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Good day, everyone, and welcome to today's Black Stone Minerals’ 2Q Earnings Conference Call. [Operator Instructions] Please note, this call may be recorded. [Operator Instructions] It is now my pleasure to turn the conference over to Mark Meaux, Director of Finance. Please go ahead.

Thank you. Good morning to everyone. Thank you for joining us either by phone or online for Black Stone Minerals’ second quarter 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.

Thank you, Mark. Good morning to everyone on the call, and thank you for joining us today to discuss our second quarter of 2023. We posted a solid quarter with adjusted EBITDA of $109 million for the second quarter, in line with the first quarter results. This is the fifth consecutive quarter where Black Stone has generated over a $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 36,200 BOE per day, a decrease of 8% from the first quarter volumes. Royalty volumes decreased 9% from last quarter at 33,600 in BOE per day, but 11% above the second quarter of 2022. 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 second half of 2022. Oil volumes moved up in the quarter as well due to new development activity in the market. Aethon continues to ramp up production in the Shelby Trough and held the five rigs on location first quarter into the quarter 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 second half of the year. In addition, 26 new generation multistage 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 ten 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 second quarter, 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 30. As of yesterday, rig count was back to 83, an increase driven mainly from the Permian that offset the decreases seen in the second quarter. This highlights the normal ebb and flow of rig movements 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 second quarter of $0.475 per unit, flat to our first quarter distribution. We have over $80 million in cash prior to the payment of the distribution and a new high watermark for Black Stone since going public. We continue to prioritize returning that cash flow to our investors. With that, I will turn it over to Evan.

Thank you, Tom. And good morning to everyone. So as Tom mentioned, our royalty volumes for the second quarter totaled 33,600 BOE per day, which was down 9% relative to the first quarter. And total production for the quarter was 36,200 BOE per day. Oil prices for the second quarter averaged $73 a barrel and our realized prices before hedges came in at 99% of WTI prices. Gas prices at the Henry Hub averaged $2.10 per MMBtu. And 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 fourth quarter from 2022, where Henry Hub averaged over $6 per MMBtu. For comparison, a year ago, in the second 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 these short-term – the short-term volatility in commodity prices. In the second quarter, 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 first quarter. And 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. So, we continue to expect that approximately 70% of our hedge 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 second quarter. These are both consistent with the first quarter 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. So, 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 consolidated a slowdown in Louisiana Haynesville as we saw prices pull back 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 helped 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 second half of the year as indicated by our guidance range. And so with that, I will open it up to questions.

[Operator Instructions] Our first question comes from Tim Rezvan with KeyBanc Capital Markets. Please go ahead.

Great. Good morning folks, thank you for taking my question. I guess I want to follow-up on your comments, Evan, you talked about the guidance in place, but it’s getting a little gassier. I guess you guided to a little gassier SKU. Can you walk through what that was? Is it a little more Haynesville, a little less Austin Chalk than what you thought? Or just sort of kind of the trajectories of those two assets as you look to the end of the year.

Yes, good morning Tim. And thank you for the question. So this is Evan and I’ll take a first stab at that. And so, yes, 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 first half of the year. So, 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 the beginning.

Evan, can I chime in on that just a little bit. With respect to the Austin Chalk, that play is pretty variable in BOE of liquids volume per thousand – per million cubic feet of gas, and it ranges from anywhere from 35 to 250 barrels per million. And 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, so that's – we may see more liquid volumes coming out of that in the next year.

Okay. I appreciate that context. And then I wanted to ask on the distribution, obviously 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 baseline that $0.475 number has been intact for three straight quarters. You've been at 96% payout for two straight quarters. Obviously, gas market looks a little better. Do you feel like there's a need to deliver a consistent quarterly distribution? Or kind of what is the Board thinking about with that same number for three straight quarters?

Yes, Tim, this is Evan. I'll start answering that. And so one being the first and second quarter did come in fairly close with each other and almost within I think $0.5 million on a DCF basis. And so, one, we saw the coverage and felt comfortable with where the balance sheet was today to maintain that higher payout ratio. And as you mentioned, even going through kind of the remainder of the year, just looking at natural gas where third quarter were up to on the strip today, call it, $2.50, which is really just under a 20% increase from what we saw in first quarter. So 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. And so yes, we like the ability to maintain that, I think, with the balance sheet strength and the forecast that we're currently looking at for the second half of the year allows that.

Okay. Thanks for that. And then if I could sneak one more in. I'm going to repeat a question from last quarter. Circling back on the preferreds, 4Q is now less than two months away. I was curious if there's any update on what management or the Board is thinking with those preferreds and the rate going to kind of a variable rate? So thanks for any color you can provide.

Evan, do you want to go ahead on that one?

Yes. Thanks, Tim. Yes, it's a great question, and it's definitely something we've been looking at internally. And so, yes, that rate does reset in November of this year going to a 10-year treasury plus 550 basis points. And so where we're looking at it at rates today, that's a little bit north of 9% relative to the 7%. And so our view really hasn't changed too much from the last quarter. And so it is something that we're looking at. And they've been a fantastic partner over the years and maintaining that when we put the preferred in place with the Noble acquisition, and so yes, maybe there's something we can do there, but it's not really any material change from where we were looking at that from the last quarter.

Okay. Fair enough. Thanks.

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

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

Thanks. Good morning, Derrick.

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 in light of lower activity trends we're seeing on shore?

Thanks Derrick. And yes, a fantastic question. And so a couple of things that we're looking at; one, we have had some high interest activity on our acreage in the Bakken, which has really helped out with this second quarter 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. So we do see a little bit of a move up on the gas side going through the second half of the year, really kind of focused in the Permian and then some benefit from the Bakken as well.

Terrific. And as my follow-up, with respect to your gas price realizations, you guys 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?

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

Terrific. Thanks for your time.

Thank you, Derrick.

[Operator Instructions]

Okay. If we don't have any?

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

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

Sure. Hey, this is Carrie Clark. Assuming 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 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 different concept than we've seen before in this solar development view as it currently stands today. So we're really hoping that there's something scalable that makes good sense for energy transition. It's certainly not at this point. Oil and gas is still very much our core competency and being an active royalty owner and the hydrocarbons game is what we're good at, but we're always looking into the future, again to just emerging technology and especially on solar in this case we're really optimistic about what Longroad – it might be able to do what we can do together and sort of using our unique position to help really create the best possible scenario for successful projects and something that it has, again, quite a bit of scale. So not much more to add at this time, but we'll definitely speak to it in the future as things develop.

Okay. Yes. Thanks for that. And then second, kind of to look at Angelina County here and on the Aethon agreement, I know the under agreement they're obligated to drill 15 wells a year on BSM acreage. But do they have any requirements on well completions a year? Or is that purely on their discretion?

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

Okay. Perfect. Thanks guys.

Thank you.

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.

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