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Good day, everyone and welcome to the Black Stone Minerals 3Q Earnings Conference Call. [Operator Instructions] Please note this call is being recorded. I will be standing by if you should need any assistance. At this time, it is my pleasure to turn the conference over to the Director of Finance, Mark Meaux. Please go ahead.

Thank you. Good morning to everyone. Thank you for joining us either by phone or online for Black Stone Minerals third 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 today from the company are Tom Carter, Chairman, CEO and President; Evan Kiefer, Chief Financial Officer and Treasurer; Carrie Clark, Senior Vice President, Land and Commercial; Steve Putman, Senior Vice President and General Counsel; and Thad Montgomery, Vice President. I’ll now turn the call over to Tom.

Thank you, Mark. Good morning and thanks for joining us for our third quarter ‘23 results. We posted a solid quarter with adjusted EBITDA of $130 million for the quarter, an increase of 19% compared to the second quarter. This is now the sixth consecutive quarter where Black Stone has generated over $100 million in adjusted EBITDA. We generated total production volumes for the third quarter of 42,600 BOE per day, an increase of 18% from our second quarter volumes and now we expect to be in the upper end of our production guidance range of 37,000 to 39,000 BOE per day. Much of the increase was driven by royalty volumes, which increased 20% from the second quarter to 40,300 BOE per day and 8% above the third quarter of ‘22. Primary driver of oil volumes was new wells coming online in the Permian. Additionally, we had 6 new wells come online in the third quarter in the Shelby Trough. Two of those were Aethon and 4 were XTO. Despite the lower rig counts in the Louisiana Haynesville this year due to lower pricing, we continue to see activity from new wells resulting in our Louisiana Haynesville volumes increasing 13% compared to the second quarter. Aethon continues to ramp up production in the Shelby Trough and held the 6 rigs on location at the end of the third quarter, increasing from 5 rigs in the second quarter. To-date, 28 wells have been turned to sales in the Shelby Trough under our development agreement with Aethon. And there are currently 35 wells in the drilling completion phase, which exceeds the minimum pace of 27 wells per year, Angelina and San Augustine counties that we expect to benefit our production in 2024. We saw a 4% increase in rigs operating on our acreage in the third quarter. The increase is driven by Haynesville and Gulf Coast with 76 rigs currently running as of September 30. Throughout the quarter, we saw rig count peak at 90 in August due to new drilling in the Permian from various operators. The U.S. rig count has contracted approximately 6% during the quarter, which highlights the natural ebbs and flows of development on a diversified acreage position such as ours. We previously announced that we are maintaining our distribution of $0.475 per unit or $1.90 on an annualized basis and as reported yesterday, represents a 1.25x coverage for the quarter. Despite the challenges with natural gas prices, we have been able to maintain a strong balance sheet through the year and hold the distribution at its highest level since going public. Additionally, we have put into place a $150 million unit repurchase program that replaces our previous $75 million program. This will allow us the flexibility and ability to opportunistically buy our own units. It’s been a great year and we are encouraged by the positive momentum into the end of the year. Yesterday, we announced Evan Kiefer has been appointed as Senior Vice President and Chief Financial Officer and Treasurer, removing the interim in his title. With over 10 years of experience with Blackstone, I congratulate him on his position. With that, I will turn it over to Evan to walk through the details of the quarter. Evan?

