditions warrant additional sales.

With a more constructive regulatory backdrop, our customers are responding, running their assets harder to meet the heightened demand while extending the planning life of those same assets. All told, we believe this is the most encouraging outlook we’ve seen for the domestic market since the beginning of 2023, more than making up for persistent weakness in the seaborne thermal and metallurgical markets. We increased sales pricing guidance ranges in Appalachia to $79 to $83 per ton. Our expected full year 2025 price is unchanged at $57 to $61 per ton based on a combination of our committed order book and our expectations for any additional commitments, both domestic and export for the open position. As we discussed last quarter, we anticipate that our 2026 average coal sales price per ton to be approximately 5% below the midpoint of our 2025 guidance range.

And like this year, we remain optimistic we can maintain margins with cost savings, though current trade policy does make these costs, sales opportunities and pricing hard to predict. On the cost side, we are reducing our full year 2025 segment adjusted EBITDA expense per ton to be in a range of $39 to $43, primarily due to better-than-expected costs in the Illinois Basin. As I mentioned earlier, we completed a scheduled longwall move earlier this month at Tunnel Ridge, and we have a move scheduled at Hamilton in the third quarter. In our Oil & Gas Royalties business, volumes have exceeded our expectations year-to-date, and we are increasing our guidance for all three commodity streams with ranges of 1.65 million to 1.75 million barrels of oil, 6.3 million to 6.7 million MCF of natural gas and 825,000 to 875,000 barrels of natural gas liquids.

On a BOE basis, our updated full year guidance midpoint is approximately 5% above our prior guidance. Segment adjusted EBITDA expense is expected to be approximately 14% of Oil & Gas Royalties revenues for the year. Other than a slight improvement to our estimate for net interest expense, all remaining guidance ranges, including total capital expenditures, are unchanged. And with that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe?

Joseph W. Craft: Thank you, Cary, and good morning, everyone. Our Illinois Basin operations ran well again in the second quarter, highlighted by record shipment volumes in June at two of our operations. These results are a direct result of the hard work and dedication of our entire team. While our financial results for the quarter continued to reflect some of the lingering issues at Tunnel Ridge in Appalachia and lower realized Coal and Oil & Gas Royalties pricing, we are encouraged by signs of improvement in the coal market fundamentals. With supportive actions by the current administration, we believe our long-term outlook for ARLP is as strong as it has been in years. The domestic coal market continues to demonstrate exceptionally strong fundamentals driven by AI data center expansion and increased domestic manufacturing.

June temperatures were warmer than normal across our key operating regions, driving significant increases in coal generation compared to last year. This weather-driven demand surge, combined with natural gas prices that remain elevated, has reinforced coal’s competitive advantage in the power generation mix. Year-to-date, electricity generation in key Eastern regions was up over 18% compared to last year, and Eastern utility inventories are 18% below prior year, nearing equilibrium for the first time since the summer of 2023. This inventory tightness, paired with robust summer demand, is creating a significant more supportive demand environment as utilities prioritize energy security and grid reliability. Given our success this year in securing a significant volume of committed tons for delivery over the next 3 to 4 years, we are cautiously optimistic that there will be opportunities to grow sales volumes next year.

While the average coal sales price per ton may trend lower than this year, we expect the increased production, along with our recently completed capital projects will drive cost per ton lower so margins can be maintained around this year’s level. On the Oil & Gas Royalties front, higher volumes this quarter helped offset lower oil prices year-over-year. As Cary said earlier, our strong volume performance is expected to continue, leading us to increase the midpoint of our 2025 BOE volume guidance by approximately 5%, demonstrating the high quality of our acreage position and organic growth potential embedded in our existing portfolio. Looking forward, while the volatility of oil prices related to geopolitical tensions has impacted deploying capital this year, our strategy for Oil & Gas Royalties business is unchanged, aiming to recycle segment cash flows to acquire minerals in high-quality basins with top-tier operators when those opportunities meet our disciplined underwriting standards.

