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Operator
Good day and welcome to the Blackstone Minerals fourth quarter and year-end earnings call. At this time, all participants are in a listen-only mode. Later, there will be a question and answer session. You may queue for a question at any time by pressing the star key followed by the number one on your telephone keypad. Please be advised that today's conference is being recorded. If you require operator assistance, please press star zero. I'd now like to turn the call over to Mark Moe, Director of Finance. Please go ahead.
Mark Moe
Thank you. Good morning to everyone. Thank you for joining us either by phone or online for Blackstone 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 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. 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 measure 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 Keefer, Senior Vice President, Chief Financial Officer and Treasurer, Terry 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 41.4 thousand BOE per day, 2% above the upper end of our full-year guidance range. Royalty volumes for the quarter were 38.9 thousand BOE, where we saw oil volumes trend down in the Bakken and Eagle Ford, but were offset by an increase in Midland Dell. We also saw a modest decrease in natural gas volumes, primarily in Louisiana Hainesville, conforming with natural gas trends in our industry. Yet we see the glass is half full. To date, 39 wells have been turned to sales in the Shelby Trough under our development agreements with ATHON. We announced in December that Athon elected to use a timeout 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 a timeout. uh will impact the next 12-month cycle for the drilling and completion of aethon operated wells that were spud prior to the timeout and in fact aethon has indicated they may drill additional wells during the timeout period and have actually begun operations on several we are working closely with aethon to determine the effects of the timeout 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 47.5 cents per unit for the last quarter, or $1.90 on an annualized basis. which, as reported yesterday, represents 1.19 times 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 distributions 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 one times 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 were able to execute and exceed those expectations. As we enter 2024, there are headwinds. 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 unit overall. 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.
Bakken
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 41.1 thousand DOE per day. For the full year, we generated 474.7 million of adjusted EBITDA from 39.8 thousand DOE 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 of 2024, we forecast annual production to be up slightly from 2023 levels. As Tom mentioned in the Shelby trough, ASON has indicated their intentions to turn in line in 2024 the wells that have been spud prior to the timeout 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 multi-stage 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 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 Hainesville 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 four states. 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 revenues from primarily in the Hainesville, the Granite Wash, and Gulf Coast, but we remain encouraged by continued activity in these places 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 MMVCU, 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 1.19 times and 1.13 times 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 in 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 26th of 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 two 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 unit's 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. At this time, if you would like to ask a question, you may do so by pressing the star 1 on your telephone keypad. If you find that your question has been answered, you may remove yourself from the queue at any time by pressing star two. Once again, that is star one to ask a question and star two to remove yourself. We will pause for just a moment to assemble the question queue. We'll go first to Tim Rezvan with KeyBank.
Tim Rezvan
Thank you for taking my questions, folks. I want 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 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're 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. This is Tom. I'll be glad to answer that as follows. We do acknowledge that $15 million is not a needle mover for Blackstone, and we do expect to continue those efforts and substantially expand upon that number maybe tenfold. 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 uh 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 okay so it's fair to think of this as maybe a third leg on the growth stool you know in addition to the chalk and haynesville agreements Well, I would tell you that typically speaking, we are expanding areas where we're already in place. So it's probably more expansive of things that we already own than adding new plates. Okay.
Tim Rezvan
Okay. I appreciate those details. And then I appreciated Evan's comments about you know, not the redeeming the preferred. It makes sense that where prices are today. How are you thinking about that repurchase program? You know, you intentionally put that into release. And I'm just trying to understand the difference between with that cash on hands, you're repurchasing shares, you know, in weakness versus maybe maintaining. You seem to indicate you don't want to maintain that 47.5 cents per unit if it's over 100%.
Bakken
know of your cash flow just trying to think how you're thinking about uses of cash given you have no debt you know between the repurchases and distributions in 2024 yes and this is evan you know as we think about you know overall cash and kind of our debt balances as well you know we don't really like the idea of going below one-time 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're at today at lower gas prices, especially compared to the $21 on the preferred. 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 be less than one time okay so i guess we'll just stay tuned and see if you start that program with repurchases yeah that's correct uh you know it's something that you know with the current environment we think it makes sense and something where we have the opportunity to to utilize kind of throughout the year and expect, you know, more on that to come.
Tim Rezvan
I appreciate the details. I'll hop back into the queue. Thank you.
Bakken
Thank you.
Operator
We'll go next to Derek Whitfield with Stiefel.
Derek Whitfield
Good morning, all, and congrats on a strong year end. Good morning, Derek. My first question, I wanted to focus on your 2024 guidance with the lower gas prices we're observing at present. How are you thinking about the conversion of the Atheon ducts to production in your guidance, meaning are you expecting uniform cadence across the quarters or more second-half-weighted activity?
Bakken
Yes, Derek, and great question. So overall, you know, Based off our conversations with Athon and the existing ducts, we do expect those to come online as they provided. 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'll likely see – some earlier on in the year call it the first and second quarter and then a little bit more towards the end of the year um based off the the current expectations that they have provided to us so lumpy but relatively uniform across the year is that a fair characterization yes okay and then shifting over to the competitive landscape
Derek Whitfield
We've seen considerable M&A across the upstream sector over the last two years, but 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're expecting to see greater consolidation within the mineral sector?
Bakken
Yeah, so this is Evan, and I'll kind of hit on the operator consolidation first. And, you know, I think overall consolidation within the industry and the operator side could be I think, you know, specifically thinking about Comps or thinking about the Southwestern deal, you know, there's benefits that can be gained through, you know, operator efficiency costs and everything that I think will trickle down and such a benefit on the mineral owner side as additional development could happen. persists. Now, on the other side of that, there's capital discipline, and I know Diamondback Endeavor has indicated possibly rig cuts and maybe a little bit more to what I would assume is going to be flatter production. So, I think overall, you know, we're still kind of waiting to see how everything ultimately transactions and how that kind of post-transaction world looks, but I think a reasonable level is probably neutral on the, you know, moderate to low growth story, particularly in the Permian and, you know, overall kind of efficiencies to be gained on the gas side, particularly on the Hainesville piece.
Derek Whitfield
And just on more of the minerals consolidation side of the equation, what are your thoughts on that?
spk01
this is Carrie Clark thanks for this question I think on you know in the mineral space just on a relative basis of course they're much smaller pool but there has been significant consolidation over the last couple of years just off the top of my head the city of Bergen transaction from last year it's a touch back a bit on the operator consolidation and its impact to us. We're always monitoring as the, you know, as these deals come about, what the specific impact is to us and trying to quantify that. And I think for the, you know, the Chesapeake and Swinn consolidation that we don't expect a material impact to us based on that transaction. But of course, you know, As I said, again, we're 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 can shift around. And that's what we are monitoring on that front. I don't – as far as outlook on mineral consolidation, there's nothing – you know, out there that we see at this point that we're anticipating. But so I think that's all we really have to share on that is just we're kind of seeing the same things that y'all might be seeing in the market.
Derek Whitfield
Ricky, thanks for the added color.
spk01
Sure.
Operator
At this time, I'd 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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