Operator: Good day and welcome to the Black Stone Minerals Fourth Quarter and Year End Earnings Call. [Operator Instructions] I’d now like to turn the call over to Mark Meaux, Director of Finance. Please go ahead.

Mark Meaux: Thank you. Good morning to everyone. Thank you for joining us either by phone or online for Black Stone Minerals fourth quarter and full year 2023 earnings conference call. Today’s call is being recorded and will be available on our website along with the earnings release, which was issued last night. Before we start, I’d like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risks that may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements. For a discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday and the risk factors section of our 2023 10-K that we expect to file later today.

Aerial view of an oil and gas field, with tanker trucks in the foreground.

We may refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliation of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday, which can be found on our website at www.blackstoneminerals.com. Joining me on the call from the company are Tom Carter, Chairman, CEO and President; Evan Kiefer, Senior Vice President, Chief Financial Officer and Treasurer; Carrie Clark, Senior Vice President, Land and Commercial; and Steve Putman, Senior Vice President and General Counsel. I’ll now turn the call over to Tom.

Tom Carter: Good morning to everyone on the call, and thank you for joining us today to discuss our fourth quarter and full year ‘23 results. We posted strong results with adjusted EBITDA of $125.5 million for the quarter, bringing us to $474.7 million in 2023. We generated total production volumes for the fourth quarter of 41,400 BOE per day, 2% above the upper end of our full year guidance range. Royalty volumes for the quarter were 38,900 BOE, where we saw oil volumes trend down in the Bakken and Eagle Ford, but were offset by an increase in Mid/Del. We also saw a modest decrease in natural gas volumes, primarily in the Louisiana Haynesville conforming with natural gas trends in our industry. Yes, we see the glass as half full.

Today, 39 wells have been turned to sales in the Shelby Trough under our development agreements with Aethon. We announced in December that Aethon elected to use a time-out provision in our development agreement that specifies that when prices fall below a certain threshold, they may elect to temporarily suspend contractually obligated drilling on our acreage. At this time, we do not expect the time-out will impact the next 12-month cycle for the drilling and completion of Aethon-operated wells that were spud prior to the time-out. And in fact, Aethon has indicated they may drill additional wells during the time-out period and have actually begun operations on several. We are working closely with Aethon to determine the effects of the time-out as we focus on longer-term expectations for production in 2025.

We had 63 rigs running on our acreage at the end of the quarter, representing approximately 10% of the U.S. rig count and a reduction of 13 rigs compared to the third quarter. Like most in our business, we are seeing general slowdown in drilling in the Haynesville and Gulf Coast as a response to lower natural gas prices. With oil prices remaining around the $70 per barrel range, we did see a small increase in Midland Delaware and the Bakken play trends. We previously announced that we were maintaining our $0.475 per unit for the last quarter or $1.90 on an annualized basis, which, as reported yesterday, represents 1.19x coverage for the quarter. Despite the challenges with natural gas prices, we’ve been able to maintain a strong balance sheet throughout the year and hold distribution at its highest level since going public.

Due to the suppressed price environment, we may be in a position where at current distribution rates, we could fall below 1x coverage, something we likely would not let stand implying a possible reduced distribution until pricing recoveries. In 2022, we mentioned that we expected to grow production through ‘23 with a target exit rate close to 40,000 BOE per day, and we’re able to execute and exceed those expectations. As we enter 2024, there are headwinds. Due to – but due to the quality of our acreage and no debt on our balance sheet, we adjusted our commercial efforts to be proactive in a down cycle and have included targeted mineral and royalty acquisitions that complement our existing acreage position. In 2023, we acquired non-producing minerals and royalties totaling $15 million.

Our strategy in ‘24 includes a continuation of targeted acquisitions that support our commercial initiatives and provide long-term accretive growth to our unitholders. Overall, it’s a strong quarter. And despite challenging commodity price environment, we remain encouraged by the long-term natural gas outlook as we continue to make progress on strategic initiatives in ‘24 and beyond. With that, I’ll turn it over to Evan.

Evan Kiefer: Thank you, Tom, and good morning, everyone. As Tom pointed out, we had a very good fourth quarter where we reported average daily production of 41,100 BOE per day. For the full year, we generated $474.7 million of adjusted EBITDA from 39,800 BOE per day, which is just above the high end of our full year guidance range. In conjunction with the earnings release, we put out our 2024 guidance yesterday. And as we look forward to the full year 2024, we forecast annual production to be up slightly from 2023 levels. As Tom mentioned in the Shelby Trough, Aethon has indicated their intentions to turn in line in 2024 the wells that have been spud prior to the time-out provision, and we’re working very closely with them to determine the long-term impact on future production volumes.

