Black Stone Minerals - Q2 2023

Transcript

Operator (participant)

Good day everyone and welcome to today's Blackstone Minerals Q2 Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, you will have the opportunity to ask questions during the question and answer session. You may register to ask a question at any time by pressing star one on your touchtone phone. You may withdraw yourself from the queue by pressing star two. Please note, this call may be recorded. I will be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Mark Meaux, Director of Finance. Please go ahead.

Mark Meaux (Director of Finance)

Thank you. Good morning to everyone. Thank you for joining us, either by phone or online, for Blackstone Minerals' Q2 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 2022 10-K.

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 and CEO; Evan Kiefer, Interim Chief Financial Officer and Treasurer; Carrie Clark, Senior Vice President, Land and Commercial; Garrett Gremillion, Vice President of Engineering and Geology; and Thad Montgomery, Vice President, Land. I'll now turn the call over to Tom.

Tom Carter (Chairman and CEO)

Thank you, Mark. Good morning to everyone on the call, thank you for joining us today to discuss our Q2 of 2023. We posted a solid quarter with adjusted EBITDA of $109 million for the Q2, in line with the Q1 results. This is the fifth consecutive quarter where Black Stone Minerals has generated over $100 million of adjusted EBITDA. Despite the pullback in natural gas prices and production, our hedge portfolio performed as it was intended to help insulate our cash flow from significant price movements. We generated total production volumes for the quarter of 36.2 thousand BOE per day, a decrease of 8% from the Q1 volumes. Royalty volumes decreased 9% from last quarter to 33.6 thousand BOE per day, 11% above the Q2 of 2022.

The primary driver was reduced gas volumes in Louisiana Haynesville, and we saw the natural decline as we saw the natural decline of several high interest, high initial production rate wells that came online in the H2 of 2022. Oil volumes moved up in the quarter as well due to new development activity in the pocket. Aethon continues to ramp up production in the Shelby Trough and held the 5 rigs on location from the Q1 into the Q2, and is expected to meet the minimum pace of 27 wells per year by the end of the year in Angelina and San Augustine counties.

To date, 22 wells have been turned to sales in the Shelby Trough under our development agreement with Aethon, and 27 are in various stages of drilling or completing, that we expect to benefit our production in the H2 of the year. In addition, 26 new generation multi-stage completion wells have been turned to sales in our concentrated acreage position in the East Texas Austin Chalk. We've reached an agreement with an existing operator in the field to drill 10 wells over the next two years, and it's exciting to see continued momentum in the play, and we will keep working to put in place new long-term development deals to further accelerate production on our acreage.

As the U.S. experienced an 11% decrease in rig activity in the Q2, we only saw an 8% decrease in rigs operating on our acreage in that quarter, primarily in the Permian, with 73 rigs currently running as of June 30th. As of yesterday, the rig count was back to 83, an increase driven mainly from the Permian that offset the decreases in the, seen in the Q2. This highlights the normal ebb and flow of rig movement seen on our acreage and the importance of working with our operators, like Aethon, for long-term development agreements, that will help to maintain consistent drilling activity on our high-interest acreage. Last week, we announced our distribution for the Q2 of $0.475 per unit, flat to our Q1 distribution.

We have over $80 million in cash prior to the payment of the distribution and a new high watermark for Black Stone Minerals since going public. We continue to prioritize returning that cash flow to our investors. With that, I'll turn it over to Evan.

Evan Kiefer (Interim CFO and Treasurer)

Thank you, Tom. Good morning to everyone. As Tom mentioned, our royalty volumes for the Q2 totaled 33.6 thousand BOE per day, which was down 9% relative to the Q1. Total production for the quarter was 36.2 thousand BOE per day. Oil prices for the Q2 averaged $73 a barrel. Our realized prices before hedges came in at 99% of WTI prices.

Gas prices at the Henry Hub averaged $2.10 per MMBtu. Our realized prices for the quarter before hedges was at 135% of that amount. The increased gas realizations for the quarter were driven primarily by revenues on new wells with production in the 4th quarter from 2022, where Henry Hub averaged over $6 per MMBtu. For comparison, a year ago, the 2nd quarter of 2022, average prices for gas was $7.17 per MMBtu, which represents a 70% decrease in natural gas prices over the last year. This continues to emphasize the importance of the hedge program we have in place to mitigate the short-term volatility in commodity prices.

In the Q2, our hedges brought in $28.2 million of realized hedge gains, and after hedges, realized prices for oil were over $76 per barrel and $4.50 per MMBtu for gas. On a BOE basis, this represents an increase of over 7% compared to the Q1. Consistent with prior messaging, we have continued our systematic process of adding 2024 hedges throughout the year. Our current strike price for natural gas is over $3.50 per MMBtu, and crude at approximately $69 per barrel. We continue to expect that approximately 70% of our hedged 2024 volumes will be by the end of the year.

