Alliance Resource Partners, L.P. Stock

Greetings, and welcome to the Alliance Resource Partners L.P. Third Quarter 2026 Earnings Call. [Operator Instructions] A reminder, this conference is being recorded.

I'll now turn the conference over to your host, Cary Marshall, Senior Vice President and Chief Financial Officer. Please go ahead.

Thank you, operator. Good morning, and welcome, everyone. Earlier today, Alliance Resource Partners released its third quarter 2026 financial and operating results. We will review the quarter, discuss our outlook for the remainder of 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 1 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 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 third quarter 2026 results including the first full quarter of contribution from our AllDale III and IV acquisition and discuss our updated guidance for 2026, before turning the call over to Joe Craft, our Chairman, President and Chief Executive Officer, for his comments.

Before I get into the numbers, one note on presentation, beginning this quarter, we redefined how adjusted EBITDA is calculated to include noncontrolling interest. And as a result, we'll be reporting adjusted EBITDA attributable to ARLP which excludes amounts attributable to noncontrolling interest in AllDale III and IV and Cavalier Minerals within our Oil & Gas Royalties segment. Prior periods have been adjusted to conform to this presentation.

Overall, results for the third quarter of 2026, which we refer to as the 2026 quarter, were higher on a year-over-year and sequential basis. Compared to the prior year, which we refer to as the 2025 quarter, total revenues increased 5.5% to $603 million. Net income attributable to ARLP increased 46.8% to $139.6 million or $1.08 per basic and diluted limited partner unit and adjusted EBITDA attributable to ARLP increased 26.3% to $233.9 million.

Compared to the second quarter of 2026, which we refer to as the sequential quarter, total revenues increased 9.3%. Net income attributable to ARLP increased 75.5% and adjusted EBITDA attributable to ARLP increased 26.4%. Net income in the 2026 quarter benefited from a $16.5 million increase in the fair value of our digital assets and a $6.3 million noncash gain from remeasuring our previously held equity interest in AllDale III in connection with the AllDale III and IV acquisition. Partially offsetting these items were higher income tax expenses and a $7.3 million loss on derivative instruments assumed in the acquisition, of which $6.7 million was unrealized.

Income from our equity method investments was $12.8 million in the 2026 quarter compared to $4.5 million in the 2025 quarter and $9.5 million in the sequential quarter. The increase was driven primarily by higher income and valuations by our investments in the Gavin Power Plant and the NGP fund, both of which continue to perform well. As a reminder, results from these investments can vary from quarter-to-quarter as valuations change.

Turning to coal operations. Sales volumes were 9.3 million tons, up 7.4% year-over-year and 9.2% sequentially. Segment adjusted EBITDA increased to $186.8 million up 18.6% year-over-year and 23.1% sequentially as higher volumes and lower per ton expenses more than offset lower average pricing. Our average coal sales price per ton was $53.93 in the 2026 quarter, down 8.3% year-over-year and 1.7% sequentially, primarily due to a higher sales mix of lower priced Tunnel Ridge volumes.

Segment adjusted EBITDA expense per ton was $35.64, improving 13.1% year-over-year and 7.9% sequentially. The reduction in per ton expense more than offset lower average pricing, increasing the spread between sales price and segment adjusted EBITDA expense to $18.29 per ton from $16.19 per ton in the sequential quarter. In the Illinois Basin, coal sales volumes were 7 million tons, up 6.4% year-over-year and 10.5% sequentially, driven by the resumption of longwall production at Hamilton. Illinois Basin coal sales price per ton was $51.16 in line with comparable periods while segment adjusted EBITDA expense per ton improved to $31.77, down 10.2% year-over-year and 11.1% sequentially, due to higher production at Hamilton and improved per ton cost at our River View complex.

Illinois Basin segment adjusted EBITDA was $139.8 million, up 32.6% year-over-year, and 34.1% sequentially. In Appalachia, wholesales volumes were 2.3 million tons, up 10.7% compared to the 2025 quarter and up 5.7% compared to the sequential quarter on strong sales at Tunnel Ridge. Appalachia coal sales price per ton was $62.35 down 25.1% year-over-year and 1.9% sequentially, primarily due to the higher sales mix of lower priced Tunnel Ridge volumes that I mentioned a moment ago.

Segment adjusted EBITDA expense per ton was $46.25, improving 19.9% year-over-year and essentially flat sequentially due to increased production at Tunnel Ridge and a higher sales mix of lower cost tunnel ridge volumes.

Shifting to our royalty segments. Total royalty revenues were $87.5 million, up 52.5% year-over-year and 26.4% sequentially and segment adjusted EBITDA attributable to ARLP was $61.8 million, up 40% year-over-year and 22.8% sequentially. The 2026 quarter was the first full quarter, including AllDale III and IV in our Oil & Gas Royalty segment.

Oil & Gas Royalty revenues were a record $59.8 million and BOE volumes were a record $1.45 million, up 61.3% year-over-year and 54.9% sequentially, primarily due to the acquisition. Average sales price per BOE was $41.21, up 15.5% year-over-year as higher realized crude oil prices more than offset the greater natural gas weighting following the acquisition. Sequentially, average price declined 16.6%, primarily due to lower realized crude oil prices and a higher natural gas mix.

Oil & Gas Royalties segment adjusted EBITDA attributable to ARLP was $43.6 million, up 61.4% year-over-year and 16.8% sequentially. The Coal Royalties segment adjusted EBITDA was $18.2 million, up 6.2% year-over-year and 40% sequentially driven by higher royalty tons sold, primarily from Tunnel Ridge and Hamilton.

As of September 30, 2026, total debt and finance leases outstanding were $679.9 million our total and net leverage ratios were 0.89 and 0.78x debt to trailing 12 months adjusted EBITDA attributable to ARLP. Net debt, which we define as total debt and finance leases less cash was $595 million at September 30 compared to $479 million on June 30, 2026. That increase of $116 million is well below the $206.2 million AllDale III and IV purchase price we paid on July 1.

We ended the 2026 quarter with total liquidity of $430.8 million. Additionally, we held 673 Bitcoins valued at $56.3 million at quarter end. Our cash flow trends continued to strengthen during the quarter. Free cash flow was $198.6 million in the 2026 quarter. Distributable cash flow increased to $136.8 million in the 2026 quarter, up approximately 29% year-over-year and up 27% sequentially. Our distribution coverage ratio increased to 1.76x, representing a significant improvement relative to comparable periods.

Turning to our updated 2026 guidance with 1 quarter remaining in the year, we are tightening our guidance ranges. In coal operations, we now expect total coal sales volumes of 34.5 million to 35.5 million tons, which raises the midpoint of our prior range with coal sales price per ton of $54.25 to $54.75 and segment adjusted EBITDA expense per ton of $37.50 to $38.50.

In the Oil & Gas Royalty segment, our tightened volume ranges reflect a slightly higher natural gas weighting following the acquisition of the AllDale III and IV acquisition, and we have also tightened our consolidated guidance ranges. Reflecting the consolidation of our AllDale III and IV, our consolidated guidance now includes ranges for both net income and adjusted EBITDA attributable to noncontrolling interests, which are detailed in our press release. As is our usual practice, we expect to provide 2027 guidance with our fourth quarter results in February.

And with that, I'll turn the call over to Joe for his comments. Joe?

Thank you, Cary, and good morning, everyone. Thank you for joining our call today. We had an outstanding third quarter, led by strong shipments from our coal operations. Hamilton's returned to longwall production and solid operating performance at Tunnel Ridge and our River View complex.

Segment adjusted EBITDA at our coal operations increased 18.6% year-over-year and 23.1% sequentially. While segment adjusted EBITDA expense per ton sold declined 13.1% year-over-year and 7.9% sequentially. Additionally, as Cary said, our Oil & Gas Royalty segment results benefited from our first full quarter, including AllDale III and AllDale IV.

Before turning to operations results, I wanted to take a moment to congratulate our mine rescue teams for their exceptional performance at the National Mine Rescue Competition posted in Tennessee during August. Members from our Alliance coal team took the stage 12 times during the award ceremony this year, including individual recognition for a national champion, a national runner up and 3 state team championships.

On the production side, our coal operations teams delivered across the board. At Hamilton, the longwall returned to production following an extended move set monthly production records in July and August and was our lowest cost operation in the 2026 quarter. That performance was the primary driver of a 10.2% year-over-year and 11.1% sequential improvement in Illinois Basin segment adjusted EBITDA expense per ton.

Tunnel Ridge continued to deliver strong sales, helping hold Appalachia segments and adjusted EBITDA expense per ton essentially flat sequentially and lower by 19.9% versus the 2025 quarter. These improvements are the direct result of capital we invested in our operations over the past several years, leading to a lower cost, more reliable platform.

One additional development from the quarter involves our Mettiki operation. You may recall, we issued a warn notice in the first quarter of 2026 and suspended mining operations. We are pleased to announce a new multiyear coal supply agreement with our largest historical customer that will allow the mine in nearly 150 miners to return to coal production operations. The mine has been transitioning from longwall mining to what we plan to be a 2 room and pillar mining sections, 2 shifts a day by the end of the first quarter of 2027 and to better align production with customer demand. As a result of winning this business, 2027 production from the Mettiki mine, is expected to be approximately 550,000 tons higher than 2026. EBITDA expense per ton next year should be lower than 2026 as well.

On the commercial side, domestic coal burn improved in the third quarter after a soft first half of the year. Sustained late summer heat drove record September power demand and coal-fired generation in September was up more than 40% year-over-year in PJN and roughly 25% to 33% across the Southeast, the Carolinas and Tennessee. That burn drew Eastern U.S. domestic coal inventories down to slightly below last year's levels.

Near-term solicitation activity remains measured as customers take a wait and see approach heading into winter. But we view that as a matter of timing, not a change in underlying demand. We continue to convert this constructive market into contracted volumes. During the 2026 quarter, we added 4.2 million committed and priced tons through 2028, and we remain essentially fully committed at the midpoint of our 2026 sales volume guidance with 31.7 million tons committed in price for 2027 which includes 700,000 tons to be shipped to meet Mettiki's new sales commitment I just talked about.

We expect to enter next year with substantial visibility and the operating capacity to capture additional demand as commercial opportunities develop.

Export markets have become a more meaningful component of our sales portfolio with 3.7 million tons committed and priced for 2026 and 3 million tons for 2027. Export volumes have come in well above our expectations entering this year. Seaborne thermal prices strengthened through the quarter, with APIII rising from about $105 per ton at the start of the quarter to about $140 per ton by the end of September. And industry analysts have raised their outlook for U.S. thermal coal exports for both this year and next. Market conditions remain dynamic, and we remain cautiously optimistic that additional export opportunities could provide upside to our sales volumes next year.

Turning to the broader markets. We believe the fundamentals supporting coal demand continued to build. Electricity load in the markets we serve is growing, while permitting, interconnection and supply chain constraints are slowing the pace at which new generation can come online. According to [indiscernible] GE Venova, the leading gas turbine manufacturer is now sold out of new turbine deliveries until 2031. We believe this dynamic will extend the runway for the existing coal fleet. On data center demand specifically, the market is becoming more disciplined, and we think that is a healthy development. Utilities and grid operators are increasingly counting only contracted financially committed data center load in their forecast. Even on the stricter basis, the market still expects demand growth to be substantial and new generation has taken years longer to build than planned. Both trends point to the same conclusion. The existing coal fleet will be needed longer and running it harder is the fastest and most affordable way to serve that load. We expect the impact to become increasingly visible in our customers' coal burn, as data center-driven demand materializes with the more meaningful impact beginning in late 2027 and into 2028. Affordability is central to this discussion.

We continue to see evidence that existing cogeneration remains cost competitive. One example is a recent Indiana study by always on energy research which concluded that existing coal plants become increasingly cost competitive the harder they run and 75% of the state's coal plants could produce electricity more cheaply than the new combined cycle gas. The same analysis found that Indiana's existing combined cycle gas fleet already ran at an 83% utilization in 2024, leaving limited room to serve new load, which makes the existing coal fleet well suited to meet incremental demand.

