Alliance Resource Partners, L.P. (NASDAQ:ARLP) Q2 2023 Earnings Call Transcript

Alliance Resource Partners, L.P. (NASDAQ:ARLP) Q2 2023 Earnings Call Transcript July 31, 2023

Alliance Resource Partners, L.P. misses on earnings expectations. Reported EPS is $1.23 EPS, expectations were $1.29.

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

Cary Marshall: Thank you, operator, and welcome, everyone. Earlier this morning, Alliance Resource Partners released its second quarter 2023 financial and operating results, and we will now discuss those results as well as our perspective on current market conditions and outlook for 2023. 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.

And 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 second quarter, then turn the call over to Joe Craft, our Chairman, President and Chief Executive Officer, for his comments.

Our strong performance in the 2023 quarter included consolidated revenues of $641.8 million, which were up 3.5% versus the prior year period. The year-over-year improvement was driven primarily by higher coal sales price per ton, which was up 5.7% versus the 2022 quarter and continues to reflect the positive impacts of our contracted order book. On a sequential basis, total coal sales price per ton was down 7.9% or $5.41 per ton. This was primarily due to approximately 500,000 higher-priced 2022 carryover tons shift in the sequential quarter at our Tunnel Ridge mine in Appalachia. In our Royalty segment, total royalties were $50 million, down 8.3% year-over-year and down 2.1% sequentially as lower realized oil and gas commodity pricing was partially offset by increases in coal royalty revenue per ton.

Specifically, oil and gas royalties average realized sales prices declined 40.2% per BOE versus the 2022 quarter as NYMEX WTI benchmark pricing peaked during June 2022. Sequentially, oil and gas royalties average sales prices were 4.7% lower per BOE. Coal royalty revenue per ton increased 17.4% versus the 2022 quarter and 5.5% sequentially. As it relates to volume, coal production increased 5.8% to 9.4 million tons compared to the 2022 quarter, while coal sales volumes decreased 0.3% to 8.9 million tons, resulting in a build in coal inventories of 500,000 tons during the 2023 quarter. Compared to the sequential quarter, wholesales volumes increased 5.1% due to higher sales volumes in Appalachia. There were no longwall moves at our Tunnel Ridge mine in Appalachia this quarter, whereas we had two moves in the sequential quarter.

Coal royalty tons sold declined 2.8% year-over-year. Oil and gas royalty volumes were 40.6% higher on a BOE basis due to increased drilling and completion activities on our net acreage and the acquisition of oil and gas mineral interest from Jason Belvedere [ph] during the second half of 2022. Turning to costs. Segment adjusted EBITDA expense per ton sold for our coal operations was $37.85, an increase of 7.8% versus the 2022 quarter, primarily due to higher labor-related expenses, higher maintenance costs as well as the impacts of increased sales-related expenses due to higher sales price realizations. These costs were partially offset by lower materials and supplies expenses during the 2023 quarter. On a sequential basis, cost per ton were 4.6% lower primarily on the strength of the additional Appalachia volumes from our lower-cost Tunnel Ridge mine.

2023 quarter net income and EBITDA increased 3.8% and 1%, respectively, over the 2022 quarter primarily due to higher price realizations in coal, which more than offset lower realized prices in oil and gas royalties along with the inflationary pressures I previously described. Now turning to our balance sheet and cash flow. Alliance had another strong quarter of cash generation with $153.5 million of free cash flow before growth investments in the 2023 quarter, an increase of 88.7% year-over-year and 9.7% versus the sequential quarter. Our total and net leverage ratios were 0.4% and 0.14 times respectively, total debt to trailing 12 months adjusted EBITDA. Total liquidity of $717.2 million remained strong at quarter end, which included approximately $284.9 million of cash on the balance sheet.

Our robust cash-generating power is affording us many options to attractively deploy capital. During the 2023 quarter, we paid our quarterly distribution of $0.70 per unit, equating to an annualized rate of $2.80 per unit that we expect to maintain throughout the year. This distribution level is unchanged sequentially and up 75% year-over-year. Additionally, we remain committed to prudently managing the outstanding balance of our senior notes due May 2025. During the 2023 quarter, we repurchased $34.2 million of senior notes. And in July 2023, we redeemed another $50 million of senior notes at par. As a result, we ended July with $289.2 million in aggregate principal remaining on the $400 million original issuance. We intend to execute additional purchases and redemptions at par of the senior notes with available cash flows over the next several quarters.

As we turn to our updated full year 2023 guidance detailed in this morning’s release, I’d like to spend a few minutes discussing the current state of our markets. As we mentioned earlier in the year, the mild winter and slower start to summer reduced overall demand for both coal and natural gas in the United States during the first half of 2023. Natural gas prices declined sequentially and remained significantly below the year ago quarter. Lower natural gas prices affected coal burns due to more competitive gas-fired dispatch options for our customers, particularly during spring shoulder demand season. Since the end of the 2023 quarter, we have seen a turn in weather patterns with historically high temperatures blanketing much of the U.S. and portions of Europe.

