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Presentation

Alliance Resource Partners, L.P. misses on earnings expectations. Reported EPS is $0.88 EPS, expectations were $1.14. ARLP isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: Greetings. Welcome to Alliance Resource Partners LP Fourth Quarter 2023 Earnings Conference Call. At this time, all participants are in listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions] Please note this conference is being recorded. At this time, it is my pleasure to turn the conference over to Cary. P Marshall, Senior Vice President and Chief Financial Officer. Mr. Marshall, you may now begin.

Cary. P Marshall: Thank you, operator, and welcome everyone. Earlier this morning, Alliance Resource Partners released its fourth quarter and full year 2023 financial and operating results. And we will now discuss those results as well as our perspective on current market conditions and outlook for 2024. 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 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 results for the fourth quarter and full year, give an overview of our 2024 guidance, then turn the call over to Joe Craft, our Chairman, President, and Chief Executive Officer, for his comments.

During 2023, we delivered another record full year in terms of revenues, coal sales price per ton, oil and gas royalty volumes, and net income. We accomplished these records in a challenging year for the global economy, pressured by high interest rates, global geopolitical unrest, and continued volatility in commodity prices. Operationally, we had to contend with reduced volumes across the Appalachia region, primarily caused by lower recoveries, fewer operating units at MC Mining, and challenging geologic conditions that delayed development of the new district at our Mettiki longwall operation. Notwithstanding these obstacles, we achieved our outstanding results through a combination of our well-contracted order book, tight focus on operating efficiencies, and investment for longer-term strategic positioning with our customers.

Full-year revenues were $2.6 billion, an increase from $2.4 billion in 2022. Net income was $630.1 million, up from $586.2 million, and earnings per unit increased nearly 10% from $4.39 in 2022 to $4.81 in 2023. Looking more closely at the fourth quarter comparisons, total revenues were $625.4 million in the 2023 quarter compared to $704.2 million in the 2022 quarter. The year-over-year decline was driven primarily by lower coal prices, lower oil and gas prices, and reduced coal sales volumes in Appalachia, which more than offset record oil and gas royalty volumes and higher transportation and other revenues. Total coal sales price per ton was $60.60 for the 2023 quarter, a decrease of 10.7% versus the 2022 quarter. Softer demand in both domestic and international markets resulting from a mild start to winter and lower natural gas prices negatively impacted coal pricing.

This was partially offset by the positive impacts of our contracted order book. On a sequential basis, coal sales price per ton was 6.7% lower. As it relates to volumes, total coal production of 7.9 million tons was 6.6% lower compared to the 2022 quarter, while coal sales volumes decreased 7.5% to 8.6 million tons compared to the 2022 quarter. Illinois Basin coal sales volumes increased by 2.1% and 6.1% compared to the 2022 and sequential quarters respectively. The increase is the result of higher volumes from our Hamilton and Warrior mines compared to the 2022 quarter and from our Gibson South operation sequentially. Coal sales volumes in Appalachia were down 27.4% and 8.8% respectively compared to the 2022 and sequential quarters. The reduced volumes across the region was primarily caused by lower recoveries, reduced operating units at MC mining, a scheduled longwall move at our Tunnel Ridge mine, and challenging geologic conditions at our Mettiki longwall operation that delayed the development of a new longwall district.

Additionally, 2023 quarter coal inventory and tons sold were negatively impacted by approximately 0.6 million tons due to an unexpected temporary outage at a third-party Gulf Coast export terminal we use for export market sales. In our royalty segments, total revenues were $53 million in the 2023 quarter, down 1.9% year-over-year, but essentially unchanged sequentially. The year-over-year decrease in revenues reflects lower realized oil and gas commodity pricing that more than offset record oil and gas volumes and increases in coal royalty revenue per ton. Specifically, coal royalty revenue per ton was up 24.3% compared to the 2022 quarter, while lower commodity prices led to oil and gas royalties average realized sales prices being down 19.7% per BOE versus the 2022 quarter.