Federal policy continues to recognize the value of the existing coal fleet and the administration continues to take the steps necessary to protect it. In September, the EPA finalized a rule repealing most of the 2024 greenhouse gas standards for power plants, including the carbon capture requirements for existing coal units and proposed repealing the remaining standards. More broadly, there is growing recognition among all stakeholders that leadership in artificial intelligence and the security of the grid are national security priorities for our country, and then both depend on abundant, reliable and affordable electricity.

Taken together, we believe these actions support extending the operating lives of existing coal plants as critical grid resources.

Turning to Oil & Gas Royalties. I want to briefly highlight our record results, which included the first full quarter with the AllDale III and IV acquisition. As we continue to scale the portfolio, Oil & Gas Royalties is contributing a more meaningful share of ARLP's consolidated free cash flow, highlighting the growing importance of the segment within our overall business. If today's higher crude oil prices remain elevated, we could be in a position to have another record quarter to finish the year.

We are also excited to increase our exposure to gas-weighted resource plays in the Haynesville given the long-term tailwinds from LNG exports and power demand. Going forward, we will remain disciplined in reinvesting the after-tax cash flows generated by the Oil & Gas business in existing regions that meet our risk-adjusted return thresholds. That concludes our prepared comments, and I'll now ask the operator to open the call for questions.

[Operator Instructions] Our first question comes from the line of Matthew Key with Texas Capital Securities.

Great job on the quarter. I wanted to start off on Mettiki first, congrats on the multiyear coal supply agreement there. I was wondering if you could provide some more color on what changed there as you kind of navigate that process? It seems like a great outcome. It should be a pretty meaningful tailwind in 2017.

I think that we had just continued conversations of the importance of our operation to their security of supply as they look at their demand for electricity caused by the data center contracts that they signed. They spent quite a bit of time looking at capital improvements at there at the Mount Storm plant and through just continued conversations, I think they recognize the value that we bring by giving them sustainable coal production at a level that if we weren't there, would make it a lot more risky for them. So we appreciate their trust in us, and we really are excited to be able to provide opportunities for the miners in that region.

And we do believe that even though it's not at the scale we would like by converting to a continuous minor operation. It will give us a little bit more opportunities to participate in the export met market because we can be a little bit more selective in mining the seams that gives us a better quality product to access the export met market.

So like I say, it's great that we've got the additional volume. We can keep the mine open. And we do believe that, that will improve our results in 2027 as we did have quite a bit of -- we did have some loss in '26 while we were waiting for this contract to materialize.

Got it. That's helpful. And I guess the next 1 would be for me. Just kind of just comment on the strong cost performance in [indiscernible] I know a big factor in that was the resumption of longwall production at Hamilton. But I'm curious about your view about how sustainable that cost performance is as we look out to the coming quarters. Basically, was this a uniquely strong quarter for the segment? Or should we kind of consider this close to a new normal in the Elanor basin?

I think that as you look to the fourth quarter, it should be comparable and it is normal in that sense. As you look at '27 given the fact that Hamilton was down half of the year, we should see improvement in '27 relative to '26. We have potential with the export market that gives us some more demand next year that we could expand volume a little bit more. So we do have some excess capacity, if the market would allow us to do that. And we do have that ability to mine a few more times that could help our costs as well.

So we feel very good that we can maintain costs at the level we are with inflation pressures that are occurring throughout the supply chain. So again, it's a tribute to our operations for their focus on productivity and being a low-cost producer.

Our next question comes from the line of Nathan Martin with Stonex Group.

Congrats on closing the AllDale transaction. Joe, I just wanted to come back to the export opportunity comments you made, how that could possibly provide some upside to sales volumes next year. How would you frame that potential upside versus the 35 million-ton midpoint of this year's sales guidance, and would you have to make any operational changes or investments to produce those incremental tons?

To answer your latter question, no, we don't need to make any additional investments or operational changes to be in a position to produce more. The price -- the reason I feel somewhat optimistic is the price curve is very constructive for export shipments. However, we are facing some logistical headwinds, barge capacity has become very, very tight due to aggregate movements that are necessary or I must project down Louisiana, that's sort of -- we're competing, I guess, for barges that in the [ Olin ] Basin that could impede our ability to grow beyond where we are. .

And also the increased cost in both ocean freight as well as the barge businesses is eating up a lot of the margins that historically when we've talked about 125 is sort of a threshold. We'll have to see that stabilize a little bit. But the real key is, can we get the tons outside the country. So if we can clear up some of the logistical issues, we're pretty confident that we could exceed our volume this year maybe by 0.5 million or 1 million tons.

Okay. Great. And then along those lines, Joe, you mentioned 125 just to kind of do that threshold. What kind of netbacks are you guys seeing right now API2 prices currently and at least the high 140s, I think, last I looked.

Yes. So again, it's raised by operation, we go to Hamilton, it has a sulfur discount to it. If we go to Gibson is pretty consistent with what the domestic markets are and the discount is varies by customer by customer. So prefer not to talk about that given the fact that we're continuing to negotiate with our training partners on that.

Okay. I appreciate that. Maybe 1 final question. Just coming back to Mettiki, you mentioned the export met possibility there. Can you remind us how many tons we could see come out of that operation?

So we think we could expand another couple of hundred thousand tons beyond the Dominion contract and many contracts were 700,000 tons next year. So we feel like it's possible we could have 150,000 to 200,000 tons in the met market...

Our next question comes from the line of Mark Reichman with Noble Capital Markets.

Thank you. You've been doing a great job signing committing new volumes. I was just kind of wondering how those 2027 committed in price volumes, how the pricing is looking there relative to the 2026 pricing?

Market has been trending up. So we've been able to capture some of that. I think it's a little early to project exactly where it will be, but we do expect 2027 revenues to be equal to, if not slightly higher than where we are on a consolidated basis for the coal segment. And in the out years, '28, the pricing is a little bit stronger to where, again, we should be able to maintain, if not grow our revenue on a per ton basis for the next 2 years. A lot of that but we'll have to see...

Well, that's very helpful. The -- on the equity method investments, I was just kind of curious, you had $12.8 million versus I think it was $9.5 million in the second quarter? And how much of the third quarter contribution came from Gavin versus other equity investments and is that $3 million quarterly guidance, is that still appropriate? Or is there a way to kind of think about how much investors should expect in terms of kind of recurring income from those investments?

Yes, Mark, on that one, as I mentioned in my remarks, those 2 investments continue to perform well. If you look at that total number there, about 85% of that was associated with Gavin. Our investment there. The remaining piece of it would be the NGP investment. Both those investments continue to perform well. It's really hard to predict what that number is going to be on a quarter-to-quarter basis. We're invested in funds there. So we're subject to fund investment accounting there. So that kind of gets revalued really at the end of each quarter, kind of the way that we look at it in some of our past guidance where we've talked about $3 million of distributions, we kind of focus on the distribution number that comes out of it. Now the distributions have been strong in the last couple of quarters, $8.5 million this quarter. I think it was $10.7 million the quarter before. .

We still think, as we look at that kind of that $3 million to $4 million per quarter is just a good number to count on. That's kind of how we look at it in terms of distributions coming in. What that earnings is going to be is going to bounce around there, and that's really hard to project. But that's kind of how we look at it. And so we kind of count $3 million to $4 million per quarter just in terms of cash distributions coming in.

Just on the oil and gas business, I mean, which has really performed well. When you think about 2027 royalty production, I don't want to get ahead of guidance, but like how much of that -- how much of the production do you anticipate would kind of come from existing producing wells versus new drilling on undeveloped acreage. I'm assuming the operators -- the development activity has gone up in response to the commodity prices. But I mean, do you think because of that, you're going to see some pretty strong organic growth in 2027 really without the need for additional acquisitions? Or are you still pretty much focus on continuing to make acquisitions where they're available.

Yes, I think we'll definitely continue to focus on making acquisitions. I mean, our focus is to continue to reinvest that cash flow that we have within that business there. I do think when you look at volume growth, I think even if we didn't make acquisitions, you would continue to see volume growth associated with our existing assets that we have there. So -- we're very optimistic in terms of what the volumes will be for us next year in terms of looking at the year-over-year growth.

We're right in the middle of doing our reserve studies for the fourth quarter right now. So when we get to February and we talk about what our guidance is there, we'll have a pretty good handle of it at that point in time. But we should see some pretty good volume growth next year just because from the fact that we'll get a full year benefit from our AllDale III and IV acquisition as well.

We are seeing private invest back to our there with these high prices, there are people that are going and trying to increase their volumes to take advantage of that higher price environment.

Right. Well, thank you very much. I really appreciate that, and it was a great quarter.

Our next question comes from the line of Michael Mathison with Sidoti & Company.

Congratulations on the quarter. Yes. Just coming to my questions, some of the good news you saved to the end, which is reopening the Mettiki mine. I recall that you had a very big asset write-down in Q1 regarding to shutting the mine. What does reopening mean in terms of that carrying value?

I think as we reopen, we don't plan to -- I mean we'll do some investments in equipment, but it's not really going to change what that carrying value is on the balance sheet. So that number will continue to remain where that is. We are making investment. We did write it down to the point where most of the assets on the balance sheet are mobile type assets there. So I don't really anticipate any additional adjustments in terms of balance sheet adjustments at this point in time associated with restarting the operation.

Great. Coming to the impact of the AllDale acquisitions, you took on some debt, you didn't fund the whole thing with debt, how much of it was cash, but there was some increase in debt. Do you foresee paying that debt down? Or would you expect to just continue to operate at this leverage level?

No. I mean the debt facility, so we did 2 things to fund that acquisition. We did draw at the end of the last quarter on our existing revolving credit facilities for about 3/4 of that total transaction. We did enter into a new $150 million short-term debt facility at minerals. So that's an 18-month facility. We do anticipate amortizing that down on a quarterly basis. And so we made our first quarterly payment right at the end of September associated with that.

So we will use the minerals cash flow to pay that facility down. We will still have a good amount of additional cash flow over and above that to continue to invest in additional minerals assets and financing markets are very supportive of this asset class. And so there is additional debt capacity. So in the event we see more sizable type acquisition other than just funding out of cash flow. There could be opportunities to enter into other facilities or continue on with this facility as well to support that growth.

Okay. Great. Very helpful. Looking at another use of cash, your distribution coverage ratio was 1.76 in the quarter. That's a 3-year high. Is there any possibility of an increase in the quarterly distribution? Or would you be prioritizing the debt paydown instead or other uses of cash?

I'd say we would more than likely be even our powder dry on that. We've got several things that we're considering. We're -- if the deal flow is there for minerals, I think we would continue to invest in that. And like Cary just said, we could potentially go higher than what their net cash is. And yes, so we're looking at other opportunities to how we could -- what the capital allocation would be. But I think right now, we want to stay at the 1.5x coverage ratio or greater. And I think that's a target that we must sustain beyond 1 quarter before we would consider increasing distribution.

Sure. That's very helpful. And again, congratulations on the great results.

Thank you. Ladies and gentlemen, that concludes our question and answer session. I'll turn the floor back to Mr. Marshall for any final comments.

Thank you, operator. To everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. We expect to report fourth quarter and full year 2026 financial and operating results in early February and look forward to speaking with you then. This concludes our call for the day. Thank you.

Thank you. This concludes today's conference call. You may disconnect your lines at this time. Thank you for your participation.

Greetings, and welcome to the Alliance Resource Partners Second 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, Senior Vice President and Chief Financial Officer. Thank you, sir. You may begin.

Thank you, operator. Good morning, and welcome, everyone. Earlier today, Alliance Resource Partners released its second quarter 2026 financial and operating results. We will review the quarter, discuss our outlook for the remainder of 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 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, in 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 second quarter 2026 results, expand on our recently closed Oil & Gas Royalties acquisition and discuss our updated guidance for 2026 before turning the call over to Joe Craft, our Chairman, President and Chief Executive Officer, for his comments.

Overall, results for the second quarter of 2026, which we refer to as the 2026 quarter, were higher on a year-over-year and sequential basis. Compared to the prior year, which we refer to as the 2025 quarter, total revenues increased to $551.6 million, net income attributable to ARLP increased 33.9% to $79.6 million or $0.61 per basic and diluted limited partner unit and adjusted EBITDA increased 14.7% to $185.7 million. Compared to the first quarter of 2026, which we refer to as the sequential quarter, total revenues increased 6.9%, net income increased $70.5 million and adjusted EBITDA increased 19.8%. These results were driven primarily by higher coal sales volumes, improved coal operating cost performance, record results from our Oil & Gas Royalties segment and higher income from our equity method investments, with net income comparisons also affected by impairment charges recorded in the prior periods.