A hot summer doesn’t necessarily dramatically impact coal burns in the near term as our customers’ units typically run baseload during summer peak demand, but it can highlight the vulnerability of the grid when demand is high and renewable sources are unable to adequately respond. Furthermore, if hot weather persists into the fall, it can change normal burn schedules and accelerate coal consumption, reducing inventories heading into winter. Overall, based upon the strength of our year-to-date results, our contracted committed tons and a relentless focus on cost control, we remain optimistic 2023 will be another record year for ARLP. As we updated our 2023 full year guidance ranges, the mild market conditions I just described caused some movement in contract deliveries and shifted the mix between export and domestic markets.

We now anticipate ARLP’s overall coal sales volumes in 2023 to be in a range of 35.5 million to 36 million tons, down from the previous range of 36 million to 38 million tons. Illinois Basin volumes have been adjusted to reflect lower volumes at our Gibson and River View operations, while our Appalachia volume guidance reflects an extended longwall move at our Mettiki mine. Our committed tonnage for full year 2023 is 34.5 million tons at the end of the quarter or 96% to 97% of our anticipated sales tons. Of that total, 4.8 million tons are currently committed to export markets. The balance of unsold tonnage levels is expected to be supplied in the export markets, primarily from our lowest cost operations, thereby still generating attractive margins.

Sales pricing for the year is anticipated to be slightly lower than at the time of our last update, we’ve chosen to modestly adjust the top end of our range for average coal price realizations down by $1 to a new range of $65 to $66 per ton versus $65 to $67 per ton previously. On the cost side, solid execution from our operations team allows us to improve our outlook for segment adjusted EBITDA expense per ton by $1 to a new range of $38 to $41 per ton. Within Appalachia, we do anticipate higher costs in the back half of the year due to the extended longwall move at Mettiki in the third quarter as well as a normal longwall move scheduled for our Tunnel Ridge mine in the fourth quarter. In our oil and gas royalty segment, we are reiterating our volume guidance ranges for the full year 2023.

And we also made a number of adjustments to our outlook including lower DD&A, a $10 million improvement in SG&A and a slight reduction in total capital expenditures. With that, I will turn the call over to Joe for comments on the market and his outlook for ARLP. Joe?

Joseph Craft: Thank you, Cary, and good morning, everyone. I want to begin my comments by thanking the entire Alliance organization for their continued hard work and dedication, which allowed us to post solid results for the quarter and the first half of 2023. Their efforts helped us deliver year-over-year improvements in coal production, realized coal prices, oil and gas royalty volumes, net income and EBITDA. Our year-to-date results have been impressive despite coal demand, both domestically and globally being lower than we expected entering this year due to a slower economic growth, mild weather in our targeted markets and lower natural gas prices. The strong first half performance was led by significantly higher coal sales price per ton, which rose by 21.8%, resulting in total revenues in the 2023 period, increasing by 20.4% to $1.3 billion compared to $1.1 billion for the 2022 period.

The year-over-year improvement in realized coal prices reflects the positive impacts of our contracted order book. Segment adjusted EBITDA expense per ton sold for our coal operations for the first half of 2023 was $38.73, an increase of 15% versus the 2022 period, primarily due to inflationary pressures throughout the year. Our net income and EBITDA rose sharply in the 2023 period, increasing 79% and 29.6%, respectively, over the 2022 period. These increases reflect higher sales volumes in both coal and oil and gas royalties as well as higher price realizations in coal, which more than offset lower realized prices in oil and gas royalties along with the inflationary pressures that Cary previously described. As Cary also mentioned, we have adjusted our production targets lower for this year in response to lower domestic demand driven by lower natural gas prices.

We are now operating four production units at our Gibson South mine, down one unit from the original guidance in January 2023. At River View, we have moved some units from production mode to construction mode to accelerate the timing of the previously announced expansion project at River View. In June, we had a groundbreaking event for the new Henderson County mine site, where the new shaft will connect through underground conveyors to eventually be conveyed to the River View prep plant and barge terminal. This project is now scheduled to be completed at the end of 2024. Committed and priced sales tons currently represent 96% to 97% of our updated guidance range, and we plan to sell any remaining uncontracted tonnage primarily into international markets.

While our view of export sales volume opportunities has not changed, pricing has been more volatile than previously expected. Accordingly, we have adjusted the top end of our coal sales price per ton sold range downward upon the recent market analysis. On the positive side, we are also lowering our cost estimates by the same amount per ton sold for the year as our team continues to find ways to reduce expenses in a severely volatile inflationary environment. During the 2023 quarter, we agreed to sell an additional 8.6 million tons with multiple customers for coal to be delivered over the 2024 to 2026 time period. As we can see in our updated sales guidance, we committed meaningful tonnage in 2024. We expect contracting activity to continue in the coming months.

As of the end of the second quarter, we have committed to sell 25.5 million tons domestically in 2024 and 1.4 million tons to international markets, representing an increase of 3.5 million tons from our last update. We also committed and priced a total of 5.1 million tons for delivery in 2025 and 2026. Our contracting customers continue to value the certainty of supply we provide across all market conditions. The modest guidance revisions this quarter have not changed our view that we still are on track to achieve record financial results this year. As we look beyond 2023, we are encouraged by growth opportunities being pursued by our New Ventures Group, the recent increase in the forward oil and gas price curves and acquisition prospects for our oil and gas royalty segment.