From a macro perspective, the ongoing shift in our country’s energy policy has been a complete reversal from the prior administration. In July, the Department of Energy released their Resource Adequacy Report, which provides compelling federal validation for this shift, consistent with what our industry has stated ever since President Obama was elected. The current administration has taken many supportive actions to ensure the United States is a global leader in artificial intelligence. To achieve this aim, America needs vast amounts of affordable, reliable energy. That is why President Trump signed 4 executive orders in April of this year, specifically addressing grid reliability concerns and the necessity to delay premature coal power plant retirements.

That is in part why on July 4 he signed into law the One Big Beautiful Bill Act, which included phasing out renewable tax credits in favor of baseload generation, including coal, which is essential for America’s energy security. That’s why President Trump announced on July 17, a 2-year reprieve from certain regulatory rules for coal-fired power plants and other industries he terms “vital to national security.” The White House said in the fact sheet that President Trump’s actions will ensure that “critical industries can continue to operate uninterrupted to support national security without incurring substantial costs.” As recent as last week, President Trump said the U.S. will do “whatever it takes” to lead the world in artificial intelligence as he signed 3 executive orders that laid out his administration’s plans to advance AI leadership by accelerating data center development and related energy infrastructure.

In conclusion, each quarter, the Board considers multiple factors when determining the appropriate distribution levels, including, but not limited to, expected operating cash flows generated by our businesses; capital needed to maintain our operations; distribution coverage levels; debt service costs; trade policy uncertainty; and any other potential investment opportunities. Today’s announced quarterly distribution rate of $0.60 per unit, or $2.40 on an annualized basis, was based upon all these factors as well as our increased visibility in ’25 and 2026 expected cash flows and committed tons. It’s also worth noting that maintaining an attractive after-tax distribution is one of our primary capital allocation objectives. With passage of the One Big Beautiful Bill Act, which restored 100% bonus depreciation and extended the 20% qualified business income deduction under tax code Section 199A, the after-tax distribution in 2025 for the majority of units outstanding is expected to be higher than what the previous distribution rate of $0.70 per unit would have delivered under the prior tax code.

As Cary said earlier, this is the most encouraging outlook we’ve seen for the domestic coal market since the early 2023. We are also operating in the most favorable regulatory environment for coal in decades. We are optimistic about the future coal potential across all areas — excuse me, we are also optimistic about the future growth potential across all areas of our businesses. This also includes examples such as our recent $25 million commitment to a private investment vehicle that will fund the acquisition of the Gavin coal power plant located in the PJM market. While the transaction was pending FERC approval as of the quarter end, we are pleased to report that the approval was received on July 23 and is expected to close during August.

The welcome news came one day after PJM announced the results of their auction to price generating capacity for the delivery year June 1, 2026 to May 31, 2027. The price came in at the FERC-approved cap of $329.17 per megawatt day for the entire PJM footprint, a new record for most of PJM, the nation’s largest grid operator. Demonstrating its importance, coal was the second largest source of generating capacity that cleared the auction. So as you consider why the Board adjusted the distribution at this time, I want to assure you it is not related to declining fortunes, but instead to strengthen our balance sheet and provide additional financial flexibility to pursue growth opportunities to maximize unitholder value. That concludes our prepared comments, and I will now ask the operator to open the call for questions.

Operator?

Q&A Session

Operator: [Operator Instructions] Our first question comes from Nathan Martin with The Benchmark Company.

Nathan Pierson Martin: Maybe just starting off with a question related to your comments towards the end there, Joe. The $25 million investment, I think, for your acquisition of the coal power plant, PJM, can we just get a little more color there? What’s going on? Do you see any other potential for additional investments in other power plants? That would be helpful to start this.

Joseph W. Craft: Yes. So ECP, which is a private equity firm, did lodge a bid to buy the Gavin power plant along with some other assets. In order to fund that acquisition, they set up a fund to raise capital. So we’ve invested in that particular investment fund that allows us to participate as an LP investor. I think the timing of that acquisition was very well timed from a purchaser’s perspective. And for some reason, it was delayed, but it finally did pass FERC approval. And we do believe that, that will be immediately accretive, and we’ll start seeing distributions from that acquisition upon its closing in August. As to whether that will portend for other opportunities, I believe it will. There continue to be certain announcements where utilities are looking at plants that they may be willing to sell as they think about how they meet their specific demand requirements.