Turning to our coal operations segment. Total coal sales volumes were 8.6 million tons in the 2026 quarter, up 2.1% compared to the 2025 quarter and up 8.9% compared to the sequential quarter. Total coal production was 8.2 million tons, up 1.5% year-over-year and 3% sequentially. Segment adjusted EBITDA from coal operations was $151.7 million, up 6.9% year-over-year and 21.3% sequentially. Our average coal sales price per ton was $54.87 in the 2026 quarter, down 5.3% year-over-year and 2.7% sequentially, reflecting the expected roll-off of higher-priced legacy contracts at Tunnel Ridge and a lower percentage of Mettiki sales in Appalachia.

Segment adjusted EBITDA expense per ton was $38.68, improving 6.3% year-over-year and 6.6% sequentially. This cost improvement was a key contributor to the quarter's stronger coal operating results and reflects the significant investments we have made in our minds over the past few years to ensure they can operate efficiently and at lower cost. In the Illinois Basin, coal sales volumes were 6.4 million tons, down 4.5% year-over-year and up 4.9% sequentially. Our River View complex delivered strong productivity and sales performance, helping partially offset lower Hamilton shipments associated with our planned extended longwall during the 2026 quarter. Illinois Basin coal sales price per ton was $51.87, up modestly year-over-year and sequentially, while segment adjusted EBITDA expense per ton was $35.99.

in Appalachia, coal sales volumes were 2.2 million tons, up 27.6% compared to the 2025 quarter and up 22.3% compared to the sequential quarter, primarily due to increased production at Tunnel Ridge. Appalachia coal sales price per ton decline to $63.57, reflecting the expected roll-off of higher-priced legacy contracts at Tunnel Ridge. One of the most notable highlights in the region was segment adjusted EBITDA expense per ton at $46.22, which improved 29.7% year-over-year and 25.7% sequentially due to higher productivity and improved recoveries at Tunnel Ridge. ARLP ended the 2026 quarter with total coal inventory of 0.8 million tons, down 0.3 million tons from both the 2025 quarter and the sequential quarter.

Shifting to our royalty segments. Total royalties revenues were $69.3 million, and segment adjusted EBITDA was $51 million in the 2026 quarter. Our Oil & Gas Royalties segment delivered record quarterly revenue of $46.5 million, up 31.1% year-over-year and record segment adjusted EBITDA of $38 million, up 27.2% year-over-year. While BOE volumes of 936,000, were up 6.4% year-over-year and down 8.4% sequentially. Higher average realized sales price per BOE was the main driver to the favorable variances during the 2026 quarter, increasing 22.7% year-over-year and 22.1% sequentially.

The Coal Royalty segment adjusted EBITDA was $13 million, up 9.7% year-over-year and 5.7% sequentially, driven by higher royalty tons sold, primarily from Tunnel Ridge and the River View complex. As it relates to our balance sheet and cash flow, as of June 30, 2026, total debt and finance leases outstanding were $590.2 million, and we had $111.2 million of cash. In anticipation of the closing of the AllDale III & IV acquisition on July 1, we drew $56 million on our revolving credit facility at quarter end to fund part of that purchase price. As a result, our total and net leverage ratios were 0.82x and 0.67x debt to trailing 12 months adjusted EBITDA. We ended the 2026 quarter with total liquidity of $424 million, which also included $312.8 million of borrowings available under our revolving credit facilities. In addition, we held 646 bitcoins, valued at $37.8 million based upon a bitcoin price of [ $50,559 ] per coin as of June 30, 2026, which was down 14.1% sequentially and resulted in a $6.3 million decrease in the fair value of digital assets and an impact of $0.05 per basic and diluted limited partner unit for the 2026 quarter.

For the 2026 quarter, distributable cash flow is $108.2 million and our distribution coverage ratio was 1.39x, representing a 39% increase compared to the sequential quarter.

Turning to our Oil & Gas Royalties acquisition. Subsequent to quarter end, on July 1, 2026, we completed the previously announced acquisition of certain general partner and limited partner interest in AllDale Minerals III, LP and AllDale Minerals IV, LP for $206.2 million, subject to customary post-closing adjustments. As described in our June press release, the transaction implied an aggregate gross valuation for the AllDale III and AllDale IV funds of $410 million and involved the acquisition of $306.2 million of third-party interest across the 2 funds with the difference between the gross valuation and the $306.2 million of third-party interest acquired reflecting existing interest already owned by ARLP and craft related parties. ARLP acquired $206.2 million of the third-party interest while craft-related parties separately acquired $100 million of the AllDale III limited partner interest, and both ARLP and the craft related parties rolled forward their existing ownership interest.

After closing the transaction, Alliance owns and controls 100% of the noneconomic general partner interest and has an approximate 61% economic interest across the 2 funds. ARLP did not acquire interest from the craft-related parties, and the entire transaction structure was reviewed and approved by our Conflicts Committee, which is comprised entirely of independent directors. The net benefit of the transaction structured ARLP is twofold: First, participation by the craft related parties allowed us to complete the acquisition at its full scale while maintaining a disciplined investment level and improving our expected returns on investment capital; and second, it preserves liquidity and financial flexibility for our team to continue advancing our ground game acquisition efforts where we remain active with acquisitions exceeding $15 million in each of the last 3 quarters.

We funded our $206.2 million acquisition using a combination of cash on hand, borrowings under our revolving credit facility and a new $150 million term loan at Alliance Minerals LLC. The term loan has an 18-month maturing, scheduled amortization and bears interest at SOFR plus a pricing grid ranging from 175 to 225 basis points based on the amount of the loan outstanding. Looking forward, we expect to prioritize reducing leverage and maintaining financial flexibility while continuing to evaluate disciplined minerals acquisition opportunities.

Turning to updated 2026 guidance. We are maintaining our overall coal sales volume guidance of 33.75 million to 35.25 million tons. Coal sales price guidance of $54 to $56 per ton, and total segment adjusted EBITDA expense guidance of $37 to $39 per ton. We view these ranges as balanced with any upside continuing to depend largely on summer burn activity and the pace of utility inventory draws over the remainder of the year. Contracting activity is a significant positive during the quarter, which Joe will discuss in more detail in a moment. But in short, we're essentially fully committed and priced for 2026 at the midpoint of guidance, with strong momentum already building for 2027.

In the Oil & Gas Royalties segment, we are increasing full year volume guidance to reflect the AllDale III & IV acquisition beginning in the third quarter of 2026. We now estimate 1.95 million to 2.05 million barrels of oil, 10 million to 10.5 million Mcf of natural gas and 1.1 million to 1.2 million barrels of natural gas liquids for the full year. Because the AllDale III & IV acquisition closed on July 1, 2026, production, revenue and income will be reported on a consolidated basis beginning in the third quarter, with amounts attributable to the craft related parties ownership reflected as noncontrolling interest. Combining that interest in the existing noncontrolling interest in Cavalier Minerals JV, our guidance includes an estimated $13 million to $15 million of net income attributable to noncontrolling interest, reflecting 6 months of AllDale III & IV and a full year of Cavalier. Please note the AllDale III & IV acquisition did include hedges related to oil and gas. So we have also included a summary of the commodity derivatives that were assumed as a part of the acquisition in our earnings release.

And with that, I'll turn the call over to Joe for his comments. Joe?

Thank you, Cary, and good morning, everyone. Thank you for joining our call today. Alliance delivered a superb second quarter, highlighted by coal's improved operating performance, record Oil & Gas Royalties results and meaningful commercial transactions, headlined by our minerals acquisitions and another exceptional quarter of booking sales by our marketing team, who secured 21.2 million tons of new commitments. New domestic sales commitments totaled 18.5 million tons spread out over the next 5 years.

There was a brief period of time during this 2026 quarter when export pricing presented at attractive opportunities, and we secured 2.7 million tons of export commitments over the 2026 to 2028 time period. On the production side, I want to give a shout out to all of our coal operations teams whose performance with seller across the board. At Tunnel Ridge, our longwall move from Panel '27 to Panel '28 was the second fastest 12 [indiscernible] face-to-face move in the mine's history, and the operation closed June with its highest shipping months since 2023.

Hamilton brought its longwall back online in mid-May and has shown consistent improvements in key operating metrics, and recovery yields this month have been at record levels for that coal mine. At our River View complex, strong productivity at [indiscernible] Henderson mine and the River View mine, have positioned us ahead of our internal production targets for both the 2026 quarter and year-to-date. Gibson South and [indiscernible] continued to be steady performers contributing to our outstanding results in the Illinois Basin.

At Mettiki mining, we moved from a 4-day to a 5-day production schedule on the strength of new business secured by our marketing team. A good example of our commercial and operating teams working in tandem. With 2026 longwall moves behind us and no additional moves expected until 2027, we believe our whole operations are well positioned to meaningfully increase production and cash flow generation during the second half of the year. We also expect to see cost improvements across the portfolio as productivity gains flow through the system and our key mines operate at more normalized run rates. Our strong contracted sales book helped limit the impact of lower domestic coal demand in the first half of this year that was caused by mild weather and lower natural gas prices.

As Cary mentioned, we are essentially fully committed at the midpoint of guidance, and we now have 29.4 million tons committed and priced for 2027 delivery. We believe this level of forward commitment reflects both the strategic importance of our coal supply and the covenants customers place in ARLP's ability to deliver.

Turning to the broader markets. PJM capacity auction results earlier this month serve as another important reminder of the structural tightness developing in power markets. The 2028, 2029 base residual auction cleared at the $325 per megawatt day cap for the third consecutive auction, while total clear capacity remained well short of PJM's reliability requirement. We believe these results reinforce the value of dispatchable coal-fired generation needed to maintain system reliability. Recent operating conditions have already put that scarcity to the test. On July 1, PJM served a preliminary hourly peak, 161.9 gigawatts and had to invoke top weather maximum generation and load management procedures. It posted another maximum generation alert on July 15, and [ MISO ] was under a similar alert that same day with demand above 120 gigawatts.

The Department of Energy has continued to lean on its Section 202C emergency authority to keep generation available in both markets and separately authorized PJM to draw on backup generation in data centers and other large facilities as an emergency reliability resource. In our view, these events reinforce the point we have been making: As electricity demand grows, the grid need reliable, dispatchable baseload capacity from all existing resources.

Federal policy is also acknowledging that preserving and modernizing existing cogeneration can be a faster and more cost-effective way to support reliability. The DOE recently announced up to $500 million of Defense Production Act Title III funding for 13 coal-fired plants, 6 of which we sell to, aimed at improving efficiency and extending plant life. Last week, President Trump announced a major expansion of the voluntary rate payer protection pledge, which has been signed on to by most electric utilities that serve the data center build out. The pledge is intended to prevent other electricity rate payers from bearing the cost of electricity for data centers.

Holding amicus power, one of the best ways to provide power for data centers is to take advantage of the existing coal fleet. They went on to say the existing coal fleet is being underutilized and can generate more of the electricity that is needed by data centers without incurring the cost of new power plants and expensive infrastructure that can take years to build.

Turning to Oil & Gas Royalties, the segment delivered another record quarter, and the July 1 closing of the AllDale III & IV acquisition marks the next phase of growth for this platform. With this transaction, our cumulative investment in Oil & Gas Royalties now exceeds $1 billion, a significant milestone in the evolution of this platform. I'll repeat what I stated, when we announced the transaction in June, this acquisition accelerates the continued growth of our Oil & Gas Royalties segment adds scale and development upside across multiple U.S. basins, is anchored by a meaningful Permian position and expands our natural gas footprint with entry into the Haynesville, a resource play well-positioned to benefit from the long-term LNG export demand growth. We expect this acquisition to be immediately accretive to ARLP's free cash flow per unit, increasing our estimated distributable cash flow per unit by 8% to 9% next year.