We are also seeing stability for coal demand over the next several years. Many of our customers are projecting significant growth in electricity demand as record numbers of new manufacturing facilities are being announced to come online over the next several years. All of these announced projects require exceptionally large electrical loads, adding to the reliability concerns of the stakeholders responsible for meeting the rising energy needs of their customers. The increased electricity demand should lead to slowing the premature closing of coal-fired power plants in the Eastern United States. We also expect the growth in LNG terminals coming online over the next 5 years will support higher domestic natural gas prices, further supporting stable demand expectations for our coal segment over the next 5 to 10 years.

In closing, I’m pleased with ARLP’s solid first half results and encouraged by the opportunities in front of us. We continue to add to our heavily contracted coal book at attractive levels and our robust cash flow generation positions us to continue improving our balance sheet and pursue attractive investments to meet the evolving energy needs of tomorrow. Looking forward, we believe ARLP is well positioned to deliver solid growth and attractive cash returns to our unitholders in 2023 and beyond. That concludes our prepared comments, and I will now ask the operator to open the call for questions.

Q&A Session

Operator: Thank you. [Operator Instructions] Our first question is from Nathan Martin with Benchmark Company. Please proceed.

Nathan Martin: Hey, good morning, Joe, Cary. Thanks for taking my questions.

Cary Marshall: Morning.

Joseph Craft: Morning.

Nathan Martin: First, great job on the cost side. However, similar to the first quarter, 2Q shipments a little bit lower than I expected, especially based on production. So maybe a bit of a multipronged question to start. First, anything behind the additional 0.5 million tons of inventory built. You guys did mention reduced export sales. Second, do you feel confident shipments will pick up in the second half over the first half? What do you expect that sales cadence to look like in 3Q, 4Q? And then finally, is there any risk to the further sales guidance cuts based on your conversations with utilities at this point? Thanks.

Joseph Craft: So to try to – I try to remember all your questions. So let me go ahead and give you a stream of answers here, and then I’ll follow up to see if I make sure that I covered everything you asked. But specifically to the first half, our production was running on a higher clip through the second quarter. And as a result, that’s the primary reason for our increase to the 500,000 ton inventory level. So our actual contract book has been run consistent – has been running consistent with what our ratable requirements are under the contract. So if we look at our contracts and look at our average ratable rate, we’re right at 99% of what we should be under the contracts, which is really good because there’s always certain issues that people have to deal with.

So we feel very good about our customers adhering to the contract terms in the first half. And as we look to the second half, we expect the same. I think that there are a few customers that are constantly asking us for deferrals. However, I believe all our customers appreciate what we did for them in 2022, and they understand that they should do the same thing for us this year. As we think through the biggest issue, I guess, on timing, it gets into the export market. We have a couple of customers that are definitely committed to take the volume. The timing is somewhat lumpy, and that does impact some of the volumes in the first half as well, not by much, but by a little. As we look to the end of the year, we’re anticipating with our guidance, about 0.5 million tons of inventory.

I would not expect that to grow beyond what would be normal. When we entered into this year, we had about 0.5 million tons of carryover and most of that was just tied to timing of vessel shipments and other methods. So I think as we look at this year, trying to factor in what we think the demand for export is, what we think the contract takes under our contracts would be. We believe we’re on track to our current guidance and the way I would measure any variability to that. And we wouldn’t – we don’t expect it to be greater than what our 500,000 ton was last year. It’s always possible for things to change, but there’s a lot of encouraging signs as we look at the last 12 months, one for comparison, when you compare 2022 against 2023, about this time last year, we saw customers starting delay and defer coal tonnage.

So when you start looking at comparisons in ’23 versus ’22, you’re not going to see the significant difference as what we saw in the first half on coal shipments in our view. We’ve seen this hot spell in July, and that doesn’t seem like it’s going to abate anytime soon. So we think that’s going to be positive for coal burns. The natural gas forward curve is still approaching 350 at the end of the year, which is constructive and going into the winter, depending on exactly how long this heat wave goes and really what happens in the economy, we believe that we’re well positioned running into 2024. So overall, I’m very pleased with our customers and their willingness to continue to take under the terms of our contract. I’m optimistic that the guidance we’ve given that there should not be any further adjustments on demand.

We will be, as we said in our prepared comments, slowing down production. So Cary, I don’t know if you want to comment specifically on the cadence for the third quarter and fourth quarter on sales that we’re projecting.

Cary Marshall: Yes. I think, yes, as you just take a look at what our expectation is in the third and fourth quarter, it’s pretty ratable between the two quarters. When you look at the anticipated volumes that we would anticipate to ship in each one of the quarters. So when you take a look at what we did in the first half and back into our overall guidance, I would anticipate shipments to be pretty equal in the third and fourth quarter of the year. It’s not really that unusual to what we experienced last year at this time as well. We were in a similar situation, and that was the result last year, and that’s our expectation for this year as well.