We generated adjusted EBITDA of $109.2 million, and distributable cash flow of $103.6 million for the Q2. These are both consistent with the Q1 results. We continue to maintain a very strong balance sheet, and this is the second consecutive quarter where we've had 0 debt outstanding, and currently have over $80 million of cash prior to the distribution later this month. Given the undrawn revolver and cash generated in the quarter, our board of directors has supported maintaining the existing distribution of $0.475 per unit, which translates to 1.04 times coverage for the quarter. Our original guidance for the year had contemplated a slowdown in Louisiana Haynesville as we saw prices pull back and due to natural gas.

In our earnings release yesterday, we maintained our original production guidance of 37,000 to 39,000 BOE per day for the full year. We do expect a slightly gassier production mix for the year compared to the original guidance, and continue seeing growing volumes in the Shelby Trough as Aethon ramps up production that's consistent with our development agreement. Permits on our acreage over the last three quarters has remained consistent, and the rig count rebound in July that Tom mentioned, all helps to offset some of the headwinds of lower natural gas prices seen this year. We continue to be encouraged by activity on our acreage, and we expect to see a modest improvement in production in the H2 of the year, as indicated by our guidance range. With that, I will open it up to questions.

Operator (participant)

At this time, if you would like to ask a question, please press star one on your touchtone phone. You may remove yourself from the queue at any time by pressing star two. Once again, that is star one to ask a question. We will pause for a moment to allow questions to queue. Our first question comes from Tim Rezvan with KeyBanc Capital Markets. Please go ahead.

Tim Rezvan (Managing Director and Equity Research Analyst)

Hey, good morning, folks. Thank you for taking my question. I, I guess I want to follow up on, on your comments, Evan. You, you talked about the guidance in place, but it's getting a little gassier, or I guess you got it to a little gassier skew. Can you walk through what that was? Is it, you know, a little more Haynesville, a little less Austin Chalk than what you thought? Just sort of the, kind of the trajectories of those two, you know, assets as you look to the end of the year.

Evan Kiefer (Interim CFO and Treasurer)

Yeah. Good morning, Tim, and thank you for the question. This is Evan, and I'll take a first stab at that. Yeah, we've seen several things going on this year that just shifted that focus towards the gassier mix. One, we did have a little bit of a pushback in the initial estimates on some wells in the Austin Chalk. We also saw a little bit of a shift from the Permian coming in a little lower than we originally forecasted at the beginning of the year, but also some increased benefit from the Haynesville side that has come in a little bit above estimates for the H1 of the year.

Really kind of a combination of those several things is what's driving the slightly increased gassier mix for the year compared to what we were looking at at the beginning.

Tom Carter (Chairman and CEO)

Evan, can I chime in on that just a little bit? With respect to the Austin Chalk, that play is pretty variable in BOE, liquids volume per 1,000 or 1 million cubic feet of gas, and it ranges from anywhere from 35 to 250 barrels per 1 million. A lot of the drilling that's been being done has been in some of the deeper areas that are more gassy, and we are working hard to see some of the core areas with higher liquids, get drilled, which really, in the highest area, that really hadn't even been developed yet. That's. We may see more liquid volumes coming out of that in the next year.

Tim Rezvan (Managing Director and Equity Research Analyst)

Okay, I appreciate that, that context. Then I wanted to ask on the, the distribution. Obviously, you know, with the balance sheet where it is, you can afford the high payout. Is there a sense that you want to keep some sort of, you know, baseline, that 47.5 number has been intact for 3 straight quarters. You've been at 96% payout for 2 straight quarters. You know, obviously, gas market looks a little better. Do, do you feel like there's a, a need to deliver a, a consistent, you know, quarterly distribution? Kind of what is the board thinking about in, you know, with that same number for 3 straight quarters?

Evan Kiefer (Interim CFO and Treasurer)

Yeah, Tim, this is Evan. I'll, I'll start answering that. So, you know, one being, you know, the Q1 and Q2 did come in fairly close with each other, and almost within, I think, $500,000 on a DCF basis. So one, we, we saw the coverage and, and felt comfortable with where the balance sheet was today to maintain that higher payout ratio. You know, as you mentioned, even going through kind of the remainder of the year, just looking at natural gas, where third quarter we're up to, on the strip today, call it $2.50, which is really just under a 20% increase from what we saw in the Q1. You know, we're we do like maintaining that distribution as best we can.

I think right now there's some momentum, at least on pricing, that does help that through the third quarter and even above that into the fourth quarter with gas prices being closer to $3. Yes, we, we like the ability to maintain that. I, I think with the balance sheet strength and, and the forecast that we're currently looking at for the H2 of the year allows that.

Tim Rezvan (Managing Director and Equity Research Analyst)

Okay. Thanks for that. Then if I could sneak one more in. I'm gonna repeat a question from last quarter. You know, circling back on the preferreds. You know, 4Q is now less than 2 months away. I was curious if there's any update on what management of the board is thinking, you know, with those preferreds and the rate going to kind of a variable rate. Thanks for any color you can provide.

Tom Carter (Chairman and CEO)

Evan, you want to go ahead on that one?