Sequentially, coal royalty revenue per ton was 0.9% lower, and oil and gas royalties average sales prices were up 0.9% per BOE. Oil and gas royalty volumes increased 13.1% on a BOE basis to a new record, while coal royalty tons sold declined 5.4% year-over-year. The record volumes from oil and gas resulted from increased drilling and completion activities on our interests and acquisitions of additional oil and gas mineral interests. Turning to cost, segment adjusted EBITDA expense per ton sold for our coal operations was $42.91, an increase of 7.9% and 4.2% versus the 2022 and sequential quarters respectively. The impacts of lower volumes I just discussed in Appalachia and higher cost purchase coal more than offset improvements in the Illinois Basin.

Specifically, the Illinois Basin saw higher volumes and lower expenses at the Hamilton mine as compared to the 2022 quarter when the facility experienced an unexpected outage that lasted four weeks. Last quarter, we gave additional color to our Appalachia longwall operation at Mettiki. It was idle for the entire third quarter and into the fourth quarter, but returned to production in late December. In 2024, we expect to move the longwall again, skipping over a region of adverse geology, and resume production under much more favorable mining conditions in March. This is expected to benefit overall production volumes and cost in Appalachia in 2024 when compared to the back half of 2023, which is reflected in the guidance I will discuss in a moment.

Our net income in the 2023 quarter was $115.4 million, 46.8% lower as compared to the 2022 quarter. The decrease reflects the previously discussed lower coal sales volumes and realized prices, higher production expenses, and lower realized prices in oil and gas royalties, partially offset by higher coal royalty sales price per ton realizations, and record volumes in oil and gas royalties. EBITDA for the quarter was $185.4 million, down 37.6% as compared to the 2022 quarter. Now turning to our balance sheet and uses of cash. Alliance generated free cash flow for the full year 2023 of $421.6 million. During the 2023 quarter, we completed two acquisitions of mineral interest, totaling $24.8 million for 3,236 net royalty acres in the Permian, Anadarko, and Williston basins.

Additionally, during the 2023 quarter, we paid a quarterly distribution of $0.70 per unit, equating to an annualized rate of $2.80 per unit. This distribution level is unchanged sequentially and is compared to the 2022 quarter. Lastly, we reduced our debt outstanding by $22.9 million, resulting in total and net leverage ratios of 0.37 times and 0.31 times respectively, total debt to trailing 12 months adjusted EBITDA. Total liquidity was $492.1 million at year end, which included $59.8 million of cash on the balance sheet. Turning to our initial guidance detailed in this morning’s release, 2024 is shaping up to be a solid year for ARLP with a well-contracted order book and the opportunity to flex additional export tons should market conditions warrant the move.

As you will notice, we have provided some additional color to our outlook by detailing both estimated realized pricing and cost per ton by region. Our expected realized full year 2024 price is based on a combination of our contracted order book and our expectations for additional contracting, both domestic and export, for the open position. We expect the logistic issues that pressured the second half of 2023, including low river system water levels and an extended outage at the third-party export terminal we utilize in the Gulf of Mexico to no longer impact 2024 results. We anticipate ARLP’s overall coal sales volumes in 2024 to be in a range of 34 million to 35.8 million tons, with over 90% of these volumes committed and priced at attractive levels similar to the 2023 average realized pricing.

Specifically, our committed tonnage for 2024 is 32.5 million tons, including 28.4 million domestically and 4.1 million to the export markets. Coal sales prices in the Illinois Basin are expected to range between $54.50 and $56 per ton compared to $55.21 per ton in 2023 and in Appalachia in the range of $80.50 to $83.50 per ton compared to $86.98 per ton sold in 2023. On the cost side, we expect full year 2024 segment adjusted EBITDA expense per ton in the Illinois basin to be in a range of $35.25 to $37.25 per ton as compared to $34.84 in 2023. And in Appalachia, $54.25 to $57.25 per ton has compared to $53.15 per ton in 2023. During the full year 2024, we have three scheduled longwall moves at Hamilton, three at Tunnel Ridge, and two at Mettiki, with one of the moves at Mettiki and one at Hamilton scheduled in March.