Nathan Martin: Great. Really appreciate the color there, guys. And then maybe looking ahead, good job securing that additional tonnage you called out for ’24 to ’26. And as we looked at ’24 and beyond you feel like this 36 million ton run rate for ’23 is it still achievable over the next few years? I know there’s obviously some puts and takes, but it’d be great to get your thoughts on maybe potential EPA regulations flowing around. Joe, you just talked about some of the demand that’s coming online on the industrial side. And how do you think those things affect your production and maybe even U.S. coal production overall as we look ahead?

Joseph Craft: So to answer your first question, yes, we do believe the $36 million run rate is sustainable over the next several years. When we look at the negotiations that are yet to be determined in the back half, we’ve got probably over a half dozen customers that we believe will be in the market to fill out their book for ’24 plus. Most of our solicitations have been for a 3-year period and most of them are at similar tonnage. So we believe that with our customer base and their plans for the future, we do see the ability to maintain our $36 million at a minimum. It could go higher depending on what we want to do in the export market. So we’re targeting about 6.5 million tons this year into the export market. It’s possible that, that number would go down if we are successful on some solicitations in the back half with the ability to flex back up to something over $36 million, depending on the export market next year and the following year.

So specifically to the EPA rules, EPA, they are out there in force trying to accelerate this transition. We believe that essentially everything they’re doing is in violation. The major questions often [ph] that was the result of the West Virginia versus EPA decision last year by the Supreme Court. So there’s a lot of legal activity going on to try to prevent those rules from coming into effect. I think that with the demand projections for electricity there are several utilities that are engaged in as well as the different RTOs trying to give warning signs to the administration that we need to maintain all of our fossil fuel fleet. That’s both coal and natural gas. There’s still pressure for some that believe that you can continue to close plants and still grow electricity.

I don’t quite understand that as far as generation to meet the growing demand. So we’re – we feel good about the future, and we feel good about the demand. Last week, just Elon Musk spoke at a Pacific Gas and Electric Summit. And he basically was saying that his biggest concern is there’s insufficient urgency and people just don’t understand how much electricity demand there will be. He’s basically the headlines were a tripling of electrical output. We believe the same thing that Elon is saying. I don’t know about the math, but we definitely are seeing in everything we’re looking at that the demand predictions for electricity are pretty low by our investor-owned utilities compared to what we’re hearing of opportunities to make investments in this transition area that’s going to require quite a bit of electric load.

And so and you still see the delay in getting replacements for coal plants. So we think it’s going to be delayed practically speaking, and hopefully, by policy. But President Biden continues to double down on his beliefs. But I think in talking to the industry, there’s some caution that’s being raised and we’re getting input from customers just saying that we need you to continue to maintain your production level for the next decade is what we’re hearing now. We’ll have to wait and see where the politics rules over what the engineering officers are saying or engineering management saying. But we feel good about our demand staying at current at this – at the 36 million tons, and hopefully, we can grow it a little bit.

Nathan Martin: Very helpful, Joe. Thanks. And then maybe just finally, if I could ask one last question. You guys mentioned your cash position, your liquidity is affording you the ability to look at multiple investments. Can you talk about some of those opportunities you guys are seeing in the marketplace currently, maybe on the oil and gas side in the New Venture side? And any thought on timing or size would be great as well.

Joseph Craft: On the oil and gas side, we committed and everything is still continuing to be the same as what we’ve indicated to you all before, and that is we’re reinvesting prior year’s EBITDA into the oil and gas space. So through the second quarter, we’ve invested around $76 million and with our guidance that leaves probably $35 million or so, well, we had $35 million for the ground game is what we call it as opposed to competing in packages. And we’ve completed around $4 million of that in the first half. And just in July, we closed $5 million of investments. As we look to the balance of the year, so there’s another $25 million or so, we would – we’re – we think there are opportunities out there. So I would expect that we will be able to complete those investments in our oil and gas segment, in our royalty segment.

We continue to be positive on that segment for the long term. We continue to see oil demand in the world at record levels. We really just don’t see that changing even with the convert into electric vehicles, we think electric vehicles will grow. We’re not in the belief that it’s going to grow as fast as I believe. But with the refining and the world demand for oil, we believe that we’ll continue to see great opportunities to invest that cash flow and get returns comparable to what we’ve been getting, which we find them to be attractive. With natural gas, with LNG terminals coming on, we think the demand is going to be growing there as well, which benefits not only our royalty segment, but also should impact domestic pricing, which will benefit our coal operations.

On the New Venture side, Matrix is continuing to perform as we previously expected. We are also looking at several opportunities to invest in the New Ventures area. Our primary focus right now are on energy solutions issues, which basically get into batteries, storage and other aspects of the battery belt and opportunities that are presenting itself with the continued investments from Michigan down through Indiana, Kentucky, Ohio, Tennessee, et cetera, which is right in our service territory. I have nothing to talk to you about today, hopefully, by the next earnings call, we’ll be able to give you better color on the opportunities that we’re talking about there.