Perfect. Thank you, Tom and good morning to everyone. As Tom pointed out, we had a very good third quarter. We reported average daily production of 42,600 BOE per day, which is an increase of 18% over our reported second quarter production. This was led by production from new wells coming online in the Permian as well as better-than-expected results in the Haynesville in the Shelby Trough and Louisiana. Lease bonus and other income for the quarter was $2.2 million for the third quarter and $8.7 million for the first three quarters of the year. While we have emphasized development programs over lease bonus, we remain encouraged by continued leasing activity in the Haynesville/Bossier despite the lower price environment this year compared to 2022. And speaking of pricing, we saw a recovery in oil prices in the third quarter with realized prices of approximately $78 per barrel and $2.90 per Mcf. That represents an increase of 8% and 1% in oil and gas prices compared to the second quarter, respectively. For comparison, during the third quarter of 2022, average price of oil was over $90 per barrel and over $8 per Mcf. The current quarter represents a 17% decrease in crude prices and 65% decrease in natural gas prices from this period last year and continues to highlight why we hedge our near-term production volumes. We have a solid hedge book that brought in approximately $24 million of realized cash settlements for the quarter with approximately 55% of our production hedged for the remainder of 2023, with natural gas hedged at a little over $5 per Mcf. In 2024, we have continued to add to our hedge portfolio with a target of approximately 70% of our estimated production by the end of the year. This results in our adjusted EBITDA for the quarter of $130 million, which is up from – up 19% from the second quarter and rivals our high watermark that was set in the fourth quarter of 2022. Yesterday, we announced our updated guidance that reflects the strong quarter and positive trends that we are seeing. As Tom mentioned, the production guidance that we expect to come in at the upper end of our guidance range for 2023, while expecting lease operating expenses and production costs remain in line with our expectations. Additionally, we expect G&A, cash and non-cash to be in the lower end of our guidance range. We previously announced the distribution of $0.475 per unit or $1.90 per unit on an annualized basis. Distributable cash flow for the quarter was $124.4 million, and this results in a distribution coverage for the third quarter of 1.25x. This is now the fourth consecutive quarter where we have ended the quarter with no borrowings on our revolver. And as of last week, we had over $90 million of cash prior to payment of the distribution next month. Effective yesterday, we increased our borrowing base from $550 million to $580 million due to an increase in commodity prices, but we have elected to hold commitments flat at $375 million. As Tom mentioned, our Board approved a $150 million unit repurchase program, while we will continue to prioritize returning cash to our investors. This allows us to opportunistically repurchase our common units. With the low gas price environment today and LNG export capacity expected to increase into 2025, we are bullish on our long-term gas exposure and do not think the current unit valuation at approximately 10.5% yield fully reflects that view. Additionally, the first redemption window for our preferred units opened at the end of next month. This unit repurchase program gives us the flexibility to potentially repurchase common units, which trades at a discount to that contractual redemption price of 105% of par or just over $21 per preferred unit. Repurchasing common units allows us to allows us the opportunity to reduce any potential dilution should those units convert into common in the future as well as offset any increased interest rate that goes into effect at the end of next month. Just as a reminder, that rate reset from 7% to the 10-year plus 550 basis points or approximately 10.4% based on current rates. I’ll echo Tom’s comments as it is a great quarter and with that, we will open the call for comments.

Thank you. [Operator Instructions] We will take our first question from Tim Rezvan with KeyBanc Capital Markets.

Good morning, folks. Thanks for taking my questions and Evan, congratulations on the permanent role. I guess I’ll start with the repurchases. I’m just trying to understand kind of the rationale behind that. You talked about a 10b5-1. And then you also talked about offsetting dilution. So should we assume you will be active this quarter is the 10b5-1 in place? Or do you – is that something you may put in place? Or I’m just trying to understand kind of the rationale behind the repurchase decision now?

Yes. Nothing is in place right now. This is just gives us the flexibility and the opportunity to repurchase units going forward. One of the things we really were looking at is the overall principal value on the preferred units being par at a little over $20 and 105% today puts it at $21.41 per unit. And since those are convertible one-to-one in the common and with the yield going to, call it, 10.5% on our common units and 10% on the preferred just gives us a little bit of that discount to the common units, which we like relative to the preferred.

Okay. Okay. And I guess if you do have another month to decide what you’re going to do with the preferred. You obviously have a little bit of a cash balance building. Will that be something that you will disclose in the marketplace if you do decide to redeem some or all of them?