And some of that, we’re seeing that over the past 2 or 3 years where utilities were looking to close coal plants to build gas plants because of the action of the administration to try to maintain every coal plant that’s currently operating. There are some utilities that want to move forward with gas building and at the same time, we’re willing to find ways to keep those plants open but allow others to own those plants. I’m not sure exactly whether we’re talking a handful to 5 to 10, but it would be something in that area that I think are opportunities that could be pursued over the next 18 to 24 months.

Nathan Pierson Martin: Okay. Appreciate that, Joe. And second, could we get a little more color on the Board’s decision to lower the distribution? I appreciate the comments that you just made in the prepared remarks. Again, increased visibility in ’25 to ’26 expected cash flows. You made the comment that your outlook for domestic coal is stronger than it’s been in years. Just trying to reconcile those comments there with the cut. But additionally, the lower distribution, I guess, saves Alliance roughly $50 million or so on an annualized basis. So do you have planned uses for that additional cash at this point, whether it’s organic or inorganic? It would be great to get your thoughts on any other potential opportunities you see out there then.

Joseph W. Craft: Yes. I think if you go back as to when we did increase the distribution to the $0.70 level, that was right after the big energy crisis. And we were expecting very high income that would flow through to our unitholders, back to my comment of trying to target attractive after-tax increases. So we were looking, at that time, over $1 billion of income in our EBITDA, I believe. And so when we looked at that, we felt it was necessary to go to that rate to provide that attractive after-tax income. Since the energy crisis of 2022, we have seen somewhat a rebalancing to margins that would be more sustainable. And I think that with the current outlook compared to where we were in 2022, we felt it was necessary to go ahead and adjust the distribution so that it would fall in line with a very attractive after-tax return on a going-forward basis and also put us in a position where we do believe, like we have said, every time we’ve made a decision on adjusting our distribution that we believe that, that is sustainable for the immediate near future.

So we felt that the timing with the new tax bill that allows for our unitholders, the majority of our units that are trading to receive benefits that are greater than what they were receiving and anticipating to receive in ’25 made for a good time to go ahead and adjust to a more normal operating margin climate for us. So that’s the primary reason. And yes, it does generate the extra cash flow. And as I said, it’s not because of declining fortunes. So that cash flow will be extra and it can be utilized to position ourselves for growth opportunities or pay down debt or unit buybacks or whatever makes sense for the long-term opportunities for our shareholders. As far as do we have some immediate need to deploy the capital, there is nothing that we can announce.

At the same time, we are looking at multiple areas of investment opportunities that we do think that we should pursue. So we are definitely focused on trying to grow our company and trying to have a balance sheet that we believe is strong and continues to be conservatively managed. We felt it was the proper time to, again, position ourselves for that growth.

Nathan Pierson Martin: And Joe, could you give any more thoughts around where those opportunities are that you’re looking at right now, whether that’s coal, land, power plants like we just talked about, renewables, et cetera?

Joseph W. Craft: Well, I think that, one, we’re continuing to look at minerals. We are looking at some investments that are in our Matrix subsidiary. Those are small, but they would allow for some incremental growth for that subsidiary. We’re really encouraged by many things that they have going on. And we believe that, that’s going to start showing sizable growth in the 2027 time horizon. Hopefully, we’ll see some of that growth in 2026. Beyond that, we’re trying to evaluate, are there ways we can participate in the energy infrastructure of data centers? There’s a lot of activity with each of our customers where they are looking at trying to expand their footprint of generation to meet the increased demand from data centers.

And we’ll continue to look at participating like we did with Gavin and selected opportunities on certain coal plants that we think could benefit our coal supply as well. So those are areas that we’re evaluating. And like I said, there’s nothing on the horizon to speak to today. But we’ll be — we’re positioned well to try to take advantage of opportunities as they present themselves.