Nathan Martin: Great. Really appreciate those comments, Joe. I’ll leave it there, guys. Best of luck in the second half.

Joseph Craft: Thank you.

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

Mark Reichman: Good morning and thank you for taking my question. I was going to – can you hear me?

Joseph Craft: Yes. We can hear you.

Mark Reichman: Okay. So I had to dial in on my iPhone because we were having problems with the server on the other phones. So the question I have is looking at sales, I mean it looks to me like even at the low end of your guidance, you’re still going to have modestly higher sales in the second half. For me, I think the wildcard is really the price. Illinois basin pricing has been relatively steady, but the pricing in Appalachia fell considerably second quarter versus the first quarter. But your guidance suggests on a total basis that really only shaved off $1 at the top end. So could you just maybe illuminate your expectations on pricing between the basins for the remainder of the year?

Joseph Craft: Yes. So we’re totally focused on the international markets. So there’s really no spot market. We don’t anticipate there’ll be any activity for 2023. And if you look at the one thermal mine we have basically in East Kentucky is really a premier product, and it doesn’t really trade off those indexes. We don’t have that much to sell open to the market this year there anyway. So our reduction down really reflects the decrease in API-2 in the export pricing of the export market that we’re planning to build for a balance of these sales. When you’re looking at the pricing, that’s on a delivered basis, so there’s a lot of different moving parts back to transportation and logistics that can solve in some of that, as far as getting a good net back at the mine.

So we estimated when we’ve got several conversations going on with our trading partners for those export volumes. And we believe we conservatively priced what we think those sales opportunities are going to be in the back half of this year, and we’re confident that we can place those tons. So we feel really good about our guidance as long as we can continue to execute and the demand stays consistent with where it is now. And it’s hard to see what catalyst would change that based on conversations we have, there’s always surprises. But right now, we feel very good about our guidance.

Mark Reichman: Well, I guess what I’m kind of getting at is it kind of implies an improvement in the third and the fourth quarter in Appalachia pricing relative to the second quarter, but maybe not as high as the first quarter. I mean, but you would expect maybe a rebound in pricing in Appalachia, assuming Illinois Basin remains relatively constant. I think right now, I have Illinois basin a little weaker in the second half. But just as the model stands now, I think I’m around 65 in the quarter on a full year basis. But like I said, that does imply the third and the fourth quarter coal sales price per ton in Appalachia quite a bit higher than the second quarter. Is that kind of consistent with what you’re thinking?

Cary Marshall: Yes. Mark, I don’t know what you mean by quite a bit higher. But I think as we look at the second half in Appalachia, we do anticipate it being slightly higher than where we were in the second quarter. Generally speaking, on the Appalachia side as we look at the back half of the year, anywhere from 2% to 4% higher than where we were in the second quarter. It’s kind of as we look at the pricing piece of it related to that particular area where our guidance kind of zeros in on.

Mark Reichman: Okay. And that’s fair…

Joseph Craft: And those are contracts too, Mark. So I mean it’s not like we’re looking at the market and projecting on the domestic side because we’re looking for contract book and what is expected to be delivered on our contract…

Mark Reichman: Yes, it’s pretty firm. It’s pretty firm. At this point, you’ve got good visibility there. And then the second question was just on the G&A. I mean $10 million reduction, I mean, that’s almost 10% of the full year previous guidance. I guess your due guidance would kind of track with the first and the second quarter expenditures. But were there any expenditures that you just – that you were expecting that you decided not to spend? Or what do you attribute to your – lowering your G&A expense guidance?

Cary Marshall: I think really when you get into G&A, it’s just looking at what full year results and the impact that we had in terms of the full year results are anticipated and what that impact works back to on the G&A side.

Mark Reichman: So kind of made you adjusted it based on kind of your first half spending and that, like I said, that kind of tracks with the new full year guidance in terms of around $80 million. But Okay. Well, that was – I mean $10 million was pretty significant relative to the previous guidance. And then just lastly, and I think this kind of goes to Nathan’s question earlier, that was a good one. You have very strong free cash flow, roughly what, about $140 million, $139 million, very strong coverage on the dividend. So just basically kind of how are you kind of thinking about capital allocation? I know you took down some debt recently. So just kind of your overall view on do you think you’ll get more active on the acquisition front? Or just how are you kind of thinking about managing the cash flow that you’re generating?

Joseph Craft: Yes. So I think as we’ve indicated previously, we plan to sustain our distribution at the $0.70 a quarter. Secondly, we will provide the capital necessary to maintain our cooperations plus the growth projects that we previously announced. So CapEx will be what is guided, and maybe a little lower. But right within those ranges, maybe at the low end, I can’t precisely tell it’s all timing. The commitments are pretty much there. Oil and gas, we talk to. And so the balance then gets to debt paydown, which Cary mentioned, it is poorly in his prepared remarks that we will look to continue to pay off those senior notes. And then we’ve got these investment opportunities, primarily in the New Venture space that we are looking at.