Looking ahead, our strategic priorities remain unchanged, maintaining a strong, conservatively managed balance sheet, investing with discipline in our core businesses. and positioning Alliance for continued growth while delivering attractive after-tax returns to our unitholders.

That concludes our prepared comments, and I'll now ask the operator to open the call for questions.

[Operator Instructions] Our first question comes from the line of Matthew Key with Texas Capital Securities.

I wanted to start just on capital allocation and how you guys are thinking about it for the remainder of the year. Obviously, you just executed a pretty big acquisition on the Oil & Gas Royalties segment. But I was wondering if there would be more of an appetite for incremental M&A as we progress through the remainder of 2026?

Yes. So in addition to the announcement we made July 1, we did also invest in about $16 million of oil and gas reserves during the quarter, which is like, I think, the third quarter in a row that we've been able to do ground game acquisitions at that level. So we have included in our plan for the year, giving them the opportunity to continue that at that pace. We'll continue to look at other deals if they're attractive to us. in the coal space, we do have some reserve issues we're looking at. There could be some small investments that we're planning to make.

And we're also looking at different things that will continue to allow us to meet our goals and objectives. We're pleased with the investment we made in the Gavin power plant. So we continue to have that on our list of things to consider as we move forward. So we feel like we're in a great position, and we do have some opportunities. We're excited about as we look forward with the growing energy demand due to the data center investments.

Got it. No, that's very helpful. And I just wanted to ask about volume cadence over the second half of '26. Obviously, no major longwall moves in the back half of this year. So should we be thinking 3Q, 4Q should look pretty similar from a volume and cost perspective? Or are there any kind of other moving parts we should be considered as we model the back half?

I think with the Hamilton starting up mid-May, it's going to be producing at a higher run rate than what you've seen in the second quarter -- in the first quarter. So you're going to see probably a doubling of that production in the third quarter versus the second quarter. And that will drive costs lower for the Illinois Basin. We're also -- I think that would be the major issue as you're thinking about both the third quarter, which would continue into the fourth quarter.

Cary, if you have anything to add to that?

Yes. Yes. I think, Matt, as you take a look at the back half of the year, we did, what, roughly $16.5 million sales in the first half. So that implies a pickup in the back half of the year about -- to get to the midpoint of the guidance range, another 18 million tons of sales or so. I think it's reasonable to expect that, that can be spread out pretty evenly between the last 2 quarters. As Joe mentioned, we will see a pickup in the Illinois Basin just because we'll have Hamilton back online in the back half of the year, and so that's obviously leading to a lot of that pickup in volumes.

But I think when you look at the back half, it's definitely reasonable to assume, just in total kind of that volume cadence about $9 million each one of the quarters to get to the midpoint of the range.

Our next question comes from the line of Nathan Martin with Benchmark [ StoneX ].

Congrats on closing the AllDale transaction. Maybe just following on Matt's questions for the back half of the year. We saw a pretty significant quarter-over-quarter decline in realized price per ton for the Appalachia segment. I know you guys mentioned there's increased sales mix of lower priced to Ridge tons there. I think some of the sales price are coming to Mettiki as well. But how should we think about the realizations in the second half? Do you expect them to kind of remain at those levels? Could they improve? Or could they draw down a little bit more as some of those contracts roll off that you guys talked about?

I think we're pretty stable on pricing for both the Illinois Basin and the Appalachian Basin for the rest of the year comparable to the second quarter revenue numbers based on our contracts. It will depend on the actual timing of some of those shipments, but it should be pretty consistent with the second quarter revenues on a per ton basis.

Okay. Got it. Joe, I appreciate that. And then committed in price, 21.2 million tons as you guys said for '26, all the way out to 2031, just since last quarter. How would you categorize the pricing on those tons versus maybe your price per ton guidance for full year '26?

I'd say they're within basically where the indexes are trading today with some inflation or factored in going forward. So there will be some increases to those contracts, but that would be in the basin mid-50s and then Northern at mid-60s, would be the price targets.

Okay. Very helpful. Appreciate that. And then I guess just one other question. Costs has been much better than expected, offsetting that lower pricing in Appalachia. I think, Cary, you kind of just talked about this on the previous question. Should we kind of expect those costs to remain where they are? Or maybe it can get a little bit better? It looks, like just carrying them forward, we'd probably be at the lower end of the cost per ton guidance for the full year, but I would appreciate any thoughts there.

Well, I think if you kind of look in the back half of the year, when you look at where our cost guidance is, it does imply to kind of get to the midpoint of where our cost guidance range is, about a 10% reduction on a going-forward basis in the back half of the year compared to what we experienced in the first half of the year. So I think that's kind of a good marker that's out there, maybe shaded a little bit more to the Illinois Basin than Appalachia, but we should see cost improvements at both of those regions going forward, somewhere in the neighborhood of that 10% of what I'm talking about or what I just mentioned previously.

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

Yes. So you now have 29.4 million tons committed in price for 2027. So you added, what, about 5.6 million tons domestically and more than doubled the exports to 2.7 million. I was just curious what are utilities telling you about their expected coal burn over the next several years? And do you believe the increase in the electricity demand I mean, what are your expectations for 2027 versus 2026 in terms of your overall production and sales profile?

As we looked at '27, I think we will what we've already got embedded pretty much is Hamilton running at the second half run rate for the full year. So that should be another 1 million tons, could be a little higher depending on the market. So that's the major change. Our River View complex has been running really well. Tunnel Ridge has been run well. But I think that as we would look at it today, we're probably 1 million to 1.3 million more volume next year if things go as planned. Based on our current utilization, we do feel that the demand will be available for us.

Everything is always -- market conditions, whether it's weather or natural gas prices, but data centers are coming online, so the demand will go up and depending on what percentage coal gets versus gas will depend somewhat on gas prices, but also back to my prepared remarks, we do believe that in PJM, that there is excess capacity in the coal plants, they're going to need to be called upon to meet the demand that's being discussed by all of our customers in PJM. If you listen to all their earnings calls, they talk about the pipeline that they have at data centers coming online. They're all projecting increases 3% at least on a year-over-year basis of engine -- electric generation on an annual basis for the next 3 years or so.

You referenced Defense Production -- you referenced the Defense Production Act Title III funding and my understanding, that $425 million of the $500 million would fund the 12 coal plant modernization projects across Kentucky, North Carolina, Tennessee, Oklahoma, Wisconsin and West Virginia. I mean, doesn't that kind of fall into your wheelhouse? I mean, are a lot of those coal-fired plants customers are yours?

6 of those 13 are our customers, and they're all looking to be operating to well into the next decade.

Right. Now I think, Matt, you kind of touched on this, but how should investors kind of think about the balance between a debt reduction, additional royalty acquisitions, unit distributions and maybe even potential unit repurchases over the next 12 to 24 months?

Well, I think, as I mentioned, again, in my remarks, we'll look to maintain growth in the Oil & Gas Royalties segment. I think on the coal side, we're going to continue to maintain our operations by investing the capital we need there. Our matrix will not be capital intensive, but there are some opportunities for growth there that we may deploy some capital, and we intend to want to reward our shareholders, unitholders with a very attractive after-tax return. So we will see what develops. I think with the LNG terminals come online, there is opportunity for natural gas prices to rise. So we're feeling it both for what we're doing on the oil and gas mineral side as well as how we're positioned in the coal industry. So we feel really good about our future.

Our next question comes from the line of Michael Mathison with Sidoti.

Congratulations on the quarter. A couple of questions about the balance sheet. It looks like inventories are down quite a bit from March and December. What drove that? And would you expect inventories to stay at this new lower level?

What primarily drove it was Hamilton in the second quarter. Again, they were not operating at -- we had that planned longwall move really for the first half, so when you look at the inventory we had built going into the year in large part that was to satisfy the Hamilton contracts we had. And we have had good shipments. We had over 3 million tons last month. We have 3 million tons this month. As Cary mentioned, we've got strong contractual commitments, should continue at that pace. So we're essentially producing, or we've got contracts already covered at what our production level is, and we do believe that there will be opportunities to maintain these inventories at this level for the rest of the year.

I think realistically, I mean this is anywhere from 0.5 million tons to 0.75 million tons is kind of a normal run rate, Michael. So we are kind of right in that level right now. Obviously, we'd like them to be as low as possible. But generally, that's where we we will target and end up kind of in that range.

It's reasonable to be at 1 million. So we don't like to be above 1 million. So the -- by being under that, back to the range Cary just mentioned, we're doing a great job this year at managing our inventories.

Okay. Excellent. Also on the balance sheet, it looked like trade receivables are up quite a bit. Is that just seasonality? Or were there other factors at play?

I wouldn't say there's other factors. Well, I mean, the factors at play get to be how much you ship during that month. And so as Joe said, we had a really strong shipping month in June. And so that plays into what the receivables look like at a quarter end at a particular point in time. And so that was the biggest piece of why the trade receivables were higher.

Okay. Turning back to the income statement. What drove income in equity method investments so much higher in the quarter?

So our equity method investments, the benefit, Joe mentioned the Gavin, our investment in the Gavin power plant. And that was one of the primary drivers. They had a really strong quarter. And so our investment in that Gavin power plant continues to be very positive. So that was one particular piece of it as well as our investment in the NGP fund. Both of those had really strong quarters. And so that's primarily what's driving -- what's going on within -- in that number for the quarter. It's hard to say whether something like that is realistic each and every quarter going forward. It would obviously be great if it was. I think, in the past, we've guided that particular area to around [ 3 million ] benefit per quarter. I think that's probably a reasonable one. It will look a little different going forward, too, because we did make this AllDale III & IV acquisition, and there were some benefits from our previous investment in AllDale III that was flowing through that line item that will now go into another area.

But I do think that, that number around [ 3 million ] a quarter is a reasonable one as we look for the balance of this year.

This concludes our question-and-answer session. I would like to turn the floor back over to Mr. Marshall for closing comments.

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 expect to report third quarter 2026 financial and operating results in late October, and we look forward to speaking with you then.

This concludes our call for the day. Thank you.

Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines, and have a wonderful day.

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.

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?

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?

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

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?

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.

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.

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.

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.

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.

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

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?

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.

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?

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.

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

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?

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.

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.

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.

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?

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...

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.

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.

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?

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

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?

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.

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?

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.

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?

Yes. Our expectation is no additional outside coal purchases.

That tied directly to our Mettiki operation.

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?

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.

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

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

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?

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.

Well, thank you. I'm very proud to be a shareholder. I like the way you run the business.

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

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.

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.

Greetings. Welcome to the Alliance Resource Partners Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions]. Please note, this conference is being recorded.

At this time, I'd like to turn the conference over to Cary Marshall, Senior Vice President and Chief Financial Officer. Thank you, Cary. You may now begin.

Thank you, operator. Good morning, and welcome, everyone. Earlier today, Alliance Resource Partners released its fourth quarter 2025 financial and operating results. And we will now discuss those results as well as our perspective on current market conditions and outlook for 2026. Following our prepared remarks, we will open the call to answer your questions.

Before beginning, A reminder that some of our remarks today may include forward-looking statements subject to a variety of risks, uncertainties and assumptions contained in our filings from time to time with the Securities and Exchange Commission, and are also reflected in this morning's press release. While these forward-looking statements are based on information currently available to us, if one or more of these risks or uncertainties materialize, for 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 statements, 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 the required preliminaries out of the way, I will begin with a review of our fourth quarter 2025 results, discuss our 2026 guidance then turn the call over to Joe Craft, our Chairman, President and Chief Executive Officer, for his comments.

For the fourth quarter of 2025, which we refer to as the 2025 quarter, adjusted EBITDA was $191.1 million, up 54.1% from the fourth quarter of 2024, which we refer to as the 2024 quarter, and up 2.8% compared to the third quarter of 2025, which we refer to as the sequential quarter. Our net income attributable to ARLP in the 2025 quarter was $82.7 million or $0.64 per unit as compared to $16.3 million or $0.12 per unit in the 2024 -- quarter. This was the result of lower operating expenses, lower impairment charges and higher investment income, including $20 million in investment income in the 2025 quarter of which $17.5 million was related to our share of an increase in the fair value of a coal-fired power plant indirectly owned and operated by an equity method investee. This helped offset a $15.4 million decrease in the fair value of our digital assets.

