Black Stone Minerals, L.P. Q2 FY2022 Earnings Call

Good morning and welcome to the Black Stone Minerals Second Quarter 2022 Earnings Conference Call. All lines have been muted to eliminate background noise. After the speakers' comments, there will be a question-and-answer session. I would like to inform all participants that this call is being recorded. Thank you. I will now turn it over to Mr. Evan Kiefer, Vice President, Finance and Investor Relations.

Thank you, and good morning to everyone. Thank you for joining us either by phone or online for the Black Stone Minerals second quarter 2022 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 in our 2021 10-K. We may refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. A 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 also be found on our website at blackstoneminerals.com. Joining me on the call from the company are Tom Carter, Chairman and CEO; Jeff Wood, President and Chief Financial Officer; Steve Putman, Senior Vice President and General Counsel; Carrie Clark, Senior Vice President Land and Commercial; Garrett Gremillion, Vice President of Engineering and Geology; and Thad Montgomery, Vice President of Land. I'll now turn the call over to Tom.

Thank you, Evan. Good morning everyone, and thank you for being here for our second quarter 2022 financial and operational results call. In the second quarter, we achieved over $112 million in adjusted EBITDA, reflecting a 14% increase from the previous quarter, leading to a distributable cash flow of $107 million for the quarter. This marks the highest cash flow in a single quarter for Black Stone as a public entity. Fueled by this record financial performance, we also raised the distribution to our unitholders. Last week, we announced a distribution of $0.42 per unit for the second quarter, which is a 5% increase from the previous quarter and 68% higher than the distribution for the same quarter last year. During the second quarter, we benefited from favorable commodity prices, with crude averaging over $100 and natural gas around $7. Overall, our realized prices rose by 32% for the quarter, which was especially advantageous given our relatively low production volumes compared to what we anticipate in 2023 and beyond. Now, let's discuss our core plays, production trends, and inventory. We have a positive outlook on our production. Our total production volumes, including royalty and working interest, peaked in 2019 at just over 50,000 Boe per day. Currently, we are at approximately 34,000 Boe per day. This decline is attributable to a few factors. Firstly, in 2017, we farmed out all our working interest in the Haynesville/Bossier Shelby Trough play in East Texas. By the end of 2018, our working interest volumes there averaged between 12,000 and 15,000 Boe per day from a capital investment of over $50 million aimed at rapidly developing a substantial mineral position in that play. We strategically decided to focus solely on the royalty volumes once this play was established and operating independently. Consequently, we have not invested in drilling capital in that area since 2017, leading to a natural decrease in working interest volumes from about 10,000 Boe per day to approximately 3,000 Boe per day currently. Diminished working interest volumes in the Shelby Trough account for the majority of the decrease in our peak production levels. Just when the Shelby Trough development was gaining momentum in 2019, natural gas prices dropped, prompting our major operators in the area to shift their focus elsewhere. BP completely exited the area, and XTO indicated they would be inactive for several years. Many of you are aware of our efforts to remarket that acreage in 2020 and 2021, which led to two development agreements currently in place with Aethon Energy covering our available Shelby Trough acreage. This year, we are wrapping up the second program year concerning our Angelina County acreage and the first program year for our San Augustine County acreage with Aethon. This relationship has proven to be both important and successful. The agreement stipulates an annual increase in well counts for exclusive access to our acreage and preferred royalty rates. The program requires a total of 15 cumulative wells to be drilled this year. That figure will rise to 25 wells annually starting in September and escalate to 27 wells in the following year. These are deep, high-pressure wells. Aethon employs specialized rigs to minimize cycle times and cut costs. Even with restrictions, these wells can produce over 20 million cubic feet per day and maintain those rates for over a year. We anticipate significant growth from Aethon’s activities in the Shelby Trough, and notably, XTO is also active in San Augustine, drilling three wells this year with the possibility of more in the future. While our royalty volumes have decreased by around 5,000 Boe per day in the Shelby Trough since 2019, we believe our potential for royalty-driven growth there is strong, and we expect the area to rebound swiftly. Additionally, we have noticed an upward trend in volumes on the Louisiana side of the Haynesville play, driven by our initiatives to secure accelerated development agreements with operators like Comstock and the overall increase in activity from producers in response to favorable market conditions related to Gulf Coast gas and LNG exports. In the Permian, our production peaked at over 6,000 Boe per day by the end of 2019 and the beginning of 2020. Currently, we average about 3,500 Boe per day. It’s worth recalling that during the pandemic, we sold properties that generated approximately 1,700 Boe per day of production to alleviate our debt from a peak of $450 million to around $55 million today. Recently, we have seen new agreements in some of our most promising areas in Pecos and Reeves County, envisioning increased drilling activity and production growth there as well. Our latest venture, the East Texas Austin Chalk, has also evolved. This play was revitalized in 2019 amidst commodity downturns and just before the pandemic hit. To date, 18 wells have been drilled in this play, and we are progressing towards contractual commitments for our acreage that could yield between 25 to 30 wells spud over the next 12 months. A very positive report by Enverus in late June highlighted this part of the Austin Chalk play, noting that the report did not include the last well, which is currently flowing at 2,200 barrels of oil and almost 12 million cubic feet of gas per day, making it a standout well. This excites us about the prospects ahead, as many areas have robust economics. We are quickly learning where and how to drill this first-generation chalk play. Our inventory in key territories is plentiful, and we are eager about the potential, especially with hundreds of thousands of acres in what could be the core area and much more in regions yet to be explored. We are also actively engaging in discussions with reputable private and public E&P companies to further expand the play into new and previously untested regions where we hold significant acreage. More updates will follow in coming quarters. The journey from a peak of over 50,000 Boe per day in 2019 to the current mid-30,000s is attributed to voluntary production cutbacks, the sale of some Permian assets to fortify our balance sheet, and a significant reduction in activity during the pandemic. However, we view that as behind us now, with both new and existing operators ramping up production and promising revival plays on the horizon. We have strategically opted to focus on organic growth based on our existing acreage, thus maintaining our balance sheet strength and capitalizing on favorable price trends. The team has embraced this mandate enthusiastically and has delivered results. We are optimistic about our production increase as we transition from the previous cycle. The plays are there, the operators are ready, the economics are favorable, and we will ramp up production. If the macro environment remains positive and our main operators in the Shelby Trough and Austin Chalk follow through with their stated and mostly contractual plans, we expect to see production growth through 2023, aiming to exit next year with close to 40,000 Boe per day. Now, let’s discuss our inventory in relation to the broader macro view on global oil and gas consumption. Two years ago, many projected that oil and gas would become obsolete within two to three years, predicting that renewables would easily fill the gap. Today, the perspective has shifted from reactionary responses to a more measured understanding of long-term trends. We believe that oil and gas have a sustainable future ahead as the world seeks environmentally friendly solutions to meet the growing energy demands of a changing global economy. With that said, I’d like to highlight Black Stone’s inventory. We estimate our inventory, considering various costs and risk efficiencies, to exceed 20 years based on the last 12 months' production rates. That’s a strong inventory figure by any measure. Importantly, you may recall that 15 years ago, our known inventory in the Shelby Trough Haynesville/Bossier was nonexistent, as that play hadn’t yet been developed. There may be unforeseen opportunities within our remaining acreage. Black Stone possesses millions of undeveloped acres that are not currently accounted for in these inventory figures. Now, I’ll turn the floor over to Jeff for further details on the quarter.