And if you go back to a year ago, I talked in terms of two different ways we could look at investments. One was to how we would think about just good investments that would give us visibility into various areas that we could determine how to make investments in those assets that could actually be long-term cash flow vehicles. And that fifth vertical was in those type of asset investments. I think we sort of matured based off of the 2 years of an investment philosophy. I think we’ve zeroed in with the experience we’ve had to focus on some businesses that we – yes, we still may invest in a minority position in some growth businesses. But when we do that, it’s definitely going to be in conjunction with the opportunity to invest more alongside those particular businesses or those types of industries where we can, in fact, start building businesses for the long term.

And we’re, again, focused in the battery area. We just think that with the increased demand in electricity that battery storage, both for the electrical sector as well as the industrial sector is going to be an area of huge demand. So we’re focused on that area and seeing how we can participate in that. The investment sizes we typically made are anywhere from $25 million to $50 million per investment to make it sizable enough that we see opportunity to make a good return and have those strategic relationships. But not so much that we are ending up focusing on one or two investments, but we’ll have the opportunity to have several so that we’ve got opportunities to be able to grow our company over the next 5 to 10 years. So we’re – as I mentioned in my prepared comments, we’re encouraged by what we’re seeing.

And I think, and hopefully, by the next earnings call, we’ll be able to give you more specifics on specific investments that hopefully will be successful and making some commitments by that time frame, but we’re not in a position to talk about those right now.

Mark Reichman: That’s very helpful. I really do appreciate it. Thank you so much.

Joseph Craft: The other thing I would just say that we’re looking – we’re hoping to find some opportunities to invest in businesses that will allow us to bring on more debt capacity as well. So these would be cash flow generating type businesses so that it would allow for additional debt capacity additions as we look into 2024.

Mark Reichman: Well, thank you very much.

Operator: Our next question is from Dave Storms with Stonegate Capital Market. Please proceed.

Dave Storms: Good morning.

Joseph Craft: Good morning, Dave.

Dave Storms: Just want to start. You mentioned in your prepared remarks on some cost savings measures that you’ve started. Just wondering if you could give us a little more color on what that looks like.

Joseph Craft: Everything goes back to efficiency. That’s the main valuation trying to determine where the most efficient mine plan is, obviously, everything needs to try to staff ourselves to be able to operate at full capacity for what we’ve got invested by cutting back some of that production. We have to decide how we do allocate that. But our guys are focused on that. I think supply chain is an area that last year we were needing to buy more supply than we actually needed just to ensure that we had materials and supplies. I think that has allowed us to – with the years – over the last year, the supply chain has improved. So that’s allowed for some small reduction in expenses, but it really just gets back to productivity. In large part, what we’re seeing in the second quarter was just the productivity at Tunnel Ridge by not having the longwall moves. So productivity is the key to cost in most cases, and that’s definitely true for us.

Dave Storms: Very helpful. And you just kind of touched on it with staffing of full capacity. It sounds like you’re reallocating some of your ships. Is there any threat of losing labor, especially in this tight labor market as you move people around?

Joseph Craft: We have had a little transit or a little bit some people that have left, but no. We’re trying to maintain our head count. And so far, we’ve been able to do that. And again, that’s why we’re repositioning to some areas, it may not be as productive in the short term, but will allow us to be more productive once we get through a couple of these construction projects. We’ve got the one at River View and the extended longwall move at Mettiki is another example, where we’re moving into a new area in the new area that we’re moving into have longer panels. So our development has been needing to catch up with the length of the panels that we’re moving to. And we could have designed that differently. But given where the market is, we felt like this was a great opportunity just to go ahead and go for the longer panels.

And – so that will reduce our production in the short term, but positioning ourselves for next year should give us a lower cost future there than what we would otherwise have with a shorter panel. So – but from a headcount basis, we’re maintaining our headcount, but it is targeted more to the 36 million ton production level compared to. When we started the year, we were targeting 38 last quarter, we went to 37. Now we’re at 36. So we’re – labor is still tight, but we’re able to maintain at this level and the attrition has slowed down over the last 3 months or so to where we can – we feel like we can maintain this level.

Dave Storms: That’s great color. Thank you. One more, if I could. Just any comments you have around the new customer acquisition environment, given that coal prices have started to stabilize a little bit, inflation started to moderate. Is any of that helping you drive new customer acquisitions?

Joseph Craft: I wouldn’t say new customer acquisitions. I mean we’ve been in this business quite a while. So we sell to most of those that want to be around for the next 15 years, which is what we’ve targeted. We have had some conversations where we’re hopeful that we could pick up some market share. But we’ll have more to know as we go through these solicitations whether that happens or not. But – as I mentioned earlier, we’re very confident that we will be able to maintain at this level, if not grow our domestic book beyond the 36 – beyond $30 million, and it allows us to stay at the $36 million. And then that then we’ll have to decide whether we want to pull back the international side or we’ll try to grow production a little bit. But right now, I’d say domestically, we’re targeted on the $30 million a year run rate for the next 5 years or so and hope that we can sustain that and believe we can.

Dave Storms: Understood. Thank you very much.

Operator: Our next question is from David Marsh with Singular Research. Please proceed.