Total revenues were $535.5 million in the 2025 quarter compared to $590.1 million in the 2024 quarter. This year-over-year decline was driven primarily by lower coal sales and transportation revenues, partially offset by record oil and gas royalty volumes.

Compared to the sequential quarter, total revenue decreased 6.3% due to lower coal sales volumes and prices. Average coal sales price per ton for the 2025 quarter was $57.57, a 4% decrease versus the 2024 quarter and a 2.1% decrease sequentially. As noted during prior calls, higher-priced legacy coal contracts entered into during the 2022 energy crisis continue to roll off and are being replaced at coal pricing levels assumed in our 2026 guidance ranges. Total coal production in the 2025 quarter was 8.2 million tons compared to 6.9 million tons in the 2024 quarter. Whole sales volumes were 8.1 million tons down from 8.4 million and 8.7 million tons compared to the 2024 and sequential quarters. Segment adjusted EBITDA expense per ton sold for our coal operations was $40.24 per ton in the 2025 quarter, a decrease of $16.3 million and 1.8% versus the 2024 and sequential quarters.

In the Illinois Basin, coal sales volumes were 6.5 million tons in the 2025 quarter down approximately 2% compared to both the 2024 and sequential quarters, primarily due to timing of committed deliveries. I would like to highlight the outstanding performance at our Hamilton Mining Complex where we achieved record production volumes and saleable yield during the 2025 full year.

Segment adjusted EBITDA expense per ton in the Illinois Basin decreased 14.4% compared to the 2024 quarter due primarily to increased production at Hamilton, resulting from fewer longwall move days and improved recoveries. Compared to the sequential quarter, Illinois Basin expense per ton decreased 3.8%.

In our Appalachia region, coal sales volumes were 1.7 million tons in the 2025 quarter, down from 1.8 million and 2.1 million tons in the 2024 and sequential quarters, respectively. This decrease was caused primarily by timing of committed sales at our Mettiki mine and Tunnel Ridge volumes that were impacted by December longwall jump necessitated by a block of support gold needed to be left beneath for gas pipelines.

Segment adjusted EBITDA expense per ton decreased 17.5% versus the 2024 quarter due primarily to increased production at our MC Mining and Mettiki operations and higher recoveries at Tunnel Ridge. Compared to the sequential quarter, segment adjusted EBITDA expense increased 9.7% and primarily due to lower production and recoveries across the region.

As I mentioned earlier, at Mettiki, a series of outages at a key customer's plant negatively impacted our shipments in the 2025 quarter. We have recently been informed that the plan expects additional outages during 2026, and they are not in a position to commit to purchase any additional tons from Mettiki for the foreseeable feature. Mettiki depends on this customer purchasing a minimum of 1 million tons per year and with no clear alternative customer to absorb production issuing Warren Act notices became unavoidable. Mettiki expects to fulfill its existing contractual commitments, which are scheduled to conclude in March 2026, primarily from existing inventory.

For the 2025 full year, segment adjusted EBITDA less capital expenditures at Mettiki was approximately $3.5 million. The anticipated impact of reduced sales volumes at Mettiki is reflected in our 2026 guidance. And additionally, the partnership will evaluate any potential impairment related to this decision during the first quarter of 2026.

ARLP ended the 2025 quarter with 1.1 million tons of coal inventory representing an increase of 0.4 million and 0.1 million tons compared to the 2024 quarter and sequential quarter, respectively.

In the 2025 quarter, Hamilton continued to produce record levels, accelerating completion of District 3, which we felt was necessary due to deterioration in the active leader entries. This will result in an extended longwall move that started last week while the first longwall panel in District 4 awaits completion scheduled for the first week of May 2026.

In our royalty segment, we delivered strong results during the 2025 quarter. Total revenue was $56.8 million, up 17.2% year-over-year due to higher coal royalty tons, higher revenue per ton sold and record oil and gas BOE volumes, which helped offset lower benchmark oil prices.

For the full year 2025, our Oil & Gas royalty segment achieved another record year of volumes on a BOE basis. In the 2025 quarter, BOE volumes increased 20.2% year-over-year and 10% sequentially, resulting in segment adjusted EBITDA of $30 million. As discussed last quarter, a high royalty interest, multi-well development pad in the Permian Delaware Basin was awaiting completion. Those wells were brought online during the 2025 quarter, and we are now benefiting from flush production from those recent completions. Additionally, acquisition activity picked up in the 2025 quarter and we completed $14.4 million of oil and gas minerals acquisitions.

Segment adjusted EBITDA for our Coal Royalty segment increased to $14.6 million in the 2025 quarter compared to $10.5 million in the 2024 quarter due to higher royalty tons sold, primarily from Tunnel Ridge.

Turning now to our strong balance sheet as well as our cash flows as of December 31, 2025, and our total net leverage ratios improved to 0.66 and 0.56x debt to trailing 12 months adjusted EBITDA. Total liquidity was $518.5 million, which included $71.2 million of cash and cash equivalents on hand. Additionally, we held 592 Bitcoins valued at $51.8 million at year-end.

For the 2025 quarter, after $44.8 million in capital expenditures, Alliance generated free cash flow of $93.8 million. We reported distributable cash flow of $100.1 million. And based on our $0.60 per unit quarterly cash distribution, this represented us paying out 77.7% of distributable cash flow and resulting in a distribution coverage ratio of 1.29x.

Looking now to our initial 2026 guidance detailed in this morning's release. There are a few notable areas that I would like to highlight. We anticipate ARLP's overall coal sales volumes for 2026 to increase and be in the range of 33.75 million to 35.25 million tons. This guidance assumes the impact of reduced coal sales volumes at our Mettiki mine and still represents an increase in sales volumes of 0.75 million to 2.25 million tons across the Illinois Basin and at Tunnel Ridge versus 2025.

Demand fundamentals continue to strengthen, supported by higher natural gas prices and low growth from data centers. and U.S. manufacturing, driving increased demand for our coal supply. Contracting activity has been robust with over 93% of expected volumes in 2026, already committed and priced at the midpoint of our guidance. This is materially better than where we were 12 months ago.

In total, we anticipate 2026 full year average realized coal pricing to be approximately 3% to 6% below fourth quarter 2025 levels. In the Illinois Basin, we anticipate 2026 sales pricing to be in the range of $50 to $52 per ton as compared to $52.09 in 2025 and $66 to $71 per ton for 2026 in Appalachia as compared to $81.99 per ton in 2025 which included a larger mix of higher-priced met TP tons.

On the cost side, we expect full year segment adjusted EBITDA expense per ton to be in a range of $33 to $35 per ton in the Illinois Basin as compared to $34.71 per ton in 2025 and $49 to $53 per ton in Appalachia for 2026 and as compared to $63.82 in 2025, which included a larger mix of higher cost Mettiki tons.

On a quarterly basis for 2026, it is reasonable to assume first quarter 2026 segment adjusted EBITDA expense per ton to be 6% to 10% higher than the 2025 quarter as a result of the extended longwall outage in the Illinois Basin at our Hamilton mine. Across our mining portfolio, particularly at River View and Tunnel Ridge, we expect an improvement in segment adjusted EBITDA expense per ton in 2026 and the same for Hamilton in the back half of 2026 and supporting our efforts to preserve operating margins with continued cost discipline and operational execution.

In our Oil & Gas royalty segment, we expect volumes of 1.5 million to 1.6 million barrels of oil to 6.7 million Mcf of natural gas and 825,000 to 875,000 barrels of natural gas liquids. Segment adjusted EBITDA expense is expected to be approximately 14% of oil and gas royalty revenues. We remain committed to investing in our oil and gas royalties business, and we'll continue to pursue disciplined growth in this segment in 2026.

Additionally, at the midpoint of our 2026 guidance, coal royalty tons sold are expected to be 6 million tons higher or 25% above 2025 levels, reflecting higher volumes at our Hamilton and Tunnel Ridge mines. And finally, we're expecting 2026 capital expenditures to be $280 million to $300 million. And for distribution coverage purposes, estimated maintenance capital per ton produced has been updated and is assumed to be $7.23 per ton produced in 2026 versus $7.28 per ton produced in 2025.

And with that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe?

Thank you, Cary. Good morning, everyone. Thank you for joining the call today. Alliance delivered solid performance during the fourth quarter and full year 2025, highlighted by resilient coal generation across our core markets, consistent operating performance from our Illinois Basin mines and tightening fundamentals throughout U.S. power markets.

As Cary mentioned, we closed out the year with strong contracting activity, as we move into 2026, we have committed in price more than 93% of our projected 2026 sales tons as reflected at the midpoint of our guidance range.

Utilities are increasingly often for longer-term agreements to lock in volume with reliable suppliers like Alliance as we enter a period of favorable supply-demand dynamics. Customers are prioritizing reliability, and we believe this reflects a growing recognition that future supply will not be as flexible or abundant as in past cycles.

Before turning to the broader market, I do want to briefly discuss a few areas as I reflect on 2025. First, the Illinois Basin delivered a stellar quarter and year. supported by robust customer demand and continued execution of our plan to enhance mine productivity and cost performance, solidifying our positioning as the premier mining operator in the basin.

Hamilton set a new record for full year clean tons in 2025. Segment adjusted EBITDA expense per ton in the region improved 14.4% quarter-over-quarter and 8.2% year-over-year driven by meaningful cost reductions at both Hamilton and Warrior. In Appalachia, we endured a number of challenges in 2025, including recent events that led to last week's difficult decision to issue a warn notice at Mettiki. At the same time, the strategic importance of Tunnel Ridge in the region continues to grow, and I am confident in our team's ability to improve execution and drive continued improvement in 2026. While Tunnel Ridge represented approximately 73% of Appalachia sales tons in 2025, it generated over 98% of the region's cash flow in 2025 and underscoring its materiality and long-term value.

Finally, in our oil and gas royalty segment, as Cary mentioned earlier, we acquired $14.4 million of additional mineral interest during the fourth quarter of 2025, while lowering oil pricing, while lower oil pricing as sideline many sellers and reduce the number of marketed acquisition opportunities, we remain committed to disciplined investment. Our focus is on proactively sourcing off-market bilateral opportunities and strengthening our targeted ground game efforts to expand our pipeline of attractive acquisition opportunities. Shifting to the macro.

As we entered 2026, natural gas prices had softened in early January from the fourth quarter due to milder-than-normal weather. However, that softness proved short-lived. By mid-January, nationwide Arctic Blast delivered some of the coldest temperatures in years across the Midwest, Mid-Atlantic and Northeast followed immediately by a winter storm firm. These events pushed electricity demand to record winter levels as natural gas deliverability tighten and renewable output remained limited during the hours when generation was needed most.

Wood Mackenzie reported that natural gas freeze-offs reached a single-day record high of 17 billion cubic feet on January 25, and regional hub pricing reached $100 per natural gas for proving once again that reliability goes hand-in-hand with affordability. By the way, our initial guidance, we have referenced today did not factor in this arctic blast which whether experts are expecting will continue into mid-February, if not longer.

During the most stress periods over the past couple of weeks, coal-fired generation once again served as the backbone of reliability. A January 25 article in the Wall Street Journal highlighted the coal supply 40% of MISO's generation and 24% of PJM's generation during the winter event playing a critical stabilizing role across the Midwest and Mid-Atlantic. These developments mirrored exactly what NERC highlighted in its 2025, 2026 winter reliability assessment at resources appear adequate under normal conditions can quickly become and sufficient during widespread extreme cold, especially when fuel deliverability constraints urge.

Load growth remains one of the most significant long-term forces shaping U.S. power markets across PJM, MISO and CIRT Operators continue to project the strongest multiyear demand growth in decades, driven by the rapidly expanding data center and AI computing loads and industrial development. These fundamentals are showing up most clearly in PJM's auction capacity markets.

In December 25, the base residual auction for 2027, 2028 delivered years clear that the FERC approved CAP across all areas. The PJM still fell approximately 6.5 gigawatts short of its reliability targets as the temporary price caps limited how much capacity the market could attract. This follows 2 consecutive auctions with similarly elevated outcomes, underscoring that PJM's accredited capacity challenge is structural.

