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Operator: Good day, everyone, and welcome to today’s Black Stone Minerals Fourth Quarter and Earnings Release Conference Call. At this time, all participants are in a listen-only mode. Please note, this call may be recorded, and I will be standing by if you should need any assistance. It is now my pleasure to turn the conference over to Senior Vice President and General Counsel, Steve Putman.

Steve Putman: Thank you. Good morning to everyone. Thank you for joining us either by phone or online for Black Stone’s fourth quarter and full-year 2022 earnings conference call. Today’s call is being recorded and will be available on our website along with our 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 our cautionary information about forward-looking statements in our press release yesterday, the Risk Factors section of our 2022 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 measures are described in our earnings press release from yesterday, which can be found on our website at blackstoneminerals.com. Joining me on the call from the company are Tom Carter, Chairman and CEO; and Carrie Clark, Senior Vice President, Land and Commercial; Evan Kiefer, Vice President, Finance, and Investor Relations; Garrett Gremillion, Vice President of Engineering and Geology; and Thad Montgomery, Vice President of Land. I’ll now turn the call over to Tom.

Tom Carter: Thank you, Steve. Good morning to everyone on the call. Thanks for joining us today to discuss our fourth quarter and full-year 2022 results. We posted a very strong quarter across the board and in fact set new records in production and cash flow. We generated total production volumes for the quarter of 42,000 BOE per day, an increase of 5% over our third quarter volumes. That increase was driven by higher royalty volumes, which totaled 40,000 BOE per day, up 7% from the last quarter and the highest level of royalty production in our history. Oil volumes trended up in the Bakken and the Midland, Delaware plays, while the increase in natural gas volumes primarily came from the Shelby Trough Haynesville/Bossier position, where our operating partner, Aethon, has four rigs on location and where we had a large contribution from overrides associated with our farmed out working interests in the play.

These overrides contributed BOE per day of volumes in the quarter that cover multiple months of production. We also saw a step-up in volume from our Austin Chalk acreage. Both of these are strong examples of our potential €“ of the potential in our organic growth efforts, where we attract operators onto our existing concentrated acreage positions through creative incentive structures and maximize the value of our retained interest through farmouts with third-party capital providers. To date, 14 wells have been turned to sales in the Shelby Trough under our development agreement with Aethon, and another 16 are in various stages of drilling or completion. In addition, 18 new generation multistage completion wells have been turned to sales in our concentrated acreage position in the East Texas Austin Chalk.

The goal is to accelerate production where it matters the most, while shielding Black Stone from any meaningful capital requirements, that strategy paid dividends in the fourth quarter, and we expect that to continue into future years as well. Our record results came against a healthy overall environment for our producers. Realized prices for the fourth quarter were approximately $85 a barrel at $6.50 per MMBtu for gas, both down relative in the last couple of quarters, but clearly high enough to encourage continued development activity. We had 108 rigs operating across our acreage at December 31. That’s an increase of 17% relative to where we were at the end of the third quarter and is 14% higher than we saw at the end of 2021. Since 2020, we’ve averaged 10% to 15% of the active rigs in the lower 48 on our acreage.

And with our organic initiatives, continue working on attracting more capital and development activity going forward. The record royalty volumes and favorable commodity price environment combined to generate the high-single quarter cash flow for Black Stone Minerals as a public company. We reported adjusted EBITDA of 131 million and distributable cash flow of 125 million for the fourth quarter, both up 7% to 8% from the third quarter. Most importantly, these record results and our confidence in our outlook for 2023 led to the fifth consecutive distribution increase with fourth quarter distributions of per unit that we announced earlier this month. This also establishes a new high watermark for Black Stone. Overall, it was a great quarter, and we have a lot of positive momentum going into 2023.

I’m sure many of you saw our announcement last week that Jeff Wood is stepping down as President and Chief Financial Officer effective next week. We really appreciate Jeff’s contribution to Black Stone over his six years with us, and we sure wish him the best in his future endeavors. Evan Keefer who has been at Blackstone for nine years and currently serves as VP of Finance and Investor Relations, will step into the CFO role. We’re fortunate to have Evan and his expertise and deep knowledge of the company and I am very confident the CFO transition will be seamless. With that, I’ll turn it over to Evan to walk through the details of the quarter and discuss our 2023 guidance.

Evan Kiefer: Thank you, Tom, and good morning to everyone. Since joining the company in late 2013, I’ve supported the IPO process. I’ve seen the Shelby Trough transition through multiple operators into the program that has grown into today and worked alongside our team through many other strategic projects. I’m very excited to step into the CFO role and what this company will achieve through our continued efforts to develop our existing asset base. As Tom mentioned, it was a record-setting quarter in terms of royalty production, adjusted EBITDA, distributable cash flow and distributions paid. We’ve accomplished all of this despite working interest volumes continuing to trend down, which was by design through various farm-out agreements that we started back in 2017 and $41 million of realized hedge losses for the quarter.