David Marsh: Hi, good morning. Thanks, guys for taking the question. Just wanted to touch on the notes real quickly. Are they continuously callable at this point at par [ph] And what are your – what are the parameters around calling those in? Is it 30 days notice?

Joseph Craft: Yes. To answer your question on that, David, yes, they are callable at par any time. And like you said, it’s just a 30-day – generally a 30-day notice period that we are required to provide in order to call those.

David Marsh: Got it. And so obviously, interest expense is down a good bit in the quarter. I expect in part here to the partial call, should we expect that to continue to decline as you continue to work those off? And can you kind of put some – maybe put some brackets around that in terms of how quickly that continues to come down?

Joseph Craft: I think as it relates to the senior notes, the current expectation, we’ll continue to call those, as I mentioned in my prepared remarks on a consistent basis. The current stock price process right now is to do something similar to what we have been doing here in the most recent quarter. That’s obviously up for conversation at each time that we make that decision to call. But I think a consistent quarterly call would be a good assumption to me.

David Marsh: Okay. Yes, that’s really helpful. And that’s for use of cash flow. I definitely think in this environment, it’s awfully tough to consider refinancing themselves. Just shifting gears a little bit. One thing I noticed is that on the oil and gas side, your BOE sold has really grown really nicely, very nicely year-over-year. I mean, it’s up 50% year-over-year. So clearly, these investments that you guys have been making are paying dividends. And obviously, oil is starting to climb back up a little bit, or the 80s here. I know that the mix for you guys is a little bit gassy. But could you just talk about directionally how does that change? How does that change the game for you guys in terms of evaluating acquisition opportunities as well, just as oil continues to creep back up. And what do we need to see on the nat gas side for you guys to get kind of better price realization maybe closer to the back half of last year type levels?

Joseph Craft: I think on the – right now, the guidance we’ve given in this release did not factor in the most recent uptick in oil prices. I think that as we look at acquisitions, we continue to be focused in the Permian. And as we think about the Delaware is a little bit more gassy, but I think most of our acquisitions most recently have been more oil-based. We still have our mid-composition, but we’re still bullish on gas too. I think our focus on the royalty side will continue to be consistent with what we’ve been doing and really target the Permian primarily, but we will look at all basins and all opportunities. So I think that we have not changed our underwriting standards, and we are seeing some good deal flow. So both for small and direct investments, and there’s still some packages out there that we’ll continue to evaluate.

David Marsh: Got it. Thank you, guys very much for the color. I appreciate it. I’ll leave to the next call.

Operator: Our next question is from Arthur Calavritinos with ANC Capital. Please proceed

Arthur Calavritinos: Hey, guys. Good morning. Thanks for taking my question. Just a couple of things. On the financing question, Cary, are there any minimum bite sizes when you guys call the senior notes?

Cary Marshall: No, there no – there’s no minimum bite sizes. It’s really, really up to us whenever we call them to designate what amount that we are calling. They’re callable on a pro rata basis. So whatever amount we designate its pro rata basis back out to the holders of those notes. But if we wanted to do $10 million, we could do that, we just opted to do $50 million in this last quarter.

Arthur Calavritinos: And it probably depends on how you’re feeling where the cash is going to be at the end of the month or the quarter, whatever, right, how you decide this? It seems like you’re matching it with your cash flows, like the way I look at it. Or I mean was that…

Cary Marshall: That’s right. Yes, that’s correct. And future opportunities for cash flow.

Arthur Calavritinos: Got it. All right. And then the second thing away from the finance question is I got the Elon Musk this morning on the PG&E conference. And the question was, when he was talking about electric demand, a few weeks ago, like the auto sales were like 3 point – I’m sorry, 7% like were electric cars. And I’m starting to think like at what point do we get with the electric cars in this country where we can almost point to this is how much EV [ph] or how much coal demand is feeding the fleet. I mean it seems it’s kind of early, but it’s – but I was shocked at that 7% number for new car sales. Any color on that you could shed where we go because it’s almost displacement, right? We’re displacing unleaded gasoline with coal to power transportation, but it’s early days. But any color on that would be great.

Joseph Craft: Yes. So with the EV space, I mean, the big issue that most – like two or three different factors. One is just the cost of the EV. And what we have seen is mostly OEMs have reduced their pricing by $10,000 per vehicle or so to try to stimulate the demand and really try to get market share because you’re starting to see many more models come out. The second factor gets into the – well, they call a range anxiety. And so there’s been a couple of announcements that have come out since our last call. One is with Tesla, where they’re going to open their network and have partnered with GM and Ford, I believe, and that’s going to roll out over the next 2 years. So that’s not immediate, but it’s going to roll out over ’24, ’25 and be fully operational, I think, by ’26.