In our oil and gas royalty segment, we expect sales of 1.4 million to 1.5 million barrels of oil, 5.6 million to 6 million Mcf of natural gas, and 675,000 to 725,000 barrels of liquid. Segment adjusted EBITDA expense is expected to be approximately 12% of oil and gas royalties revenues for the year. In 2024, we are anticipating $450 million to $500 million in total capital expenditures. Consistent with messaging in recent quarters, 2023 and 2024 are years of elevated capital expenditures as we make long-term strategic investments in our River View, Warrior, Hamilton, and Tunnel Ridge mines to ensure they remain reliable low-cost operations for many years to come. Starting in 2025, we anticipate our capital expenditures to return to more normalized levels of $6.75 to $7.75 per ton produced.

Additionally, we remain committed to investing in our oil and gas minerals business, the amount of which will be dependent upon the opportunities available that meet our underwriting standards. Next, we remain focused on continuing to improve our balance sheet, maintaining flexibility and strong liquidity. We expect to retire the $285 million outstanding on our senior notes periodically throughout the balance of 2024 using a combination of operating cash flows and a number of attractive financing options currently available to us, including increases to our existing facilities, equipment financing, and utilizing the collateral value of our high quality and unencumbered royalty assets, all of which are at various stages of execution today. Thereafter, we will continue to evaluate the highest return and best use of excess cash flow.

This includes returning capital to our unit holders in the form of cash distributions or unit repurchases and accretive growth opportunities that extend beyond our base business. With that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe?

Joe Craft: Thank you, Cary. Good morning, everyone. I want to begin my comments by thanking and congratulating the entire Alliance organization for their resilience, continued hard work, and dedication for delivering another record year for total revenue, realized pricing per ton sold, oil and gas royalty volumes, and net income. Cary did an excellent job summarizing our 2023 results and outlining our guidance for the upcoming year, as well as explaining the factors that contributed to our success in 2023. As we look to 2024, our coal sales book is expected to be equally as strong as last year and be the anchor to deliver another solid year of revenue. Our dependability and the reliability of our coal quality are highly valued by our customers, evidenced by the premium pricing we have received relative to the spot market on recent commitments with domestic customers for multi-year contracts.

We are entering 2024 with over 90% of our coal sales volumes committed and priced at similar levels relative to 2023. We are expecting our production to be more consistent than 2023, believing we have moved beyond the several negative geologic areas that we faced this past year. As we think about the outlook for the coal industry and the markets we serve, several key themes emerge, underscoring the critical need for reliable, affordable base-load fuel for electric generation. The first relates to increasing market expectations for nationwide energy demand. Over the past year, we should all take notice that grid planners have nearly doubled five-year load growth forecast in support of ongoing investment in US industrial and manufacturing sectors, as well as citing rising energy needs associated with data centers and artificial intelligence.

While the speed of electrifying the transportation sector may have slowed, the enthusiasm for AI has accelerated. The power demand requirements for data centers cannot be understated. Highlighted by recent estimates, the electric demand from operational and announced data centers in the US will reach over 30 gigawatts in the coming years, with some individual sites needing upwards of 600 megawatts of power. These increased revisions are not temporary fluctuations, but represent fundamental changes to energy consumption patterns. Just last week, the governor of Indiana announced Facebook parent Meta will build an $800 million data center on a 600-acre site in Jeffersonville, Indiana, across the river from Louisville, Kentucky. And the governor said that his state aims to be the AI capital of the Midwest, while Kentucky’s Governor for several years has declared Kentucky as the undisputed electric battery production capital of the United States of America.

Both of these messages suggest more to come, more proof to support our belief that low growth in our key markets will be exceptionally strong over this decade. Furthermore, we are observing a renewed emphasis and urgency by regulatory bodies such as [IRC] (ph) and NERC to ensure power grid reliability, a fundamental attribute coal-fired generation provides. In the markets we serve, regulators, elected officials, and leaders focused on economic development are evaluating actions needed to ensure reliable electricity capacity is available to meet this growing electric demand, especially in peak times. Impacts from weather time and time again display the weakness of the grid domestically and unfortunately at times the danger to consumers. Two weeks ago, after what was a relatively mild start to this winter, the US experienced a cold snap in which over three quarters of the country was exposed to below freezing temperatures and hundreds of thousands were without power.