Nathan Pierson Martin: And then just maybe one final question. Just coming back to the administration’s Big Beautiful Bill, as you pointed out, a number of items in there that are favorable to your business to fossil fuel power generation. How many of your customers do you think stand to benefit from that bill? Any thoughts on how much demand for your product could potentially increase? Have you seen new inquiries? And then additionally, does ARLP stand to benefit at all from some of the other provisions regarding royalty rates, leasing rebates, et cetera? I don’t believe you guys mine on any federal reserves at this point, but just wanted to make sure.

Joseph W. Craft: On the last point, we did not. However, there was a provision for metallurgical coal, broadly defined, that is a 2.5% production tax credit. That is transferable. So that can be utilized by us for our metallurgical product, and our PCI product has a 2.5% cost reduction that could reduce and transfer to our oil and gas segment, the taxes we pay there. So there could be some benefit there. And I think that relative to our customers, one of the biggest benefits is there was a — I don’t know if it was actually part of the tax bill, but it was related to that because there was $1 billion item in that bill to keep fossil fuel plants open, including coal. And then there was another reallocation subsequent to the bill of several other hundreds of millions of dollars that the DOE is making available to those utilities that need to continue to invest in their fossil fuel plants so that they can maintain them and keep them operating.

So in the prior administration where there were targets to close plants prematurely, there were several plants that — of our customers that were not maintaining those plants with capital in anticipation of running them for their full life. So there is some catch up, and there will be opportunities through the Department of Energy that will provide capital for our customers so that they can, in fact, keep their plants open and maintain those for extended life. What we saw in the PJM auction, there were 17 units that total over 1.1 gig, I think, that withdrew their retirements in this particular auction compared to last year. So we’re definitely seeing IRPs from our customers, extending the lives of their coal plants. And so we do believe that the demand is going to be stable as opposed to declining.

So as far as whether it’s growing demand, it’s definitely maintaining demand as far as capacity, which has not been projected over the last year or 2. And as far as the demand, we do believe our demand will increase as the data centers that have been announced by several of our customers are actually starting to come online and the consumption of that powers around the clock because these data centers are run basically 24/7. So we do anticipate that there will be increased electricity demand in our service territory with our customers and that they will start utilizing their coal plants more than what their capacity factor has been over the last several years.

Operator: Our next question is from Mark Reichman with NOBLE Capital Partners.

Mark La France Reichman: So clearly, the distribution adjustment is being done to give you greater flexibility to fund growth capital expenditures going forward. So this $0.40, I guess, reduction for the full year annualized distribution, so that will save you, what, about $50 million or $51 million a year. So I guess what I’m kind of wondering is, do you feel like that, that gives you enough flexibility going forward? I mean your growth CapEx this year is $5 million to $10 million. So I guess, what assurance might investors have that they might not see additional cuts? Or do you think this is — this gives you plenty of flexibility for what you’re maybe contemplating over the next 3 to 5 years in terms of growth CapEx on average?

Joseph W. Craft: Yes. As I indicated, we made that decision believing that we do — we are in a position to maintain this for several years. Each quarter, we look at that as a decision, but we would not have made the adjustment to this level if we didn’t believe it could be sustained at this level. As far as our capacity to grow, the things that we’re looking at would be immediately accretive and we would have the ability to finance those. We have significant financing capacity. We have significant growth continue to be expected out of our Minerals segment, which that growth would be self-financed. So yes, we do believe for the things that we’re looking at, that we will have a strong balance sheet that would allow and support any activity to grow and be able to maintain the distribution at its current level that we announced today. So we’re seeing growth.

Mark La France Reichman: I appreciate those, yes.

Joseph W. Craft: I guess, yes, I think will indicate that…

Mark La France Reichman: No, I think it’s a good decision. I mean — go ahead.

Joseph W. Craft: Yes. Well, we did indicate that we do have the ability to grow our volumes next year. So you need to put that in your calculus also.