Then you’ve seen another announcement by numerous of the other manufacturers from – from the European manufacturers primarily coming together and talking about building out their own network. On top of the $5 billion NEVI program that the government has put in place, and we’re starting to see finally the states starting to go out and bid for those projects. So I would say over the next 1.5 years to 2 years, you’re going to see a pretty robust network of charging stations on the highways that should give customers a safe feeling on the ability to have range anxiety eliminated to where it would support the purchases of more EVs. I think the commitment, not only by the OEMs, but all these governors around the battery belt to build these out. The third factor I didn’t mention is back to the tax credit, the $7,500 tax credit per vehicle, which also then requires a certain percentage of the auto to be manufactured in America and/or the battery materials being sourced or manufacturer or some type of assembly in America.

And that’s an area that is constantly being discussed. I think that this administration has – when they’ve adopted regulations expand that opportunity to make sure the $7,500 credits are available. And so the price point seems to be competitive with the combustion engine. How fast that goes is anybody’s guess. But I think when we look at our new ventures area and we look at investments in the battery space, all these manufacturing facilities are talking about at least 50 megawatts, sometimes 250 megawatts of somewhere in between for every manufacturing facility that you hear announced. And that’s a significant load compared to historic when business economic development officers are out looking for projects to move to States in the past. 5,000 megawatts would be high, much less 50 to 100 to 200.

So we’re looking at major sinks. And not only are they large loads, but they want to be continuous. They do not want to have interruptible rates. And we’re starting to see capacity concerns, and that’s why you hear Perk [ph] and all these guys saying we better pay attention to the speed of this transition because you can’t continue to close plants and build plants and add no new capacity. So I think that demand for electricity has definitely gone up. I think, as I said earlier, it seems to be underappreciated at what that speed is going to be. And back to your question of when can we actually see that and see that roll through? I think it will be within the next 2 years. In my conversations, when I go out and speak to people, I’ve been saying to everybody, just think about how many people have a graduation in their family this year, whether it’s college or high school or candor carton [ph] or whatever and just say, how fast did that 4 years go by.

It goes buying a flash. So we, as public policymakers and investors, we have to recognize we’re making decisions right now that are going to determine the answer to your question. And so we don’t have time just to delay and just think business as usual. We have to really gear up in anticipation of this significant growth in electricity demand. And therefore, it’s time to – for policymakers to come to the table and realize that if we’re going to have reliable, low-cost energy we can’t do business as usual. We have to factor in this demand growth, and that’s why I have confidence that they’re going to start thinking in terms of deferring some of these closures because if we’re going to meet that demand, you have to have electricity. It’s bottom line.

I want to electrify America, he’s got to have electricity to do it. And we all know that the renewables are just – you cannot look at a renewable installation that’s adding capacity because we still don’t have battery storage to a level that is dependable. So you really have to look at base load plants, and those are fossil plants in your nuclear fleet. So – and it’s hard to answer your question precisely. But directionally, I would say within 2 years, you’ll have a better idea of exactly what that demand load is for – I’m focused on the Eastern United States. So for the areas where we market, I think we’ll have a very good idea about 2025 exactly what that demand load needs to be and therefore, what capacity we have to have to provide for reliable energy.

Arthur Calavritinos: Yes. And it’s interesting. A couple of weeks ago, Barons [ph] who had a cover story in Siemens, the big German equivalent of GE, having enormous problems optimizing wind power, wind mills, and these are great engineers. So the win may fall far short of what’s like what’s boiler played on a wind mill to deliver electrons. So just – it seems like it’s happening in slow motion, when we find out. So – all right. And then on the Permian, there’s a large royalty company, public loan. I don’t know they’re having a proxy fight whatever, right? So I don’t know if they’re getting delayed in buying stuff. But there – are there more opportunities than normal for these oil and gas royalties in the Permian because it seems like there’s some dysfunction in some of the M&A going on?

Joseph Craft: I would not say there’s any more than normal. So going – starting last year, as you saw some of the price decline, it got sticky, nobody was wanting to sell at those prices. But then after you start adjusting to what might be the new normal. So there’s adequate deal flow for us to maintain our policy to think in terms of investing $100 million a year. And that’s the way I would look at it from our lens and our perspective without modifying our underwriting standards. So as one of the earlier callers said, I mean, our returns have been very good. We’ve been able to hit our targets as we think about the investments we’ve made and – and I think our guys have done a very good job of trying to assess the pace of drilling.

And you can read a lot of stuff. But I think in the Permian, they’re going to continue producing at the same level for several years to come. So as a royalty owner, we feel like it’s a great investment for us to be complementary for our cash flow purposes as we look to where we want to be in 2030.

Arthur Calavritinos: And you’re the right size, not like an Exxon where you’re like too big where it doesn’t make a difference. You’re – and you’re not too small. You got a good size then, right? I mean, go in…

Joseph Craft: We think so. Yes.

Arthur Calavritinos: Okay, great. Thank you very much for taking my questions. Thank you.

Joseph Craft: Thank you.

Operator: We have reached the end of our question-and-answer session. I would like to turn the conference back over to Cary for closing comments.

Cary Marshall: Thank you, operator. And to everyone on the call, we appreciate your time this morning as well and also your continued support and interest in Alliance. Our next call to discuss our third quarter 2023 financial and operating results is currently expected to occur in late October, and we hope everyone will join us again at that time. This concludes our call for the day. Thank you.

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