We expect a modest increase in volumes in the East Texas Austin Chalk where we now have 30 new generation, multistage completion wells that are currently producing as we are working with our operating partners in the area to accelerate activity. Our Permian position is broadly expected to remain in-line with 2023 levels as operators continue to focus on capital discipline, but is offset by an expected decline in the Bakken as that play continues to mature. On the heels of a robust 2022 and 2023, we expect a slowdown in Louisiana Haynesville in response to lower natural gas prices as evidenced by a recent announcement of rig cuts as well as some natural production declines on our acreage outside of these 4 plays. Lease bonus and other income was $3.8 million for the fourth quarter and $12.5 million for the full year.

The fourth quarter included leasing from primarily in the Haynesville, the Granite Wash and Gulf Coast, but we remain encouraged by continued activity in these plays despite the lower price environment. We expect lease bonus, operating expenses, production costs for 2024 to be in-line with 2023 levels. G&A is expected to increase slightly in 2024 as a result of inflationary costs and our continued efforts to support our ability to evaluate, market and manage our undeveloped acreage positions to potential operators. In 2023, Henry Hub averaged $2.74 per MMBtu while our natural gas hedges had a strike price of over $5 per MMBtu which provided over $80 million of realized hedge gains for the year. In 2024, we see those levels move lower to $3.55 per MMBtu while our oil hedges are currently just above $71 per barrel.

We are in our normal range of hedging approximately 60% to 70% plus of expected volumes for the rest of the year. That will continue to provide support to our cash flows for 2024 due to the recent pullback in pricing. With the previously announced fourth quarter distribution, we will pay out total distributions of $1.90 per unit for 2023, which represents a 9% increase over 2022. Distributable cash flow for the quarter was $119.1 million and results in distribution coverage for the fourth quarter of 1.19x and 1.13x for the full year. That allowed us to fully pay off the debt at the end of 2022 and remain at a zero debt balance throughout the year. We currently have $103 million of cash in advance of paying the fourth quarter distribution. So now moving on from the common units to the preferred.

As we have discussed on prior calls, we have the option to redeem our outstanding preferred units at 105% of par or $21.41 per unit through February 26, 2024 or next week. We have not redeemed and do not expect to redeem any units before the redemption window closes, which will not reopen for 2 years until November of 2025 at a redemption price of 100% of par or $20.39 per unit. The rate on the preferred units reset in November of 2023 from 7% to the 10-year treasury plus 550 basis points or 9.8%. As you recall, we also put in place a $150 million unit repurchase program in October of 2023. This gives us the flexibility to opportunistically buy our common units, which currently trade at a discount to the preferred units redemption price. Given the low natural gas environment today and the liquefied natural gas export capacity expected to increase going into 2025 and beyond, we remain bullish on our long-term gas exposure and unit price.

And so with that, I will turn the call open for questions.

Operator: Thank you. [Operator Instructions] We will go first to Tim Rezvan with KeyBanc.

Tim Rezvan: Thank you for taking my questions, folks. I wanted to start on the comments. You mentioned expanding your growth strategy into buying minerals in the Gulf Coast. The $15 million is relatively small relative to some acquisitions that your public peers have had made in the last couple of years. I was wondering, if you could expand a bit on this growth strategy. How big are you willing to go? And then if you could talk – you mentioned the Gulf Coast, they are non-producing, can you talk specifically where that is and your line of sight on production from that area?

Tom Carter: Thanks for the question, Tim. I will be – this is Tom. I will be glad to answer that as follows. We do – we acknowledge that $15 million is not a needle mover for Black Stone. And we do expect to continue those efforts and substantially expand upon that number maybe ten-fold. And with respect to the type of acquisitions and where those are, I don’t want to say too much because of competitive reasons. But suffice it to say that our goals here are to buy properties that are not already well overpriced like in the Permian so that our capital will have better running room and can be accretive to our production profile.

Tim Rezvan: Okay. So, it’s fair to think of this as maybe a third leg on the growth stool in addition to the Chalk and the Haynesville agreements?

Tom Carter: Well, I would tell you that typically speaking, we are expanding areas where we are already in place. So, it’s probably more expansive of things that we already own than adding new plays.

Tim Rezvan: Okay. I appreciate those details. And then I appreciate Evan’s comments about not redeeming the preferred. It would make sense of where prices are today. How are you thinking about that repurchase program? You intentionally put that in the release. And I am just trying to understand the difference between with that cash on hand you are repurchasing shares in weakness versus maybe maintaining – you seem to indicate you don’t want to maintain that $0.475 per unit if it’s over 100% of your cash flow. Just trying to think how you are thinking about uses of cash, given you have no debt between the repurchases and distributions in 2024.