For the full-year, we generated $771 million of oil and gas revenues, which was up 57% over 2021 levels and $466 million of adjusted EBITDA from 37,100 BOE a day of total production for the year. We paid out a total distribution of $1.75 per unit for 2022, which is an increase of 85% over 2021 levels. We retained approximately $75 million for debt repayment throughout the year as well. In conjunction with that, the earnings release that we put out our 2023 guidance yesterday. As we look forward to the full-year 2023, we forecast annual royalty production to be up slightly from 2022 levels, with the majority of those gains coming from our key organic growth plays. We expect to see production growth in the Shelby Trough as Aethon continues to ramp up development activity targeting a minimum pace of 27 wells per year by the end of this year, as well as higher volumes in the East Texas Austin Chalk as we work with our operating partners there to accelerate activity.

We have had 24 new generation multistage completion wells spud in the Austin Chalk with 18 of those that are currently producing. We also expect production growth from our Permian and Bakken positions where we have visibility into some high interest development locations. This is partially offset by a slowdown in Louisiana Haynesville after a very robust 2022 and some natural production declines on our acreage outside of these core plays. We mentioned last year that we expected to grow production through 2023 with an exited target rate of close to 40,000 BOE per day. Despite the recent pullback in natural gas prices, our expectations are to be at or above that level by the end of this year, which will be driven largely in part from our development agreements with our key operators in the Shelby Trough and Austin Chalk.

We expect lease bonus, operating expenses, and production costs to be roughly in-line with 2022 levels. G&A is also expected to increase slightly in 2023 as a result of inflationary costs and selective hires to support our ability to evaluate market and manage our undeveloped acreage position to potential operators. While we don’t normally give specific cash flow guidance, I will note that strike prices on our natural gas swaps increased from approximately $3 per MMBtu in 2022 and to over $5 per MMBtu in 2023, an increase of over 60%. The average strike price of our oil hedges increased by over 20% from approximately $65 per barrel in 2022 to over $80 per barrel in 2023. We are in our normal range of hedging approximately 60% of our estimated volumes for the rest of this year.

That will provide a great deal of support to our cash flows in 2023, even with the recent pullback in pricing. And speaking of hedges, we’ve started the 2024 natural gas position with €“ in the recent weeks to protect against, what could be a difficult period in gas prices in advance of increasing LNG exports in 2025. We currently have hedges covering approximately 15 Bcf of natural gas production for the full-year of 2024 with an average strike price of $3.67. We will remain consistent with our hedge program continuing to build the 2024 position throughout this year, targeting 70%-plus of our estimated volumes by the end of the year. Even with the distribution increase, we generated distribution coverage of 1.26x for the fourth quarter, which further strengthened our already solid balance sheet.

We had a total debt of $10 million at the end of the year and currently have $57 million net cash position in advance of paying the fourth quarter distribution. This has all been very positive for Blackstone, and we have been able to grow our royalty production through organic efforts without incurring debt or issuing new equity for acquisitions. We are very well-positioned to continue this trend into 2023 and offer a compelling value proposition to new and existing investors with virtually no debt and a distribution, which we believe is sustainable in 2023 that delivers a yield of over 12% to our current unit price. And so, with that, we’ll open the call to any questions.

Operator: And we’ll take our first question from Derrick Whitfield with Stifel. Your line is open.

Derrick Whitfield: Good morning all and congrats to you, Evan, on your promotion.

Evan Kiefer: Thank you, Derek, and good morning.

Derrick Whitfield: For my first question, I wanted to focus on your 2023 guidance. With the lower gas prices we’re observing at present, how are you thinking about the conversion of DUCs to production in your guidance?

Evan Kiefer: Yes, Derrick, that’s a great question. And obviously, gas prices have pulled back pretty significantly since the middle of December. And so €“ we do see it as a challenged market going into this year and what we see going forward. One thing I will point to that we do have a lot of visibility into is really the Aethon agreement through the Shelby Trough. That set up by a minimum development pace through those contracts. So, we do have some visibility there, as well as some of the development agreements that we have also in the Austin Chalk. Now, we do think there’s going to be a decrease in our overall Haynesville Louisiana volume, compared to what we saw in 2022 because of the prices, we even saw the Comstock announced that they’re laying down two rigs. So, we do expect it to be a little bit of a challenged year with slightly lower volumes on the gas side in the Louisiana Haynesville this year.