From Texas to the eastern United States, winter demand approached record levels, and the state’s grid operators asked for consumers to curb consumption due to a capacity shortage. It is times like that when wind turbines are often unable to turn and natural gas pipelines can be constrained in their ability to deliver, that the grid is tested and failure can have catastrophic consequences. Having this strategic flexibility of coal on the ground elevates the service and reliability we provide to unmatched levels. It is for reasons similar to these that we believe the US will continue to see delays in extensions in the premature closure of critical coal plants and why we are committed to serve these markets for many years to come. Over the past year, utilities have extended the plant operating life of approximately 10 gigawatts of coal generating capacity as a result of increasing electricity demand and delays in the construction of replacement generation, particularly renewables.

We acknowledge the US grid will evolve with time, but policy decision makers must be responsible and practical in doing so. And currency policy needs to reflect the realities of exploding demand and of the laws of physics that dictate how electricity is generated, transmitted, and delivered. We believe we are well positioned to be part of a long-term solution, supplying reliable, affordable base load energy for consumers and creating long-term value for our unit holders. Now, turning to strategic updates related to our business. In 2024, we expect to complete the major infrastructure projects at Tunnel Ridge, Hamilton, Warrior, and the River View complex. As Cary mentioned, ARLP will start to recognize the benefits from these strategic investments in 2025 as capital expenditures will be significantly lower and our minds will be more productive, ensuring we maintain our position as the most reliable, low-cost producer in the United States and the eastern United States over the next decade.

Turning to our royalty segment, we remain committed to growing our oil and gas royalties business, which delivered record volumes in 2023. Over the past year, we acquired $111 million in additional oil and gas minerals, primarily concentrated in the Permian Basin. This marks our largest investment year since 2019. We love the cash flow potential this segment offers via hedge-free exposure to commodity price and organic growth. As we look to 2024, I would comment that during periods of commodity price volatility, the size and timing of acquisitions can be difficult to predict as our growth strategy relies on strict underwriting standards for investment that we will not compromise in tight markets. We also remain committed to pursuing growth opportunities beyond coal and, oil and gas royalties.

As we advance these initiatives, our investment decisions will be selective, aligned with our core competencies, and focus on areas where we can add significant strategic value. Let me be clear. We are not interested in building a portfolio of passive venture capital style investments. Initial positions should be thought of as potential platforms for future lines of business with long-term growth and cash flow generation. To that end, two weeks ago, we announced that our wholly owned subsidiary, Matrix Design Group, entered into an agreement with Infinitum to develop and distribute high efficiency reliable motors and advanced motor controllers designed specifically for the mining industry. This collaboration represents a natural progression and extension of our initial investment in Infinitum back in 2022.

We believe their groundbreaking motor technology will bring much needed innovation to the mining industry by delivering more efficient and higher performing production equipment. Specific to Alliance, we believe their technology will improve our mining processes, reduce capital and operating costs, and help extend the life of certain mining equipment. Additionally, while we are unable to publicly quantify any potential revenue impacts at this time, we believe the relationship could lead to new revenue streams for Matrix by selling additional products to third-party mining customers and OEMs around the world, like Matrix is currently doing, as a technology leader for underground proximity detection systems. In closing, our business continues to be a generator of strong cash flows that positions us to continue improving our balance sheet by simultaneously pursuing the highest and best uses for our capital.

I am proud of ARLP’s performance in 2023 and encouraged by the opportunities in front of us as we gear up for what should be another successful year in 2024. That concludes our prepared comments. And I’ll now ask the operator to open the call for questions.

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Operator: Thank you. We’ll now be conducting a question-and-answer session. [Operator Instructions] And our first question will be coming from the line of Nathan Martin with the Benchmark Company. Please proceed with your questions.

Nathan Martin: Yeah, thanks, operator. Good morning, Joe. Good morning, Cary. Thanks for taking the questions.

Cary. P Marshall: Good morning.

Nathan Martin: I want to start with the distribution this quarter. Coverage ratio was 1.8 times, looks like for the full year ‘23. But it did dip to 1.3 times in the fourth quarter. I know you guys have said you’re okay with the distribution dipping down temporarily, but it seems like keeping it closer 2 times, which is where you prefer to be, obviously. But it would be great to get your thoughts there on the distribution and the coverage. And I think you mentioned last quarter that your board meeting will be behind you by the time this call came around. So, maybe any takeaways from those conversations as well. Thank you.