Evan Kiefer: Yes, Tim, this is Evan. As we think about overall cash and kind of our debt balances as well, we don’t really like the idea of going below 1x coverage for a period of time and effectively having to borrow to support the distribution. That said, we also see value in our units over a long-term and see that there could be accretion to repurchasing those units at where we are at today at lower gas prices, especially compared to the $21 on the preferred. And so overall, we feel more comfortable using some of the revolver as it exists to be able to repurchase our common units as opposed to supporting a distribution level that would require coverage to be less than 1x.

Tim Rezvan: Okay. So, I guess we will just stay tuned and see if you start that program with repurchases.

Evan Kiefer: Yes, that’s correct. It’s something that with the current environment, we think it makes sense and something where we have the opportunity to utilize kind of throughout the year and expect more on that to come.

Tim Rezvan: Thanks. I appreciate the detail. I will hop back in the queue. Thank you.

Evan Kiefer: Thank you.

Operator: We will go next to Derrick Whitfield with Stifel.

Derrick Whitfield: Hi. Good morning all and congrats on the strong year-end.

Tom Carter: Good morning Derrick.

Derrick Whitfield: And my first question, I wanted to focus on your 2024 guidance. With the lower gas prices we are observing at present, how are you thinking about the conversion of the Aethon DUCs to production in your guidance, meaning are you expecting uniform cadence across the quarters or more second half weighted activity?

Tom Carter: Yes, Derrick, great question. So, overall, based off our conversations with Aethon and the existing DUCs, we do expect those to come online as they provided their – as you would expect with multi-pad completions, it becomes a little bit lumpy as multiple wells are going to and expected to come online at the same time. What that’s going to do is you will likely see some earlier on in the year, call it, the first quarter and second quarter and then a little bit more towards the end of the year based off the current expectations that they have provided to us.

Derrick Whitfield: So, lumpy, but relatively uniform across the year, is that a fair characterization?

Tom Carter: Yes.

Derrick Whitfield: Okay. And then shifting over to the competitive landscape, we have seen considerable M&A across the upstream sector over the last 2 years that only limited amounts of activity in the mineral subsector. With that said, what are your thoughts on the impact E&P consolidation could have on your business, namely Chesapeake, Southwestern, and if you are expecting to see greater consolidation within the minerals sector?

Evan Kiefer: Yes. So, this is Evan. And I will kind of hit on the operator consolidation first. And I think overall, consolidation within the industry on the operator side could be beneficial. I think specifically thinking about comps or thinking about the Southwestern deal, there is benefits that can be gained through operator efficiencies, costs and everything that I think will trickle down best of the benefit on the mineral owner side as additional development could persist. Now, on the other side of that, there is capital discipline, and I know Diamondback with Endeavor has indicated possibly rig cuts and maybe a little bit more to what I was seeing to be a flatter production. So, I think overall, we are still kind of waiting to see how everything ultimately transacts and how that kind of post-transaction world looks.

But I think at a reasonable level, it’s probably neutral on the moderate-to-low growth story, particularly in the Permian and overall kind of efficiencies to be gained on the gas side, particularly on the Haynesville piece.

Derrick Whitfield: And just on more of the minerals consolidation side of the equation, what are your thoughts on that?

Carrie Clark: This is Carrie Clark. Thanks for the question. I think on – in the mineral space, just on a relative basis, of course, they are a much smaller pool, but there has been some significant consolidation over the last couple of years, just off the top of my head, the Sitio-Brigham transaction from last year. And to touch back a bit about on the operator consolidation and its impact to us, we are always monitoring as the – as these deals come about, what the specific impact is to us and trying to quantify that. And I think for the Chesapeake and SWN consolidation that we don’t expect a material impact to us from – based on that transaction. But of course, as I have said, again, we are always looking at those operator consolidations and understand that capital can shift from priority projects for one company and as they form a different company that could shift around, and that’s what we are monitoring on that front.

I don’t – as far as the outlook on mineral consolidation, there is nothing out there that we see at this point that we are anticipating. So, I think that’s all we really have to share on that is just we are kind of seeing the same thing that you all might be seeing in the market.

Derrick Whitfield: Terrific. Thanks for the added color.

Carrie Clark: Sure.

Operator: At this time, I would like to turn the call back over to Tom Carter for any closing comments or additional remarks.

Tom Carter: Well, thank you all for joining the call today and we look forward to speaking with you again in 90 days or so.

Operator: Once again, ladies and gentlemen, that does conclude today’s call. Thank you for your participation. You may disconnect at this time.

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Q4 2023

Earnings Transcript

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