Evan Kiefer (Interim CFO and Treasurer)

Yeah. thanks, Tim. Yeah, it, it's a great question, and it's definitely something, you know, we've been looking at internally. Yes, that, that rate does reset in November of this year, going to 10-year treasury plus 550 basis points. Where we're looking at it, it rates today, that's a little bit north of 9% relative to the, the 7%. Our, our view really hasn't changed too much from the, the last quarter. It, it is something that we're looking at. And, you know, they've been a fantastic partner over the years in maintaining that when we put the preferred in place with the Noble acquisition.

Yes, maybe there's something we can do there, but it, it's, you know, not really any material change from where we were looking at that from the last quarter.

Tim Rezvan (Managing Director and Equity Research Analyst)

Okay. Fair enough. Thanks.

Operator (participant)

The next question comes from Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield (Managing Director)

Good morning, all, and congrats on your new Austin Chalk agreement.

Evan Kiefer (Interim CFO and Treasurer)

Thanks. Good morning, Derek.

Derrick Whitfield (Managing Director)

For my first question, I wanted to focus on your 2023 guidance. Assuming the midpoint of guidance, the implied trajectory for the balance of 2023 is about 1,000 barrels up on oil and about 6 million cubic feet down on, sorry, up on gas as well. Focusing on oil specifically, what do you see as the primary driver of that oil growth and of the lighter, lower activity trends we're seeing on shore?

Evan Kiefer (Interim CFO and Treasurer)

Thanks, Derrick. Yeah, it's a fantastic question. You know, a couple of things that we're looking at. One, you know, we have had some high-interest activity on our acreage in the Bakken, which has really helped out with the Q2 relative to the first, where those wells will continue to produce off into the next couple of quarters. We do have some line of sight of wells that have come online that we expect to see or will come online soon in the Permian. We do see a little bit of a move up on the gas side, going through the H2 of the year, really kind of focused in the Permian and then some benefit from the Bakken as well.

Derrick Whitfield (Managing Director)

Terrific. As my follow-up, with respect to your gas price realizations, you guys are, are considerably better than the industry for Q2. Wanted to ask if you could speak to some of the drivers there and your expectations for Q3 realizations as we stand here today.

Evan Kiefer (Interim CFO and Treasurer)

Sure, Derek. And so, yes, we came in at 135% of benchmark for the 2nd quarter. Really, what drove that was volumes a- and revenues that we recognized in the quarter that came from production in the 4th quarter of last year. There wasn't any particular well, there was actually a handful of them that came in that we booked. As you're aware, as a mineral company, there is an inherent delay from that initial production to when we receive checks on that. It's just the natural filling in of some of those wells that really dri- drove some of the higher prices, especially on the gas side this quarter.

Derrick Whitfield (Managing Director)

Terrific. Thanks for your time.

Evan Kiefer (Interim CFO and Treasurer)

Thank you, Derrick.

Operator (participant)

As a reminder, if you'd like to ask a question today, please press star one.

Tom Carter (Chairman and CEO)

Okay, if we don't have any.

Operator (participant)

Pardon the interruption. We have one more question from Trafford Lamar with Raymond James. Please go ahead.

Trafford Lamar (Analyst)

Hey, guys. Thanks for taking my questions. First, I, I was just wondering if you all could provide any additional color on the Longroad agreement, possibly development start date or any phase details or anything you all be willing to tell us?

Carrie Clark (SVP of Land and Commercial)

Sure. Hey, this is Carrie Clark. I, I'm assuming that you saw the press release. I don't think we have any more details to provide on the Longroad arrangement right now other than what was in the press release. We're excited about it. It's, you know, it's just a way for us, as we are always doing, to try to look at another option for extracting value out of the assets that we manage and own, and we're excited about it. I think it's a, a different concept than, than we've seen before in this, in this solar development, you know, as it currently stands today. We're really hoping that there's something scalable that makes, makes good sense for energy transition. You know, it's, it's certainly not at this point.

Oil and gas is still, is still very much our core competency and, and being an, an active royalty owner in the hydrocarbons game is what we're good at. We're always looking to the future again to emerging technology and especially on solar in this case, we're really optimistic about what Longroad it might be able to do and what we can do together and, and sort of using our unique position, to help really create the best possible, possible scenario for successful projects and, and something that has, again, quite a bit of scale. Not much more to add at this time, but, but we'll definitely speak to it in the future as things develop.

Trafford Lamar (Analyst)

Okay. Yeah, thanks for that. Then second, going to look at Angelina County here and on the, on the Aethon agreement. I know under the agreement, they're, they're obligated to drill 15 wells a year on BSM acreage, but do they have any requirements on, on well completions a year, or is that purely on their discretion?

Evan Kiefer (Interim CFO and Treasurer)

Yeah, this is Evan. Yeah, it's a, a great question and timely, just given where prices are in Louisiana with really gas prices. Yes, there, there is a provision in there to where they have to drill and complete the wells to get them online.

Trafford Lamar (Analyst)

Okay, perfect. Thanks, guys.

Evan Kiefer (Interim CFO and Treasurer)

Thank you.

Operator (participant)

It appears there are no further questions at this time. I will now turn the program back over to our presenters for any additional remarks.

Tom Carter (Chairman and CEO)

All right. Well, thank you all very much for joining the call today, and we look forward to speaking with you next quarter.