All right. Well, thank you, and good morning, everyone. I'm going to keep my comments brief this morning as Tom really covered the important stuff of production, both for this quarter and of course our expectations for future growth in those volumes. I do want to make a quick word just on price realizations, and our outlook around that. Realizations for the second quarter were consistent with last quarter, at almost 100% of average WTI prices for crude, and 120% of average Henry Hub prices for our gas. That is before the impact of commodity hedges. And I'll note that, even though, as Tom mentioned, we reported record highs for adjusted EBITDA and DCF this quarter, those amounts were constrained by our hedges that should be no surprise. The positive news around that is those hedges roll at the end of the year, and the swap prices for our gas hedges increased by over 50% going from 2022 to 2023. And our oil hedge swap prices are up almost 30% for next year. So at current strip prices, and our existing hedges in place for both 2022 and 2023, realized prices would increase by 11% next year despite the backwardation in the current curves. So even if production levels stayed flat from 2022 to 2023, which of course is not our expectation, that would imply over $50 million of incremental distributable cash flow next year. Now, as you might expect in this environment, we do get a lot of questions around our hedging philosophy and our hedging practices. And I'll just say, during our entire history as a public company, we have hedged a certain percentage of our near-term forecasted production volumes. Typically, that's around 70% one year out and 50% or less, two years out. We designed that hedging strategy to even out and reduce volatility in our cash distributions. And looking at the history of that hedging program, since our IPO in 2015, it has generally been positive including a big benefit in 2020, when commodity prices turned down so dramatically. In 2021, and so far this year as prices have risen just as dramatically, the hedging program has limited some of that upside for us. So you take the bad with the good, and we continue to believe that a systematic hedging program serves its purpose over the long term. And frankly, the worst outcome would be to hedge through a down cycle, stop hedging at a time like this when prices are relatively attractive, and then watch prices just fall again when we don't have that hedge protection. The other thing that we like about hedging for 2023 is that it locks in some of that incremental DCF over this year, that I just mentioned. And as a management team, we feel good about the extent to which we can use hedges to provide greater certainty to investor distributions and particularly when that points to locking in a distribution increase. As I said last quarter in response to a question around all of this, it's just a corporate philosophy is one that we've been consistent around since our IPO, recognizing that in some years we'll benefit from it, and in some years we won't. Okay. So in our earnings release yesterday, we updated our guidance with the expectation that we would come in for the full year around the low end of our original guidance range. We see the ramp-up in some of our more active plays facing some headwinds by global supply chain interruptions that are happening across the industry. And we've also had some well timing slip, in some high-interest areas, as our operators optimize from multi-pad drilling. Over the long-term, that's going to be good for us, but it can tamp down some near-term volumes. And as Tom said, we absolutely view these as temporary issues. Our focus is to facilitate activity on our existing acreage that leads to production growth in 2023 and beyond and we believe we're very well positioned to do that. And finally, the balance sheet remains in great shape. The borrowing base for our revolving credit facility was reaffirmed at $400 million in April. Our total debt balance was $86 million at the end of this quarter and is down further to $54 million today. And of course, that is in advance of paying our second quarter distribution, which will occur on August 19. So that concludes our prepared remarks. So Paulie, we will open this up for questions.