Joe Craft: Thank you for the question. So we did finish the year, as you mentioned, with those coverage ratios that are included in our press release. As we look to 2024, as we’ve indicated, we believe 2024 has a potential to be just as good as 2023. There are opportunities as we go looking towards 2025, we’re also optimistic about our opportunities in ‘25. We just talked about the capital will be coming down substantially in ‘25 versus ‘24. We believe our operating costs will be lower, and primarily because of the efficiency of projects we’ve talked about. We believe natural gas should be higher priced in 2025 because of the LNG terminals that are coming online in back half of 2024 in the United States. So there’s a lot to be optimistic about.

We’ve signed some long-term contracts that give us some stability through 2028. Yet at the same time, we do have not as much contracted in ‘25 as we have in ‘24, where we’ve got over 90%. So I think as we move through the year, the Board will make a decision on a quarter-by-quarter basis as to whether to maintain the distribution at the $0.70 level. I believe we’re in a position to do so, and that would be my expectation. And another factor that we’ll have to consider is how does the market react to our continued growth and our continued opportunities that we have in front of us. As I’ve mentioned in the past, we’ve been disappointed that our unit price didn’t track the distribution increase that we gave in 2023. So it’ll be a quarter by quarter decision.

But we are — as Cary mentioned in his prepared remarks, we’re very focused on growing our company, maintaining and growing our cash flow, and returning that to the shareholders, similar to what we’ve been doing over the last 25 years.

Nathan Martin: I appreciate that color there, Joe. Maybe next, just a bit of a multi-pronged question. You just mentioned some of the contracts [you guys did] (ph). It looks like an additional 12 million tons over that 2024 to 2028 period. First, is it possible to get a breakdown of how those tons were spread throughout that time period? And then maybe some more color on what the pricing looked like. And then second, for this year specifically in ‘24, what portion of those committed tons are fixed price and what portion are open to market pricing still at this point? I would assume the domestic tons are largely fixed, but are your export tons tied to an index like API2 or something where you could have some volatility? Are there any floors or ceilings in those contracts, maybe like some of your peers have had?

Joe Craft: So as far as the actual volume beyond 2024, I don’t have those numbers right now. I don’t know if you’ve got those, Cary. But back to the pricing, the pricing in ‘24 of our contract book is comparable to what our 2023 average revenues are. Domestic contracts do have escalators in them. Some are fixed. Some are actually indices. Their — our export volumes, I believe, just goes through 2024. I don’t think we have any in the out years, and those are fixed prices. Some of them do have indices — they do tie to indices, specifically our metallurgical contracts are tied to some indices that will fluctuate based on what the market is. What did I miss from your questions?

Cary. P Marshall: Yeah, I think, Nate, just in a follow-up in terms of the out years, I think if you go back and look at where we were guiding last quarter, just in terms of commitments, if you look in the out years of those 12 million tons, they do go, as we mentioned, out to 2028. Most of those volumes that go out for that period of time are in the 1.5 million ton range once you get beyond the 2024 period. So if you look at 2025 to 2028, that would give you an indication of the level of contracts. Some of them will scale up and scale down, but they may be 2 million one year and then kind of scale down to closer to 1.25 as you get toward the tail end of it. But generally speaking, it’s fairly significant volume as you go over that 2025 through 2028 time period.

Joe Craft: And the message is they understand that they need to start layering in some volume. And they’re basically giving us confidence that those plants are needed not only through the ‘28 time period, but beyond. So we are hearing from our customers that the expectations are that with grid reliability, with the growth in electrification, that the existing fleet of coal plants need to stay open longer. And we will see that play out. I mean, the Biden administration continues to suggest that they don’t need to keep the plants open, whereas Republican candidates have all suggested that we do. So I think that we believe that the law of physics is [now required] (ph) and the growth and demand that these plants will stay open and we’re very confident that our production volumes will be sustained for the next five to six to seven years.

Nathan Martin: That’s very helpful, guys. Maybe just to kind of wrap that up. I mean, really, I guess my questions kind of revolve around maybe what gets you to the lower, the high end of your full year ‘24 price per ton guidance and you’ve got 32.5 million tons, it looks like, committed and priced. Maybe what’s your assumption there in API2 price if that’s what your export volumes are tied to? We’ve seen some pressure there obviously. You mentioned that domestic contracts, where you’re pricing those have been above the spot rates, so that’s a positive? Just trying to get a sense of maybe what gets you to the lower high end of that range. Thank you.