Yes. That is correct. Yes. And we have $90 million today on the balance sheet. Really, that’s going to be paid out as far as the distribution in the middle of next month. But as we go forward, thinking about the potential redemption of the common – on the preferred or redeeming any common units, that will most likely just be used out of any cash that we build through coverage or we have the line of credit that’s currently unused with $375 million of cash commitments today.

Okay, okay. So you have options. Okay. I appreciate that. And if I could just take one last one in, obviously, a very strong production number. The modest revision to guidance saying it will be at the upper end in first some sort of decline in the fourth quarter production. Can you talk about kind of what you are seeing and why we shouldn’t think that you will be above that 39,000 a day for the year, just trying to think about the kind of the near-term cadence of production.

Yes. Of course, Tim and thanks for the question. Yes, when we model our forecast and look forward, we typically just model what we have very clean visibility and line of sight into. So, that’s going to be based off of any feedback we received from operators, from permits and drilling activity that we see on our acreage. And so whenever we look into our results for the third quarter, that was all from new wells that we saw drill at the beginning of the year. With the lower rig count in the Haynesville, we see some challenges there going forward and expect overall production, although it was up for the quarter to still remain fairly flat going into next year. But there is always things that occur on a large diversified position such as ours that we don’t necessarily have that clean visibility into. And so because we model what we see and have that visibility into, there is that inherent conservatism built into our views. Right now with where we see the program going and where we see with the drill pace and everything, there is that decrease from current volumes into the fourth quarter. But we are still encouraged and optimistic as to what volumes can go into next year and beyond.

Okay. Thanks for the responses.

Thank you.

[Operator Instructions] We will go next to Derrick Whitfield with Stifel.

Good morning and congrats on your results.

Thank you.

Following up on Tim’s question, given the strength of your oil production in the quarter, could you help to frame how much of that increase was for prior quarter activity versus underlying growth?

Yes. So, based off of the production that we saw in the third quarter, all of that was really, or at least the vast majority of that was from wells that were drilled in 2023. The actual breakdown between what was in the current quarter versus production that we received from prior periods going to be a smaller portion or a smaller piece of that. But like I said, the majority of the increase in oil volumes in this quarter was all really drilled in 2023.

And with regard to the 28 Angelina County Aethon wells that are in various stages of development, could you help frame the split on where they lie in development and your expectations on when the wells will be turned in line?

Yes. So, we have through that agreement certain criteria that requires them to drill and complete those wells. Whenever we look at what the wells are currently being in the drilling phase, that may include wells that are on the same pad. That’s going to be on average, call it, 10 months from initial drill to turn in line going forward. And so we would expect to see those wells coming online, most likely in the middle of next year.

I would just add something to that statement. Aethon is really doing a great job out there in the Shelby Trough. And they have a growing program out there and some of the metrics around timing that we built into our contract some 2 years or 3 years ago are morphing as multi-pad development wells become more common, and the program is likely to expand. So, we may see a little bit more lumpiness in turning to sales because they are doing more wells at once, and it takes longer to get a full set of them up and ready to turn on. But we see that as positive and we really look to work closely with Aethon on all of that.

And perhaps staying with you for one last follow-up, if I could. I know your focus in the recent years has been on organic conversion opportunities. Having said that, how would you characterize the current state of the M&A market and your desire to participate in that?

Well, I will answer that this way. The overall M&A market is pretty frothy in terms of valuations, I would say. But we think there continue to be more opportunities than we would have said we saw a year or 2 years ago, but we are trying to look in places where maybe other people aren’t looking.

Sure. Thanks for your time.

Thank you, Derrick.

At this time, I will turn the conference back over to our presenters for any additional or closing comments.

Well, thank you all for joining us today. We are pretty optimistic with the pace, and activity levels that we are seeing and our ability to continue to grow our platform, and we look forward to talking to you again next quarter.