Since then, FERC has begun evaluating reforms intended to curb volatility, better balance affordability and reliability and support the construction of new generation. Though the ultimate direction and time line of these reforms remain uncertain.

These market developments reinforce what we have consistently communicated. Full secure dispatchable generation remains indispensable and coal's value to our nation's grid is increasingly being recognized by customers, energy markets and regulators. From a policy and planning perspective, these conditions underscore why a balanced resource mix that includes coal remains essential as the grid navigates rapid change to ensure the United States can win the global AI race.

I want to acknowledge the Trump administration's foresight and supporting policies to preserve coal units and recognize their contribution to grid reliability. From the first day, President Trump was sworn into office 1 year ago, he understood the importance of preserving all existing base load generating units in order to protect our national security interest. Every day since the energy dominance council has worked tirelessly on this objective with particular focus on affordability, reliability and preserving the existing coal fleet as well as providing a regulatory framework that allows the operating lives of these plants to be extended.

Fortunately, their leadership is making a difference. According to Americas Power, utilities in 19 states have reversed or delayed more than 31,000 megawatts of coal retirements based on low growth or reliability concerns, reinforcing that policies become increasingly aligned with real-world grid reliability needs.

As we look to 2026 and beyond, we remain committed to a disciplined capital allocation framework by investing in high-return opportunities across our core operations and royalty platforms, returning capital to unitholders, all while maintaining a strong balance sheet. We believe this balanced approach positions Alliance to capitalize on strategic growth opportunities, while maintaining financial flexibility in a rapidly evolving energy landscape. I want to thank our employees for their outstanding performance throughout the year. We look forward to building on this momentum.

That concludes our prepared comments, and I'll now ask the operator to open the call for questions. Operator?

[Operator Instructions]. And the first question is from the line of Nathan Martin with Benchmark Company.

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

Yes. I think that most of our tons that are remaining to be sold are in the Illinois Basin. We do have a little bit at MC Mining where we got about 200,000 tons to sell, but most is in the Illinois Basin, primarily Gibson South and Hamilton. We do believe that we're well positioned. I think that oe thing that we have to factor in is that some of the tons that we have committed in those basins include optionality for our customers.

So even though the price has increased this quarter because of the Arctic are that we've seen and now the natural gas price is rising like they have. there should be some upside that allows for the Illinois Basin pricing to potentially end up towards the end. At the high end of the range, if not exceeded a little bit, but that really depends on how our customers flex up contracts that we have just basically assumed in our contracted position that those are at their base levels and doesn't factor in their optionality.

And I don't know exactly precisely have that trends, but I do believe it's safe to assume that as we look at the markets right now that we would be at the high end of the range on the Illinois Basin. In Appalachia, we just don't have that many times to sell Tunnel Ridge is basically sold out and see, like I said, it's 200,000. And we have seen an uptick in the export markets, which is positive for EMC, but that hasn't materialized yet. We did book some tons just recently, but we're anticipating that price may go a little higher. So we feel pretty good there but we just don't have it many times there to really influence what that price is going to be for -- yes, for our price ranges for Appalachia. So I'd say they will probably come in at the midpoint level.

That was very helpful. I appreciate that. Maybe a little bit bigger picture, coal -- thermal coal demand specifically continue to be supported, utilities look more and more to contract for longer duration, as you mentioned in your prepared remarks. What would it take for Alliance to increase production I guess where you guys kind of capped today? And what could you increase it with approximately how much investments?

I think right now, we do not plan to add any units. So the one area where we could add units is at River View, we could add a unit there. But we're not anticipating to do that. And I think that if there's any incremental demand that we could potentially just work a little bit more over time on weekends and things of that nature. But I think our primary growth is just be an improved productivity. We're very focused on improving our productivity and specifically in the Illinois Basin. We're encouraged by some of the investments we've made in our equipment. We had the joint development agreement with Infant item, where we're converting some of our shuttle cars to the technology utilizing infinite motor, and that's proving to be very attractive improvement in our productivity, and we're rolling that out with new -- our shuttle car rebuilds. So we do think that there could be an opportunity things continue to progress on the trend line that they are that we could show a little higher production in the Illinois Basin or our continuous miner operations as we focus on productivity improvements. But we're not adding or planning to add any additional capital to increase with units and things of that nature. If a customer wants to come and lockup tons for a longer term, we would consider that. But at this moment, there's no plans to do so.

Okay. Got it. And then maybe one final more modeling question maybe for Cary. Equity method investments benefited from that $17.5 million in income from your previous investment at the -- full fired power plant. Cary, any thoughts on how to model that going forward? Is it just going to be lumpy? And then maybe any updates on other potential investment opportunities like that, that you guys see in the marketplace today?

Yes. Sure, Nate, on that. I think when you look at that equity investment income, I think taking out the part associated with the increase in the fair value of the equity method investment is fair to do. So I think as you look at it on a going-forward basis, we were at $17 million here. I think a lower run rate on that more along the lines of $3 million or so per quarter is probably a fair number to take a look at here from a modeling perspective going forward, Nate.

As far as looking at other opportunities, we are evaluating other opportunities to invest in existing coal-fired generation. So that is our -- on our radar and it would be great if we could find more opportunities to deliver the results at the -- plant is has afforded us. It's been a very good investment.

Our next question is from the line of Matthew K. with Tex Capital.

I wanted to talk ask a little bit about expected sales cadence in 2026. Obviously, Mettiki expect to come offline in March 2026. And I think you mentioned that you'll have some catch-up sales and longwall moves as well. Just at a high level, how should we be thinking about cadence and quarterly sales as we go through this year.

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

And then the last half of the year, we don't have any additional longwall moves. So those longwalls will be running full out at that particular point in time. So back half of the year volumes will be the best volumes on a quarterly basis as we look quarterly throughout the year.

Got it. That's helpful color. And in regards to export sales for 2026, I see there's roughly 1.7 million tons committed. How do you expect export sales to compare to 2025 levels? And what type of netbacks are you currently seeing in that market?

Yes. I think going forward, right now, the only exposure we would have the export market will be the MC Mining tons. I mentioned the 200,000 tons. So there's not much that we're looking at export. We're always, we're primarily focused on our domestic customers, and we do believe with the demand they're going to have that they're going to need all the production that we have that's available. We do have the ability of Gibson to ship into that export market.

But currently, we see the domestic market as having a higher netback. So the only shipments we have are based on what we had contracted that we're really targeting in '26. Those were based on prices that we entered into a year ago. So actual netbacks that we're looking at right now, I can't give you a number because we're not actively looking at that market other than at MC where the netbacks have been around $83, I think, for the small tonnage that we did book this month.

Our next question is from the line of Mark Reichman with NOBLE Capital Markets.

It was interesting this morning the EIA had kind of a report out on the monthly wholesale electricity prices. And just like, for example, in the Mid-Atlantic and the Midwest regions, the total generation increased 3% or 49 billion-kilowatt hours. The natural gas declined well, coal generation increased by 49 billion-kilowatt hours. And so it looks like you saw pretty healthy increases in coal in the Midwest, the Mid-Atlantic Central and even in the Southeast to some extent. And I was just kind of curious, is it still kind of a horse race between the spark spread and the dark spread or have we reached a point where for utilities, the reliability, the deliverability is more important.

Well, during this winter storm, it was definitely the reliability. There were freeze-offs. There were a lot of utilities that were curtailing some of our customers, but the coal plants were running flat out for the numerous reasons that coal does have an advantage in winter storms, we have storage on site and I think that the freeze offs did play a role on that. I think as far as February, as I indicated earlier, with the February pricing. We continue to believe that coal burns are going to be strong in February. We are seeing March gas be very volatile. Gas prices have done $0.50 a day over the last week. So it's hard to predict exactly where that's going to go, but there was significant draw over the last week of natural gas in the regions where we market. So believe that both demand for data centers, the winter that we have, we're in a good position relative to coal on gas demand for 2026, at least through the first half of the year.

And then we'll focus on the next half when we start anticipating what the weather demands in the energy demand or actual demand for electricity is in the second half of the year. But I think we're in very good shape from a coal perspective to see the demand in 2026. And as we mentioned, we do believe that supply is pretty limited. I mean, supply increase is limited. So that should bode well on a supply/demand balance as far as pricing. As we roll into the midyear and start thinking about pricing for '26 going forward.

Yes, I would think so. I may be looking at this wrong, but I was just kind of curious, the guidance on the total sales tons for coal versus the royalty tons sold, I mean, there was a bigger delta between the, say, the 2025 guidance and the 2026 guidance between those 2 segments? What was driving that?

So when we're looking at '26.

I think for '26 for royalty tons you're [ 30 ] to 30.8. I think '25 guidance is 23.5 to 24.50. So that's a pretty big delta, whereas the total sales tons was 32.5 to 33.25 last year, now it's 33.75 and 35.25.

Yes. I think, Mark, I think what the biggest delta is in there in terms of cottons and the increase that you're seeing is the movement over at Tunnel Ridge into the new district is leading to higher coal royalty volumes associated with that new district. So that new district does have -- we do lease those -- Tunnel Ridge does lease those from our coal royalty division there. And then additionally, we've got higher volumes projected coming from our Hamilton operation as well. And so those are the 2 primary differences that are leading to the increase in the guidance range. The largest of which is going to be a tunnel ridge. Really, all of the tunnel ridge volumes now that we will be selling will flow into our coal royalties area.

That was based on an acquisition we did a couple of years ago that reserves and district.

The next question is from the line of Michael Mathison with Sidoti & Company.

Congratulations on all the visibility for coal over the past few weeks. Coming to my questions, you referred briefly to 2026 pricing. With demand increasing the way it's been, are you seeing firmer pricing? And could you put any color behind that?

Of the tons that we contracted this year over this last quarter, I think we did contract 1.5 million tons in 2027. And that tonnage get priced a little bit higher than the high end of our range that we got right at the high end of the range for 2026, it was a little higher than what our fourth quarter sales prices were going in the out years, we have 1 contract that actually is a 5-year contract. So we are seeing increases on a yearly basis for that contract. We had 2 other contracts that were 3 years '26, '27, '28 time frame. So those prices mostly -- they were all in the Illinois Basin and they were priced at the high end of our 2026 range in '27, and then they got a little higher than that in '28 going forward. So that, again, as I mentioned in our guidance, we really didn't reflect what we saw with the arctic weather and the higher gas prices. So if we were to contract today, those prices would be higher, and how long that sustains itself is totally dependent on energy demand and what gas prices do going forward.

Well, and trying to look at longer-term demand factors, inventory of coal held at power plants was significantly down in '25, Big bird off already here in Q1 '26 do you see inventories at this level just kind of making where you were last year almost a trough in pricing and we should look at just higher pricing going forward for the new model?

I think so. I think that, again, the supply is limited. I don't think we're going to see supply growth. We're actually seeing some mines that will deplete over the next 3 years. I don't believe that those companies are going to recap to try to maintain that volume. So I do see supply pretty flat to trending down for the domestic Eastern markets. And I believe the demand is going to go up. We've seen the extra capacity these coal units have available based off the coal burn we've seen in January and as demand goes up for data centers, and those data centers are completed, I expect that our synergy demand for coal for data centers will, in fact, go up. So that should put at a favorable supply/demand perspective that would support higher pricing.

Well, great. That's very helpful. So good luck and coming quarters.

Thank you.

Thank you.

Thank you. At this time, we've reached the end of our question-and-answer session. I'll hand the floor back to Cary Marshall for closing comments.

Thank you, operator. To everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our first quarter 2026 financial and operating results currently expected to occur in April, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you.

Ladies and gentlemen, thank you for your participation. This does conclude today's teleconference. You may disconnect your lines at this time, and have a wonderful day.

Greetings. Welcome to Alliance Resource Partners Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note this conference is being recorded. At this time, I'll turn the conference over to Cary Marshall, Senior Vice President and Chief Financial Officer. Thank you. You may now begin.

