Black Stone Minerals LP
NYSE:BSM
Earnings Call Analysis
Q3-2023 Analysis
Black Stone Minerals LP
Black Stone Minerals reported a robust third quarter in 2023, showcasing notable growth with an 18% increase in total production volumes from the previous quarter. The company achieved an impressive 42,600 barrels of oil equivalent (BOE) per day, positioning it at the higher spectrum of its production guidance, ranging from 37,000 to 39,000 BOE per day. This surge is primarily attributed to the inflow of royalty volumes, surging by 20% since the second quarter, and an 8% year-over-year uptick. This remarkable progress was led by new wells in the resource-rich Permian Basin and improved results in the Haynesville Shale, particularly in the Shelby Trough area, and Louisiana. Black Stone's distribution for shareholders has been reinforced at $0.475 per unit, equating to $1.90 per unit annually, assured by a confident distribution coverage of 1.25 times for the quarter.
Despite experiencing a tumbling in oil and natural gas prices from the same period last year, Black Stone Minerals has navigated through this volatility prudently. The company's strategy includes a solid hedging program that provides stability amidst fluctuating prices, bringing in approximately $24 million in realized cash settlements for the quarter. Moreover, the production hedge stands at about 55% for the remainder of 2023, ensuring a cushion against price drops with natural gas hedged at slightly over $5 per Mcf. Looking into the future, the company has supplemented its hedge portfolio for 2024 targeting a hedge of roughly 70% of estimated production by year-end.
Black Stone has managed to keep its lease operating expenses and production costs aligned with its original expectations, underlining effective cost management. Additionally, the company's general and administrative (G&A) expenses, both cash and non-cash, are projected to settle at the lower end of their guidance range. These disciplined cost control measures contribute to a solid financial footing as indicated by the company's performance and forward-looking statements.
Reaffirming its commitment to enhancing shareholder value, Black Stone Minerals announced a significant unit repurchase program, inflating the budget from a previous $75 million to an escalated $150 million. This strategic move signals the company's intent to opportunistically acquire its own units, reflecting a bullish stance on the long-standing potential of their natural gas exposure and a belief that current unit valuations do not fully capture this potential, especially considering the impending rise in LNG export capacity projected up to the year 2025.
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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 2013 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 [indiscernible] 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 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've 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're 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'll 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 3 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 noncash 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.
[Operator Instructions] We'll take our first question from Tim Rezvan with KeyBanc Capital Markets.
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. 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 fourth quarter production. Can you talk about kind of what you're seeing and why we shouldn't think that you'll 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's 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's 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're still encouraged and optimistic as to what volumes can go into next year and beyond.
[Operator Instructions] We'll go next to Derrick Whitfield with Stifel.
Following up on Tim's question. Given the strength of your oil production in the quarter, could you help 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 Asian 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'd 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 or 3 years ago are morphing as multi-pad development wells become more common, and the program is likely to expand. And -- so we may see a little bit more lumpiness in turning to sales because they're 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 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'll 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 ago, but we are trying to look in places where maybe other people aren't looking.
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're pretty optimistic with the pace and activity levels that we're seeing and our ability to continue to grow our platform, and we look forward to talking to you again next quarter.
Thank you. Ladies and gentlemen, that does conclude today's program. You may disconnect at this time.