Joe Craft: Yeah, the whole range is going to be dependent on the export market. So we’ve seen the export pricing on the indexes drop probably $10 to $12 in the last month. We don’t believe that’s sustainable. We believe that the pricing will get back in the API2 level that’s greater than the $110 to $120 range, because we believe that’s what the world supply will demand for those products. We do believe that demand is stable. However, the pricing right now is a little soft. And so the whole swing will be how we place those export tons throughout 2024 that will be the determining factor as to the ranges that you spoke to. But when you look at the total compared to our UI position, it doesn’t move the needle that much because we have so little times that are needed to be placed for 2024.

Nathan Martin: Great. I appreciate those comments, guys. I’ll pass it along to the next caller. Thanks for your time and best of luck here in 2024.

Joe Craft: Thank you.

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

Mark Reichman: Thank you and good morning.

Joe Craft: Good morning.

Mark Reichman: So going into the fourth quarter, the delta between what was committed and priced in 2023 and the — your guidance, that was kind of expected to be kind of what happened in the export market. So the tons sold came in kind of at the low end compared to the guidance. So when do you expect that delta between committed and priced and what was sold to carry over into 2024? Will that mainly be in the first quarter? And I assume that’s kind of already kind of baked into the 2024 guidance?

Cary. P Marshall: Yes, that’s right. That’s right, Mark. We would expect those tonnages to roll over into the first quarter and it is baked into the guidance that we provided.

Mark Reichman: Okay. And then, during the last conference call, you didn’t expect much in the way of fourth quarter outside coal purchases, but sequentially the number increased over 20 million from 11.5 million. So did the adverse conditions at Mettiki, did those just extend beyond your expectations and do you think we’re done with the outside coal purchases?

Joe Craft: So, yeah — so we, in the last earnings call, we felt like the longwall would be up and running by the end of November and it was actually delayed until the end of December. So we did have some shipments that we needed to buy some coal that we thought we would be able to produce that we came up with short and we may have to actually buy some in the first quarter. The longwall did come up the last week of December. It is operating as expected. But depending on whether the timing of shipments is possible, we may have some purchases in the first quarter. I don’t believe we are anticipating anything beyond that.

Mark Reichman: Okay. That was at least when I compared to what our estimates looked like. I think we were at the low end, but that was kind of a difference. And then just lastly, I know it’s too early to talk about revenues, but this agreement between Infinitum and Matrix, rather than revenue numbers, can you just kind of maybe highlight the economics of becoming a global distributor for Infinitum? Are there any shared arrangements on the development of new mining products? So I mean, will they just get the margin from the sale of Infinitum’s projects, products? Or are there some other, like, when they go in and install a project for a mining customer, are there other sources of revenue? What does kind of the revenue sub-stack or revenue stack look like for Matrix when they enter an arrangement like that with Infinitum?

Joe Craft: Well, the initial project they were working on, they basically are making equipment that effectively we’re going to be testing in our operations in 2024. That’ll start, I believe, in the second quarter of this year.

Cary. P Marshall: Yeah.

Joe Craft: Cary, do you have those more specifics? And then that will roll in, and then we will start to hopefully be marketing those in 2025.

Cary. P Marshall: Yeah, that’s right, Joe. The products, it kind of goes back to similar to what we did with IntelliZone, where we’re providing proof-of-concept for these underground. And so we have been in discussions with the regulatory agencies here for underground mining and do anticipate those going underground here. Certainly by the second quarter we’re hoping to push it even a little bit quicker than that.

Joe Craft: And we’ve got another motor technology that we’re also working on that would also need MSHA approval. And that’s too, we would think that that would be manufactured and then sold into 2025. Our initial focus will be domestically, but then it too would be rolling out, similar to our proximity device and IntelliZone that is currently being marketed in South Africa and Australia.

Mark Reichman: Well, that’s very helpful.