Mark La France Reichman: Well, that’s a good segue into my next question. I mean last year at this time, Alliance had about 16.6 million tons committed and priced for 2025. And so now you have 26.6 million tons committed in price for 2026 versus 20.5 million tons at the end of the first quarter. So what are the wild cards that you see that might drive growth in sales tonnage in 2026 versus 2025? And would you see it more in the Illinois Basin or Appalachia?

Joseph W. Craft: The easy one is at Tunnel Ridge. I mean our sales were impacted this year because of our production issues at Tunnel Ridge. And as Cary mentioned, we made our longwall move into our new district, that we started production back in that new district on July 10, and our production is at levels that we thought it would be. So our yields have increased double digits, so it’s a significant impact. We believe that there’s 750,000 to 1 million tons of just normal capacity at Tunnel Ridge that we lost this year that had — they operated at their historical rates we would have produced. We have market for that. We’ve had to defer some of our shipments into next year because of our production problems we had. So that’s 750,000 to 1 million tons of potential in Appalachia.

In Illinois Basin, we are in the process of completing the transition to our Henderson mine from River View to move some units over. So we’re not in construction phase. We’ve completed our construction projects. We’re now in operating phase. We’re seeing improved results there. So there could be the potential of another 1 million tons out of Illinois Basin if the market demands that. We’re at the low end of our export volumes, where this year, we’re looking at maybe 3 million tons compared to close to 6 million last year. And there’s potential that, that market could come back around. The demand has been there. The pricing has been off relative to comparing netbacks. Recently, we’ve seen some stabilization. We’re getting some inbound inquiries as to opportunities that are significantly more attractive than what they’ve been during the year, but it gives us some hope that talking to what our export opportunities might be next year, that there could be some potential to increase that volume above the, say, targeted 3 million tons that we’ll probably ship in 2025.

So those are the prospects that we see.

Mark La France Reichman: And the last question is, as you know, this Gavin plant, I mean, that looks like a fantastic investment with some really strong partners in addition to just the return on the investments. Do you see the potential for — if you do this one or any future ones that you might have an opportunity to supply the plant?

Joseph W. Craft: We do. The Gavin plant, at its current run rate, is fully committed with tons. However, with this growth in demand, there is a potential that they could burn higher than what was anticipated when the investment was made. And so it is a plant that is in our ZIP code that we could supply coal to that plant. And as I mentioned, there’s several other plants that we currently sell to that utilities are willing to consider sales opportunities that could be candidates for, whether it be ECP or others that are looking at acquiring coal plants to structure those acquisitions in a similar fashion as ECP did for the Gavin plant.

Operator: Our next question is from Dave Storms with Stonegate Capital Partners.

David Joseph Storms: Just want to start, we saw a trade deal over the weekend. And just with some of this uncertainty coming off in the global macro environment, is there any sense you can give us on maybe the directional impact on this maybe relative to your guidance?

Joseph W. Craft: I can’t comment on the most recent one that was announced. I really don’t have the details, but the one that was announced with Japan talked about $500 billion of investment coming to the U.S. in areas that include energy, among other things. So there — Japan does have a few investments in our territory between Toyota and Indiana and Kentucky. I think that there’s a potential for examples like that, where there is investments that are coming to this part of — or to the Eastern part of the U.S. Earlier in the year, they announced the Nippon deal with U.S. Steel. So I believe that there will be manufacturing demand increases in our Eastern footprint that will benefit from multiple investments where you’re hearing the President talk in terms of increased business for the U.S. The one anecdote I did hear out of the agreement with the EU, and I don’t recall the exact amount, but there was a substantial amount of energy that they would be purchasing as part of that arrangement.

So we do believe on the positive side that so much of what President Trump is trying to do is revitalize manufacturing in America. And a large part of that will be focused on the manufacturing of goods that will require additional electricity. Specifically, you look in the budget bill on the increased capital that they’ve allocated for defense spending, which is in addition to the manufacturing that’s currently being done in America, a substantial increase in manufacturing of products that will be available not only to satisfy the U.S. budget, but also his efforts to try to get countries around the world to increase their security budget from where they were. They originally had an objective to go to 2% of their GDPs. He most recently is encouraging — demanding those countries to go to 5%, and some portion of that would be purchasing goods from U.S. manufacturers of defense equipment.