Thank you, operator, and welcome, everyone. Earlier this morning, Alliance Resource Partners released its third 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 the remainder of 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 ARLP'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 third 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 third quarter of 2025, which we refer to as the 2025 quarter, Total revenues were $571.4 million compared to $613.6 million in the third 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 second quarter of 2025, which we refer to as the sequential quarter, total revenues increased by 4.4% due to higher coal sales volumes and prices. Our average coal sales price per ton for the 2025 quarter was $58.78, a decrease of 7.5% versus the 2024 quarter but an increase of 1.5% on a sequential basis. The year-over-year decline was primarily due to higher-priced legacy contracts entered into during the energy crisis of 2022, that expired in 2024. As it relates to volumes, total coal production in the 2025 quarter of 8.4 million tons was 8.5% higher compared to the 2024 quarter, while total coal sales volumes increased 3.9% to 8.7 million tons compared to the 2024 quarter.

Compared to the sequential quarter, total coal sales volumes were up 3.8%. Total coal inventory at quarter end was approximately 950,000 tons, down 1.1 million and 0.2 million tons compared to the 2024 quarter and sequential quarter, respectively. In the Illinois Basin, coal sales volumes increased by 10.8% as compared to the 2024 quarter, led by increased volumes from our Hamilton, Warrior and River View mines but were down 0.8% versus the sequential quarter due to timing of delivery for contracted tons.

Coal sales volumes in Appalachia were down 13.3% compared to the 2024 quarter due to lower production year-to-date at our Tunnel Ridge mine, but were up 21.8% versus the sequential quarter as we successfully transitioned the longwall at Tunnel Ridge to a new longwall district during the 2025 quarter, which was the primary driver for the increased volumes.

As anticipated, the new district has delivered improved geology and mining conditions compared to the challenges we experienced over the last several quarters. Segment adjusted EBITDA expense per ton sold in Appalachia improved 11.7% compared to the 2024 quarter as all mines in Appalachia achieved lower cost in the 2025 quarter. And sequentially, better results from NC Mining and Tunnel Ridge contributed to a 12.1% improvement in the 2025 quarter.

In the Illinois Basin, segment adjusted expense per ton decreased 6.4% compared to the 2024 quarter, primarily as a result of increased regional production, lower long-haul move days at Hamilton and improved recoveries at our River View and Hamilton mining operations. Expenses in the 2025 quarter included a $4.4 million unfavorable contingent consideration liability adjustment at our Hamilton Mine related to our original acquisition based upon a revised outlook that anticipates increased production in the future at Hamilton. But for this adjustment, segment adjusted EBITDA expense per ton in the 2025 quarter in the Illinois Basin would have been flat with the sequential quarter.

Turning to our royalty segments. Total revenues were $57.4 million in the 2025 quarter, up 11.9% compared to the 2024 quarter. The year-over-year increase in revenues primarily reflects higher coal royalties tons and revenue per ton sold, partially offset by lower average oil and gas price per BOE. Specifically, Coal Royalty sold during the 2025 quarter increased 38.1% compared to the prior year and 28.5% sequentially primarily due to higher Tunnel Ridge volumes, which drove Coal Royalty segment adjusted EBITDA up 54.5% compared to the 2024 quarter and 44.6% higher compared to the sequential quarter.

Oil & Gas Royalty BOE volumes during the 2025 quarter increased 4.1% year-over-year. However, a lower mix of oil volumes and lower realized crude oil pricing resulted in a 10.5% decline in average oil and gas sales price per BOE compared to the 2024 quarter. Our net income attributable to ARLP in the 2025 quarter was $95.1 million. This included a $3.7 million favorable increase in the fair value of our digital assets and $4.5 million in investment income from previous growth investments.

Adjusted EBITDA for the quarter was $185.8 million, up 9% from the 2024 quarter and up 14.8% sequentially. Now turning to our balance sheet and uses of cash. As of September 30, 2025, our total and net leverage ratios were 0.75x and a 0.6x debt to trailing 12 months adjusted EBITDA, respectively. Total liquidity was $541.8 million at quarter end, which included $94.5 million of cash on the balance sheet.

Additionally, we held approximately 568 Bitcoin on our balance sheet, valued at $64.8 million at the end of the 2025 quarter based upon a price of approximately $114,000 per Bitcoin. For the 2025 quarter, Alliance generated free cash flow of $151.4 million after investing $63.8 million in our coal operations. Distributable cash flow for the 2025 quarter was $106.4 million, up 17% sequentially, leading to a calculated distribution coverage ratio of 1.37x based on a quarterly cash distribution of $0.60 per unit or $2.40 per unit on an annualized basis.

Turning to our updated 2025 guidance detailed in this morning's release, favorable weather for most of this past cooling season and rising electricity demand drove increased coal consumption in the Eastern United States, helping further reduce customer inventories. Long-term demand forecast continue to be revised higher across the country as the more favorable regulatory environment continues we are observing a steady stream of domestic customer solicitations for long-term supply contracts.

During the 2025 quarter and subsequent to its end, ARLP has remained active in domestic utility solicitations for 2026 and beyond. Our teams have been successful in securing additional contract commitments as customers continue to value our product quality, reliability of service and financial strength. Our contracted position for 2025 is up slightly to 32.8 million tons committed and priced including 29.8 million tons for the domestic market and 3 million tons for export. We have elected to tighten our full year sales guidance to 32.5 million to 33.25 million tons with the midpoint coming in within 1% of our previous guidance in July. Perhaps more importantly, strong demand for our supply allowed us to add to our 2026 order book once again.

We have now contracted and priced 29.1 million sales tons for 2026, up 9% from last quarter, putting us in a good position for this time of year for prompter shipments. With respect to pricing, we increased the low end of our coal sales pricing guidance ranges for both the Illinois Basin and Appalachian. And on the cost side, we expect full year 2025 segment adjusted EBITDA expense per ton to be in a range of $60 to $62 per ton in Appalachia and $34 to $36 per ton in the Illinois Basin.

In our Oil & Gas Royalties business, we are adjusting our full year 2025 oil volume guidance to account for a timing delay in a high royalty interest, multi-well development pad in the Delaware Basin of the Permian which is now expected to come online in early 2026. As it relates to all our other guidance ranges, they are largely unchanged from our previous expectations.

And with that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe?

Thank you, Cary, and good morning, everyone. Our operations delivered another solid quarter of performance. Our Illinois Basin operations are performing well, led by Hamilton, which benefited from new automated longwall shields commencing operation immediately after a successful longwall move in early August.

Looking forward, the combination of Shield and share automation is expected to enhance productivity, reduce the number of personnel required on the face and minimize maintenance demands. In our River View complex, the Henderson County mine achieved a key infrastructure milestone in late August with the opening of its new portal facility, equipment and personnel transitions to better mining conditions are planned to be in place early next year when 6 units are scheduled to be operating at the Henderson County mine and 3 units are scheduled to remain operating at the River View mine.

[ Appalachia ] operations improvements were led by Tunnel Ridge, which successfully transitioned to a new longwall district in the 2025 quarter. As expected, the move was resulted -- has resulted in significantly improved mining conditions, dropping the mine's cost per ton sold by 8.8% compared to the 2024 quarter and 19.3% to the sequential quarter. With both regions performing well, our total cost expectations for 2025 are on track to fall within the updated guidance range.

Looking at the coal market. U.S. coal demand is continuing to experience strong fundamentals, supported by a combination of favorable federal energy and environmental policy to preserve America's coal fleet plus rapid electricity demand growth. Compared to last year, year-to-date utility coal consumption has increased by 15% in MISO and 16% in PJM. This surge reflects not only favorable natural gas pricing, but more importantly, a realization of the dramatic load growth required by artificial intelligence and data centers.

Natural gas fundamentals remain supportive of coal dispatch economics. Henry Hub has averaged over $3.50 per million BTU in 2025. And the current forward strip is averaging higher pricing in 2026 and 2027. Rising electricity demand, combined with the expected growth of LNG export capacity should keep upward pressure on natural gas prices, further enhancing Kohl's competitiveness in power generation dispatch.

Furthermore, utility coal stockpiles have normalized at healthy levels supporting more robust term contracting activity. With normalized utility inventories and unprecedented demand growth from data centers, analysts we follow are projecting 4% to 6% annual growth in electricity demand in PJM and other markets we serve over the next several years.

As a result, we believe Alliance is well positioned to increase production at Tunnel Ridge and in the Illinois Basin in 2026 to meet this demand. Market signals are validating the need to keep baseload power plants online, to meet this anticipated electricity demand, including coal-fired power plants previously planned for decommissioning. The recent PJM capacity auction cleared at maximum allowable prices with every megawatt of coal capacity selected, while reserve margins fell below reliability targets, clearly demonstrating that the grid needs every available megawatt of dispatchable generation.

During the quarter, as I mentioned in our last earnings call, to assist in extending the lives of coal plants in our marketing footprint, we invested $22.1 million as part of a $25 million commitment and a limited partnership that indirectly acquired a coal-fired plant in the PJM service area, positioning Alliance to directly benefit from the tightening power markets and growing demand for reliable baseload generation. We expect this investment to generate attractive cash-on-cash returns during 2026 and beyond.

In conclusion, our priorities remained unchanged, maintaining a strong balance sheet, investing prudently in our core operations. and positioning Alliance for long-term growth while delivering attractive after-tax returns to our unitholders. With the completion of several major capital projects at our mines, sustaining capital needs in our coal segment are expected to decline meaningfully, which enhances free cash flow visibility for 2026 and beyond.

In our Oil & Gas Royalties business, we continue to pursue disciplined, accretive growth opportunities. Although lower commodity pricing has limited investment opportunities in 2025, the segment remains unlevered, and we strive to reinvest internally generated cash flow to expand our minerals position where we see attractive economics and high-quality operator activity.

Returning capital to our unitholders remains a key component of our strategy. During the 2025 quarter, we declared a quarterly distribution of $0.60 per unit, equating to an annualized rate of $2.40 per unit and unchanged from the sequential quarter. As Cary said, distributable cash flow for the 2025 quarter was $106 million, $106.4 million, up 17% sequentially, leading to a calculated distribution coverage ratio of 1.37x for the 2025 quarter.

We expect the operating and financial results for the fourth quarter to equal our outstanding 2025 quarter results. At Alliance, we remain laser-focused on delivering what America needs most, reliable, affordable baseload generation. With supportive policy, improving market fundamentals and disciplined execution. We believe we are well positioned for the balance of 2025 and beyond.

That concludes our prepared comments, and I'll now ask the operator to open the call for questions. Operator?

[Operator Instructions] And our first question is coming from the line of Nathan Martin with Benchmark.

You guys talked about how domestic customer engagement has intensified as utilities seek reliable supply, and that's kind of giving you greater demand visibility than you've experienced in several years. Could you guys give us a little more color on how long some of these supply contracts are being signed for now? And maybe what kind of structure is typical on the price side, whether that's fixed or if it's tied to a variable index, for example.

Yes. So most of the customers are coming out for 2 to 3 years, I would say. And of those, they prefer fixed pricing. So we are looking at fixed pricing. We do have some understanding that there would be some reconsideration in the event that tariffs impact costs that aren't -- they are not anticipated or expected. So there is some tariff concept and the protection in those contracts, but primarily, they are fixed price for the 2- to 3-year time period. Some are going a little shorter than that, just like a 1 year or even some are still staying in the spot market.

But typically, within those contract structures, there is escalation years 2 and year 3 in terms of the pricing, generally speaking.

Okay. That's helpful, guys. And then what index should we be paying attention to? Is it still the Illinois Basin index and Northern App cap type indices?

Yes. But at the same time, I don't think the index based on the volume is being tracked precisely. So I think that you need to factor in each customer is a little different. But I mean I think those indexes are generally accurate, but we are seeing some pricing that's little bit higher than what those index have been showing, depending on what time you're looking at.

You're starting to see the index go up over the last quarter, say -- and I think that's reflective of where the -- where some of these contracts are trending into.

Got it. And that's actually where I was going to go with my next question. Your pricing guidance also for full year '25, I guess a little bit higher now at the midpoint. As you look to '26, I believe you said last quarter that the expectation was for price per ton could decline around 5% year-over-year. And now that you've added some additional tonnage for '26. Do you still feel like that down 5% is the right way to think about pricing for next year?

Yes. I think we still have -- like we've mentioned, some of our contracts rolled off in 2024. We have some contracts in Appalachia that are rolling off in 2025. So that's the main reason for the suggestion that our overall pricing is likely to be down year-over-year because of the Appalachia contracts that are rolling off in 2025, they're having to be replaced the '26 pricing.