Joe Craft: I think that when we look at it, to try to give you some idea, so I think we’ve got invested around $67 million in Infinitum. And we believe that cash flow that we’ll receive just from these two announcements are going to give us an attractive double-digit return just on net investment as a byproduct of that relationship. And [that doesn’t even] (ph) anticipate what we would get on that actual investment in Infinitum. So that sort of gives you an idea of the scale of the opportunity just from this one or these two products that we are talking or are ready to design, build, and sell into the marketplace.

Mark Reichman: Well, that’s really helpful and I appreciate that. I really didn’t have too many questions on the guidance. I thought that was pretty straightforward and looked pretty good. So thank you very much.

Cary. P Marshall: Thank you, Mark.

Operator: Our next question is from the line of David Marsh with Singular Research. Please proceed with your questions.

David Marsh: Hi, guys. Thank you for taking the questions. Appreciate it and congrats on a really great year. Just as we start to look forward into ‘24, I guess, as some of my questions kind of echo a little bit some of the questions previously. I mean, particularly in Appalachia, it looks like you guys had some margin compression. Was that in part or largely due to your production shortfall there and your need to purchase other externally produced coal?

Cary. P Marshall: Yeah, I mean, that’s right, Dave. I mean, there was margining compression in Appalachia, primarily driven by the items that we talked about with the production issues, particularly in the back half of the year that we experienced within the region.

Joe Craft: So essentially, we had — longwall at Mettiki didn’t operate the second half of the year. So that now is operating. So you’re going to see us go — that volume to come back into the market. At MC we went from four units to three units starting, I believe, in September or October. So we’re planning to operate at three units at MC. We do have some new equipment there. So we think that our cost should be rather relatively stable. ‘24 there, but….

Cary. P Marshall: And then, David, as you look into 2024 in terms of the compression that you see on the margins on that side of it, that’s primarily on the top line driven as we had some higher price contracts that were — that we shipped on in 2023 that expired. And the market environment’s a little bit lower as we look at where we’re contracted in 2024 related to the Appalachia region.

David Marsh: Right, understood. So just pulling that thread forward on the Appalachian EBITDA expense per ton, we should naturally expect that to decline from the fourth quarter level, correct? And then what would the trajectory be of that? I mean, do you think you can get back down into the 40s or is that — are we living in a 50s kind of world in terms of expense per ton there?

Joe Craft: I’d say you’re looking at the 50s, not the 40s. The industry has experienced inflation like all others. But — so all of our costs have gone up somewhat just because of inflation. But then you factor in going from four units to three. Another factor in Appalachia in 2024 is we’re in the process of moving to the new reserves we bought at Tunnel Ridge. And so we do have shorter panels in 2024 compared to historic as well as projected in ‘25 forward. So we’re probably going to have some reduction in volume at Tunnel Ridge that enters into that mix. But, yeah, you’re looking at probably mid-50s in Appalachia for the year would be the estimate right now, which is what we’ve sort of guided to, the $54.25 to $57.25.

David Marsh: Right. Yeah. And I mean are we going to — I’m just trying to get an understanding of trajectory on it. Will it start still kind of closer to the Q4 level and gradually decline throughout the year or is it going to just — is there going to be a pop down and then a flat kind of throughout the year?

Joe Craft: Right now, our quarter — our first quarter appears to, it looks like it’ll be in the low end of the range, if not lower than the range. So if we can get the volume out of Mettiki that we’re anticipating, the first quarter should be a good quarter. Then when you look at the trajectory beyond 2024 into 2025, we should start seeing the benefits of us getting into the new reserves at Tunnel Ridge. So we should see some decline in the 2025 time period, depending on the inflation of course, inflation could take some of that away from us.

David Marsh: Yeah, sure. Absolutely, absolutely. Well, that’s excellent. That’s very, very helpful. And then just lastly from me, in terms of — as you look at your cash flow and your opportunity set with that cash flow, could you just kind of rank it in terms of priorities, expansion CapEx into like the new lines of business that you’ve been pursuing versus debt reduction and potential increase to the distribution?

Joe Craft: So I think our priority, as Cary mentioned, will be pay down the debt. We will be paying down the senior notes in ‘24 and potentially in the first quarter of next year. However, he’s also looking at refinancing, or entering into some facilities that will give us capacity to grow. Some of them will be funded, but hopefully some of them will be unfunded, be revolver type arrangements. So then as far as growth, we’ve talked about oil and gas. We’ll continue to invest there. We will still have opportunities to invest in other items. There’s nothing on the horizon that I can give you any specifics on how we would allocate that capital, but we are continuing to look at multiple areas of investment. And so we’ve got a capital allocation process that will evaluate investments in future cash flow growth, which we do put as a priority.