Derrick Whitfield: Terrific. And maybe shifting over to the Austin Chalk. Since there were no, I guess, material updates in your press release, I wanted to see if you could offer some perspective on 2023 as it relates to your general expectations for activity and if there are any specific developments we should place on our radar?

Evan Kiefer: Yes. So overall, everything out there is still going forward as we expect. I mentioned in my commentary that we have 24 wells have been spud, 18 of them are online. So that leaves 6 wells currently that have been spud that are coming online here very soon. We do think, kind of for the remainder of the year, there’s potential for an additional 8 to 10 wells to be drilled out there this year with further development going forward. Overall, kind of our view is that even with kind of gas prices pulling back, it’s still a very economic and very attractive returns to operators out there. So, we’re excited with working with the existing operators that we have and potentially new ones that we can bring to the acreage going forward to continue to develop at the pace that we would like.

We, overall still see within the fairway approximately 250-plus remaining locations out there at current prices. And so, we do see a lot of runway, a lot of potential activity that we can drive on this position going forward.

Tom Carter: I’d just add to that, that while the Chalk play generally over time has had a fair amount of variability in it. And this Brooklyn redevelopment is still in its early stages. The last two wells that have been drilled in what we call the core of the core are outstanding wells, one of them producing over 1,500 barrels of oil a day, and 12 million cubic feet of gas over the last 30 days.

Derrick Whitfield: That’s terrific. Great update guys.

Evan Kiefer: Yes, thank you Derrick.

Operator: And we’ll go next to Tim Rezvan with KeyBanc. Your line is open.

Tim Rezvan: Hey, good morning everybody and congratulations Evan, on the promotion.

Evan Kiefer: Yes. Thank you, Tim.

Tim Rezvan: So, I’ll pick on you first. I’ve asked you repeatedly in the past about the distribution level. And as you showed in the report, you continue to have de minimis debt and leverage. So, how do you think about 79%, call it, 80% distribution in this quarter €“ how do you think about that rate going forward? And why would you €“ why wouldn’t you, kind of increase it given that debt they have?

Evan Kiefer: Yes. So, I’ll just start off by saying when we look at the distribution and our internal policy, as far as trying to establish what we want to set that at going forward, is that we’ll look forward to the next 12 months to 24 months at overall general activity in the sector, pricing trends and everything else and try to establish what we think is a reasonable distribution that can be maintained over the forward quarters. We like the idea of having a stable to growing distribution, which is what we’ve done over the last five quarters where we’ve been able to slowly increase that as prices and production has improved. So, looking at the fourth quarter with increasing it again to the , it’s something that we feel is fairly stable and achievable throughout this year, despite some of the pricing pullback, while able to, at this point, have all of our debt significantly paid-off.

Obviously, that will increase whenever the distribution gets paid out from $57 million today and go back up, call it, around the $50 million mark going forward. And so, it’s really a product of looking at what we see the guidance going forward and trying to set a distribution that we feel very comfortable and achievable going forward despite some volatility in overall pricing.

Tim Rezvan: Okay. Okay. That’s helpful context. And then if I could switch gears a bit. It’s been a fairly active M&A period for most of the public minerals companies. Blackstone has been an outlier, seems to be focused on the override that you can do to increase activity. What are your thoughts on that? Are you not at all looking at M&A? Is it more that you have in like the prices you see? Again, with the balance sheet you have, you certainly can support some inorganic growth. So, just kind of curious how management and the board is thinking about that?

Tom Carter: Tim, this is Tom. I’ll answer that. Historically, for a long time, we’ve been an acquisition company. Our feeling today is that the market is very competitive in that arena. And we really look at the efficiency of that source of production relative to the cash flow per share or production per share. And it is balancing to find things of size and pricing levels that we feel are competitive with what we can do on our own properties, but your question earlier around our coverage, if you will, we may be a little bit different from others. We don’t have any problem whatsoever with building up a fair amount of liquidity on our balance sheet because we’ve got things that we can do with it over the near next 24 months. And if an acquisition that we just had to have because it was very well priced, we’d be in a really great position to do that, but we’re currently trading, our stock is trading at a 12% yield, and it’s hard in our opinion to buy things that have a 12% internal rate of return when our equity is trading at a 12% yield.

It’s just not that compelling. That doesn’t mean we won’t ever do it again, but it’s just €“ it’s not €“ we don’t see it as an efficient way for us to grow because we don’t want to lever our balance sheet up a lot and with the way our units are trading, it’s a challenge.

Tim Rezvan: Okay. I appreciate that color. If I could sneak one last one in. Just to circle back to the Haynesville. You talked about the Aethon agreements that you have in place. How confident are you that those agreements will hold if we were to see gas prices, kind of gap down? And I don’t know if you know or can share any details on maybe hedges that they have in place or kind of what assurances do you have that they would honor that if we do a worst-case scenario for gas?