However, because of the movement of Tunnel Ridge into their favorable geology, we are expecting to pick up volume there back to levels that were more that we were experiencing previous to the bad geology we've experienced over the past several quarters. So we do believe that the cost improvements that we see at Tunnel Ridge would allow our margins to be maintained for '26 compared to '25.

Yes. That's right, Nathan. And depending upon what our volume guidance is for next year, that could impact these numbers a little bit as well. typically, we provide that -- we'll do that at our January meeting. So we'll provide some volume guidance as well as updated pricing guidance based upon our experience from entering into solicitations for this year and what that looks like in terms of better guidance on volume when we come back and talk to you in February.

All right. Perfect. Appreciate that. And then just maybe one final bigger picture question. A couple of weeks back, Administration, Department of Energy announced some additional investments in the coal-fired power [indiscernible] space. Maybe, Joe, could you please talk about how you see that impacting your business and your customers? I know the late retirements have been talked about a lot recently, but it would be great to get your thoughts.

We are seeing a very active engagement, both by utilities and the Department of Energy on dispatching those resources. I think the number was around $625 million. Those bids are due in imminently and there was a call recently among the various customers that we're interested in taking advantage of that, and it was very robust. I believe that, that the request for support will be greater than that number.

So we are seeing several significantly more than several, I guess. Utilities are interested in taking advantage of that opportunity. There has been indication depending upon demand and the attractiveness of the opportunities that are presented that could open the door for more bonds being available to assist these utilities and investing in their coal plants to make sure that they do dispatch and run beyond basically run for their original determine life, what their anticipated life would be. We know several customers that are looking at investments that we sell to, that it would benefit them by actually increasing the demand that they would have in the out years if they can get these grants and/or loans from the government.

Our next question is from the line of Mark La Reichman with NOBLE Capital Markets.

So just was curious about the equity method investment income. So it was 2 losses for the first and the second quarter and then $4.5 million in the third quarter. And I was just kind of wondering, even though it doesn't really lag the dog here. Have those investments kind of turned the corner? I mean, can we kind of expect positive numbers in the fourth quarter? I was just kind of curious for your thoughts on how those investments are playing out?

Yes, Mark, I think as it relates to that, I mean, I think you're right. I think from where we are right now, I think we can anticipate modestly positive numbers in the fourth quarter here going forward. We did have some of our equity investments that we did make. We have started receiving some decent distributions in relationship to our investments that we've made in those, which has led to some higher valuations for some of those investments, which you're seeing that reflected in this quarter's number there.

So this quarter is probably a little bit higher than what typically would be on a normal going-forward basis. I mean, we'll see, depending upon how say the GABA investment may perform for us because we are anticipating cash-on-cash returns from there as well. So -- but I think what you say is modestly positive in the fourth quarter and going forward, I think that's a fair position with where we are today.

And then on the multi-well pad in the Delaware Basin of the Permian, which is now expected to come online in early 2026. Would you say that that's really the event that's most responsible for the change in guidance with respect to the oil and gas royalty volumes? And how early in 2026, do you think it would come online?

Yes. I think that is responsible for the changes that we've made in our guidance ranges there. There's no question that will come online. It's just a matter of timing. Right now, our best guess on that is first quarter of 2026.

And then with respect to the coal business, pricing came in ahead of our estimates and the segment adjusted EBITDA expense per ton came in lower than what we were looking for.

So that's all very positive. So you had the longwall move in July, which which positively impacted Appalachia. And I believe you had the Henderson in the third quarter. So Illinois Basin, if I just kind of look at the expenses, 35, 37 to 10. So that's kind of in line with your guidance. Appalachia you're actually -- you were at 58 to 62 last quarter. And so now you're at 60 to 62 and you were at 57, 74 for this quarter. So would you frame that? Would you say that maybe you maybe expected more improvement in the expense per ton in the third quarter? Or would you say that like fourth quarter going forward, it seems to me that that the expenses could actually be kind of at the lower end of your guidance kind of from this point forward. So just kind of your thoughts on the -- most particularly to Appalachia.

And I think that the guidance reflects that the fourth quarter for Medici, we are anticipating costs to go up in the fourth quarter at Mettiki compared to the third quarter. So that's influenced -- on a going forward basis, we don't think that's systemic. It's just a certain circumstance where our geology is right now for Mettiki. So going forward, '26 forward, we do believe we're going to be back on a path of having lower cost in Appalachia.

The next question is from the line of Matthew Key with Texas Capital.

I wanted to talk about just initial expectations for volume in 2026, given that you guys have made strong progress on the contracting front. What's your view of the best case scenario for shipments in '26 versus '25? I know you can get potentially $1 million more out of Tunnel Ridge. So I just wonder if you could just walk me through what other opportunities are out there for increasing volumes as we head into next year.

I think that we do believe that Illinois Basin will also be able to yield some increase. It's yet to be determined exactly what that is. We've had some early indications based off of the contracting that we've been discussing that because of the timing of data centers that are coming online and the just a strong growth continuing in 2026 that there will be opportunities to be able to grow our total overall in a 2 million-ton range and how much of that is going to be Illinois Basin versus half.

It could be a little higher in app versus Illinois Basin, but it's yet to be determined, but if we were to try to make a guess today, what our sales would be in '26 versus '25, it would be about 2 million tons.

Got it. That's super helpful. I appreciate that color. And I just wanted to touch briefly on M&A outlook in the current market. Any opportunities out there in coal? Or do you view it more likely more focused on the Oil & Gas Royalty business or secondary business?

Yes. I would say it would be more focused on minerals. As we indicated, we're continuing to look at the infrastructure area. So we would like to find more opportunities like Gavin. So we're considering that. There's a couple of other things that we're looking at, small dollars, but that allow Matrix to be able to achieve its goals and the growth opportunities it sees beyond its own organic growth that it's looking at.

So I think those would be the areas that we'd be focused on. But on an M&A standpoint, there's really no real expectation that we would participate right now in expanding our coal operations.

The next question is from the line of Dave Storms with Stonegate.

Just wanted to start. You mentioned on the outlook that you're expecting increased production at Tunnel Ridge in the Illinios Basin. Just would love to get your thoughts around maybe the logistics of increasing that production is that's going to require more staffing or anything of that nature?

No. I think with the capital that we've committed over the last 2, 3 years, we're fully capitalized. I think we would not be bringing on any new units. It would just be taking advantage of the trend lines we've got being able to roll into those investments. So when you -- we've got the staffing there, River View when we transition to 6 units, we're just moving people over. We just have more favorable conditions and the reserves that we're moving to compared to the reserves that we would have been mining had we stayed on the original plan.

So we're able to achieve more with the existing headcount, both at Hamilton and Tunnel Ridge, we anticipate that our development and '26, say, the second half of '26 will be in panels that could, in fact, allow dropping a unit or so development. So from a head count perspective, we don't anticipate hiring or needing to add personnel to achieve that 2 million tons of extra sales that I mentioned a few minutes ago.

Understood. That's very helpful. And then it was also mentioned they anticipate approximately 300,000 to 600,000 million tons of [ met ] to be sold in 2026. That's currently uncommitted. Can you just talk about your confidence that, that will get committed or your comfort with maybe potentially bringing that to the spot market in 2026.

Yes. So on the met side of the business, that typically is price on a quarterly basis or committed on a quarterly basis. So historically, we've really not had committed met tons, and we still down, but we do anticipate that we will be able to place those times and the pricing right now is -- again, the pricing is based off index at the moment in time that they actually commit.

So we do believe that we can sell it. We can't really give you a prediction on what the price is going to be.

Next question is coming from the line of Tim Snider with Schneider Capital.

Thanks for all the color on the power market, super interesting. Question I had at what kind of level of maybe either Henry Hub or intraday pricing for the basins that you guys are kind of active in terms of delivering coal to your power customers are we seeing switching either from coal to gas or gas to coal. And then the other follow-up to that is how quickly does that occur? Is that something that can happen in 24 to 48 hours or so depending on what the front month does? Or is this a more, I guess, more of a paste switching on and off.

I would answer that by saying that we're seeing the actual competition of gas to coal being less of a factor as data centers come online than what it has in the past. I think the major question back to gas and coal on gas competition is just going to get to the winter. You have to have a winter. If you don't have a winter, then your question is more relevant and it would be more gradual as opposed to a day-to-day type decision.

But I think whether dependency for winter is probably the 1 area of where gas prices would be impacted, that could have an influence on what coal demand would be. But assuming a normal winter or a winter like we had last year, we didn't experience in 2025, we haven't experienced true gas on coal competition like we had in the past. And again, I think that's driven by the capacity utilization and with the growth we're seeing.

So we saw, as I mentioned in the prepared remarks, 15% to 16% growth year-over-year in electricity demand, and a lot of that is anticipated to grow again 4% to 5%. So I don't see that as a direct, a major issue in trying to influence what spot price in going to be.

Again, I do believe that the demand on the next 2 to 3 years is is growing, and they're going to need the coal supply. They need every coal plant open to meet the demand for data centers. So yes, gas prices are important, but it's not as significant as it's been in the past.

Got it. So would it be fair to say then basically from your vantage point, it's kind of all of the electrons are needed going forward irrespective of kind of source sort of sensitivity just that was there historically, just isn't there anymore going forward?

Yes. That's fair. It's what I was trying to say.

Next question is from the line of Michael Matheson with Sidoti & Company.

Congratulations on the quarter. A couple of things that I noticed going over your financials. CapEx is lower year-over-year and in line with the sequential quarter. Does that make you see full year CapEx is coming in toward the low point of guidance?

Yes, it's hard to say on that. I think really probably closer to the midpoint of guidance is fair. We do anticipate fourth quarter CapEx to be higher than where we are. But typically, we do end up with some capital that carries over year-to-year. But I think it will be higher than where we were this quarter, whether we get to the top end of the guidance range, likely not there, but somewhere in between.

Great. Looking at depreciation expense, it was higher year-over-year in Q3, and I noted that you looked full year guidance. Were there onetime factors in play for that? Or does this level of depreciation feel like the new normal?

Yes. I think this level is probably the new name for where we're at in terms of depreciation levels. We've had assets that we've placed in service here throughout the year that led for us to kind of narrow that guidance range from where we are before and just kind of the fact that where we are right now, that's a pretty good rate as we look for the balance of this year, which kind of gets you to where our guidance ranges on.

All right. Then looking at some more big picture items. Joe mentioned that you were interested potentially in other transactions like Gavin. Do you see Kevin as sort of the beginning of a trend of a lot of utilities wanting to sell off their coal-fired capacity or does it look like 1 by 1 at a time?

It's more of the latter. I mentioned on the last call maybe 5 to 10 units or plants, and I haven't seen anything that would change that perspective. And I'm focus strictly on East of Mississippi. So there may be some things in the West that I'm not aware of. But as we look at the east of the Mississippi, I can see 5 to 10 units and/or plants that would be interested in transacting and changing ownership as opposed to continuing to own those plants on a going-forward basis.

And just one more question back to coal operations on expense per ton is down sharply in Appalachia. Do you feel like -- and you gave a lot of color around supporting why that would sort of endure you feel like that lower expense level is something we can count on going forward? Or were there onetime factors in play?

We do believe you can count on that going forward. And the primary reason is back to the new district. We're going to in Tunnel Ridge. As we look at our MC mine, it's only 2 units, but that looks to be sustainable. And then as we proceed into '26 were Mettiki, we appear -- that appears to be consistent with what we been seeing.

So as I mentioned a few minutes ago, we do believe that the Mettiki situation is tied to a specific geologic issue in the fourth quarter. But going forward, we do believe Appalachia is going to show very sustainable lower cost than what we've seen over the last several quarters.

This now concludes our question-and-answer session. I'd like to turn the floor back over to Cary Marshall for closing comments.

Thank you, operator. And to everyone on the call today, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our fourth quarter 2025 financial and operating results is currently expected to occur in February, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you.

Thank you. Ladies and gentlemen, thank you for your participation. Today's conference has concluded. You may disconnect your lines at this time, and have a wonderful day.