And then alternatively, we will look at whether there are other uses for that capital. I mean, I think that distributions have continued to be high on our priority list. So it’s my goal that distributions will be consistent, but we got to evaluate the future on a quarter-by-quarter basis as we talked about. So that will include not only just the future markets but just as important the opportunities in front of us to make investments.

David Marsh: Got it. Thank you very much. That’s all I have.

Operator: Our next question is from the line of Dave Storms with Stonegate Capital. Pleased to see you with your questions.

Dave Storms: Good morning.

Cary. P Marshall: Hello. Good morning.

Dave Storms: Good morning. Just a couple quick ones for me. Curious as to how you’re thinking about the labor outlook now that we’re kind of through the holidays and maybe labor might start picking up. I know you mentioned that you might be sticking with the three units at Mettiki, I believe it was, but with some of these capital improvement projects expected to be completed this year, is that going to require increased hiring?

Joe Craft: So, we have seen an improvement in our retention and our availability of labor, specifically in Illinois Basin as an example. So we do have the Henderson County mine that we are developing that should become operational. Well, it is operational as we’re ramping, but it should get to where we will be increasing staffing at that mine by the end of 2024 or during 2024 as that ramps up. We expect that that plant or that mine will be — will have more production starting in 2025, that — effectively what we’re doing at River View is we’re basically having two portals instead of one. And that second portal will be at Henderson County. So there will be some hiring there. There still is a need of some hiring at our mines, just back to normal attrition, not what we’ve been experiencing in the last two or three years, but what we would consider to be normal.

So I think on a labor front, we’re in a better position than we have been historically. At MC Mining, we still see challenges, so we’re currently not anticipating increasing that mine back to four units. It’s possible, but that’s the one area that we’re continuing to see challenges of being able to attract sufficient numbers to commit to bringing back that unit. But I think everywhere else, we’ve been encouraged by the recent activity of people wanting to come work for us.

Dave Storms: Very helpful. Thank you. And then just on the inventory front, how comfortable are you with your current inventory levels? Are you expecting to continue to run those off? I know they were impacted by that temporary outage. Now that hopefully things are starting to normalize, would you expect your inventory levels to continue to track down slightly?

Joe Craft: I think, our goal is to maintain, more than likely, just as a working inventory level, given the amount of tons we’re putting in the export market. It’s right at a million tons a month. But it will fluctuate based on timing of vessels, because the vessels take, it may be on the 30th, it may be on the second, so there could be 60,000 to 100,000 tons right there that could put us in a position that we could be a little higher than that. Our goal would be to maintain inventory right at that million ton a month level. Right now I think it’s around 1.3 million, something of that nature, but — so it’s going to be in that swing area I would say.

Dave Storms: Understood. And then last one from me, kind of on a macro level. I thought I saw that LNG export terminal constructions have been paused in the US. Do you anticipate that if this becomes a prolonged pause, that it will increase demand for international coal as consumers need to switch from LNG to coal, or is this not something that you really have on a radar at this point?

Joe Craft: The pause is not in construction. It’s on new permits. It may be permits of the under — currently under regulatory review. But as far as the terminals that are under construction, they’re continuing to be completed. And the permits that have been issued that are not under construction, it’s our understanding that those two are allowed to proceed. So we don’t anticipate any interruption in the demand indoor supply for LNG until the end of the decade as a result of these permits. We believe that these permits — these plants that have been permitted will in fact be developed and that the demand for LNG will continue to be strong for the remaining decade.

Dave Storms: That’s very helpful. Thank you.

Operator: Thank you. At this time, this concludes our question-and-answer session. I’ll hand the call back to Mr. Cary Marshall for closing remarks.

Cary. P Marshall: Thank you, operator. And to everyone on the call, we appreciate your time this morning and also your continued support and interest in Alliance. Our next call to discuss our first quarter 2024 financial and operating results is 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.

Operator: Thank you. You may now disconnect your lines at this time. Thank you for your participation.