So there’s definitely a goal and objective to increase America’s GDP from manufacturing as part of his strategy on these tariffs.

David Joseph Storms: Understood. That’s very helpful. And then just one more if I could. You mentioned…

Joseph W. Craft: The demand is both — yes, the demand is both AI and manufacturing increases for electricity.

David Joseph Storms: Got it. That’s perfect. You also mentioned an equilibrium in inventories not seen since, I believe it was 2023, and how this should have a positive impact on demand. When thinking about the pacing of this demand growth, do you see it more as a gradual increase as inventory levels continue to trend downwards? Or could this come as a restocking wave over the next coming quarters?

Joseph W. Craft: It seems to me that they are basically at equilibrium for most of our customers. And it’s trending a little higher than what historically it’s been. But it seems to be stabilizing at a level to where we are seeing more — some demand this year to maintain inventories at current levels that we really didn’t anticipate thinking that they might — our utility customers might lower inventory levels from the current level. So what we’re seeing is there appears to be an effort by our utilities in the areas where we serve to be at equilibrium today. And therefore, there will be a correlation with their demand increase to what their actual coal purchases would be. Over the last 2 years, we’ve seen coal consumption go up, but the deliveries haven’t been as strong because they had been taken from their piles. So right now, we’re seeing basically an equilibrium for most of our customers that their purchases are designed for what they anticipate their burns to be.

David Joseph Storms: Understood. And I guess just with the 1.2 million tons that ARLP has, do you feel comfortable with that current internal inventory levels relative to this correlation that you’re anticipating?

Joseph W. Craft: Yes. So our current shipments have actually driven those down a little bit as we speak. And we do anticipate that our shipments are going to be pretty consistent through the third quarter. And then going into the fourth quarter, they’ll be — we should be in good shape for the rest of the year is what we’re projecting to be able to maintain our inventories at that level.

Operator: Our next question is from Michael [ Mathison ] with Sidoti & Company.

Unidentified Analyst: I know you primarily produce for the U.S. domestic market, but I’m wondering if the big decline in Chinese demand for seaborne coal has begun to back up and have an impact on U.S. pricing. Any comments on that?

Joseph W. Craft: We are — as I mentioned a few minutes ago, we are getting some inbounds at pricing that is more attractive than it has been. And so at the same time, the domestic pricing is better for us. So from a netback perspective, even though we have seen improved pricing, it’s still not as attractive for us as the domestic market. So we’re going to continue to prioritize the domestic market because of the growth we see. That’s our primary market. It’s more stable for us. But as I mentioned a few minutes ago, there is a possibility or probability even that our export tonnage could be higher next year than it is this year because of seeing some signs of pricing moving a little bit better than what we’ve been experiencing for most of this year.

Unidentified Analyst: Turning to the royalty portfolio. Royalties are roughly 10% of revenues but about 20% of EBITDA, much, much higher margins. Do you see continued investments in royalty assets? And what sectors are you targeting? How big do you see the program roughly 2 or 3 years from now?

Joseph W. Craft: Yes. We are continuing to be committed to our mineral space. So — and we anticipate allowing that segment to invest its EBITDA. So that’s $100 million plus or so a year is what our goals are. We’re — we would go larger than that if the right opportunity would present itself because when you look at our royalty segment, it has no leverage on it. So it does have the capacity to borrow. But yes, it’s a core business for us, and we do anticipate continuing to invest in areas that we primarily targeted, which is the Permian and the Delaware Basin. We would look at opportunities outside those basins, but that’s primarily where our focus has been recently.

Unidentified Analyst: Congratulations on the quarter.

Joseph W. Craft: Thank you.

Cary P. Marshall: Thank you, Mike.

Operator: There are no further questions at this time. I would like to turn the floor back over to Cary Marshall for closing remarks.

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. Our next call to discuss our third quarter 2025 financial and operating results is currently expected to occur in October, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you.

Operator: Thank you. You may disconnect your lines at this time, and thank you for your participation.