Evan Kiefer: Yes. So Tim, this is Evan. I’ll start with that. One of the biggest points that I’ll mark to, and I can’t really comment too much on Aethon hedge position and everything just because we typically don’t have those conversations with them, but when we originally struck the deal with Aethon in Angelina County was May of 2020 when prices were sub $2 at the time. And so we kind of set up this program with them to be interesting to them at those price environments and so where we still see economics on these wells being very attractive to them going forward. And so, obviously, there will probably be a threshold to where it dips below that, but at current prices and current levels, as we said, negotiated those deals at sub-$2 pricing gives us a lot of leeway and confidence into that program going forward.

Tom Carter: Yes. I’d like to add to that. The Aethon agreement and the assets that they have under their umbrella with us, are in fact, are indeed a big deal to us. And I think it’s a pretty big deal to them. We have contractual relations with those guys that are pretty constructed to address a long-term development program, not just a given 6 or 9 or 12 or 24-month cycle because this is a 20-year development program out there. Our royalty rates vary with gas prices. And we also stay in touch with those folks. Never say never on people changing their direction, but we don’t have any indication of that with Aethon at this point in time. And we think they’re great operators and great long-term partners, and we will be responsive to them. And I think they to us in developing that program for the long haul.

Tim Rezvan: I appreciate the comments. Thank you all.

Operator: And we’ll take a question from Monroe Helm with Clemensen Capital. Your line is open.

Monroe Helm: Okay. And thanks a lot and thanks for the information so far. I’m kind of new to the story, and I appreciate some of the color on the agreement. Just on the Aethon agreement since you just mentioned kind of a 20-year development plan. Is there a certain number of wells we’re committed to drill in 2020 by year over the next two or three years, not just 2023, but 2024, 2025?

Evan Kiefer: Yes. This is Evan. So, I’ll start with that. And so at the end of this year where they start ramping up to 27 wells per year, that’s the current terminal rates that it goes to going forward. And so that program originally started with Angelina County at four wells per year, ramped up to 10 and then 15, and then also including the development agreement in San Augustine that went from 5 to 10 to 12 going forward. And so, that’s where we get to the growing into that 27 well pace at the end of this year that’s going to continue into future development years.

Tom Carter: There’s a lot of subtleties and things in those agreements that they can use to control their own destiny. They in fact, if they go above 27 wells a year, they actually get even a lower royalty from us, which is a win-win for them and for us. And who knows that may be happening also. So, it’s a complicated agreement, keeps our land administration team on its toes, but it’s a great partnership so far.

Monroe Helm: Okay. Can you tell me a little bit about how you entice these producers to drill on your acreage. I think I noted in the press release that there are some completion techniques that have enhanced the rate of returns over in the Austin Chalk. Could you maybe talk about that and some opportunities there to get more activity on your acreage?

Tom Carter: Well, I would say this is an area where we have a lot of acreage. Some of it is very old production that’s been out there seeing and we are doing €“ taking steps with the operators of those older properties to encourage them to redevelop the property and that’s hopefully going to pay some dividends. And in addition to that, we have acreage that is in the play that wasn’t tied up where we have made trades with folks to come in and drill wells on that property, not charging them large upfront fees and working with them on royalty to stimulate activity because as the critical mass of the whole area, which is several hundred thousand acres increases the likelihood of more rapid development increases. And the wells that have been drilled to date in the core of the play have been very good wells, and there’s a lot more of them to look at like the ones I mentioned earlier.

Monroe Helm: Okay. One of maybe when you were setting your most recent distribution increase, did you take it €“ how seriously did you consider an environment where we might have $2 to $2.50 gas for some extended period of time?

Tom Carter: Well, I think we believe and took into account that 2023 and 2024 and maybe some into 2025 that will be challenging for natural gas markets. Everyone, I mean as we’ve all looked out over the last five years, I think it’s a general consensus in the industry that until some of these newer LNG export facilities come online, there’s going to be a in growth of natural gas because it’s €“ the production has gone up and the prices that were in existence last year really saw some increases in activity. We think it’s going to be a period of time where we don’t see that much growth, but we’re well hedged and we have agreements that we don’t think our operators are going to be highly volatile in their well count.

Monroe Helm: Okay. Well, I appreciate your answers.

Tom Carter: Welcome.

Operator: And it appears we have no further questions. I’ll turn the program back to the speakers.

Tom Carter: Well, thank you all for joining us today, and we look forward to talking with you in a couple of months.

Operator: This does conclude today’s program. Thank you for your participation, and you may disconnect at any time.