Thank you to all our speakers. Your first question comes from Brian Fitzgerald, a private investor. You may proceed with your question.

Hi. Thank you for a very good quarter. Great results. Could you add more commentary on the East Chalk, and the operators in the area now that you set up a favorable royalty program to induce drilling?

Sure, Brian, I'll start on that and others can chime in. Look, we're very excited about the chalk. This is honestly two years of a lot of hard work by the team. As we said in prior calls, we had an existing group of really three main operators in the core of that field. And so we've just done a number of things. We have worked with those existing operators, to try to accelerate their activity on existing leases. And we have brought in new players, to start new development activity around it. So I think as we mentioned, we've had 19 wells spud around that area over the past year plus and 11 wells producing now. We see that area is getting better and better delineated all the time. And what we're excited about, is with this new completion technology, we're absolutely seeing a nice fair way of acreage where we're seeing consistent and very strong results. As Tom mentioned, the most recent well out here came in just an absolute barn burner at 2,000-plus barrels a day and almost 12 million cubic feet of gas a day. So yes, look we're excited about this. It's been a ton of hard work and we think that as we look into 2023 and beyond, it's going to be a real area of growth for us.

Thank you.

Your next question comes from Trafford Lamar of Raymond James. Your line is open.

Hey, guys. Thanks for taking my call. My first question kind of revolves around the distribution coverage. I know in the first quarter you are about 1.1x and then this quarter was closer to 1.2. Just looking at the second half of the year on like a modeling basis what could – could we expect an average of that or closer to 1.2 or revert back to 1.1? I just want to get your thoughts on that. Thanks.

Sure Trafford. This is Jeff. I'll start on that as well. Yes. So look we have sort of said on some of these past calls that we expect distribution to come down, payout ratios to come up over time just given the fact that the balance sheet is so clean and we are prioritizing returning our excess cash to investors. Second quarter was a little unusual. Obviously, there's some backwardation in price curves through Q3 and Q4 before the uptick in hedges kick in for 2023. So really we ran a little higher coverage than we would anticipate going forward this quarter at 1.21 times really just to sort of balance it out through the rest of the year. So – but there's been no change in philosophy here. I think we will continue to prioritize returning cash to investors over things like buybacks for the moment. And so you should see that coverage ratio come down as we go forward through the year.

Okay. Perfect. Great. Thank you for that. And then my second question revolves around hedges. I just want to get your thoughts on maybe 2023 and onwards if – the possibility of collars. Have you all talked about that versus swaps? I know you've all been strictly swaps in 2022 and then right now for 2023. I just wanted to get your thoughts on that.

Yes. So we look at collars and swaps for every time we go to put on trades. We've seen those swap levels as attractive. So collars will be something that we continue to look at. I think the last time we had them was maybe in 2019 that we had used some collars and we've been pretty simple with the swaps since then. So I think most likely what you'll see is the hedge program will continue to be dominated by swaps, but if we see some areas that really make sense to maybe preserve a little more upside and still get nice downside protection through a collar we may do that. But again, we like to stay pretty simple with this. We're not trying to do anything other than provide stability in the distribution and what we found is that swaps tend to do that most effectively.

Okay. Perfect. Thank you all.

Thank you.

Thank you. Your next question comes from the line of William Sams from the Marlin Sams Fund. Your line is open.

Hi. Congratulations on a great year for you. I never dreamed the dividend would go up quite that much. What percent do you hedge on your oil and gas production?

Thank you for the question, William. It really depends. Historically, we have looked to systematically layer in hedges that provide us with around 70% coverage for one year forward. We typically hedge some of our expected volumes two years forward from the time we initiate a hedge. So, we aim for about 70% coverage in the one-year forward range and 30% to 50% coverage in the two-year forward range. We regularly add those hedges as needed.

Okay. That's answers my question.

I would like to comment on the hedging. If you consider the context of our inventory of over 20 years, we are consistently covering 12 months ahead. Therefore, regarding our total resource base, we are largely unhedged.

Okay.

Thank you, William.

Thanks.

There are no further questions at this time. I would like to turn the call back over to CEO and Chairman Mr. Tom Carter.

Well thank you all for joining today. We're excited about what's going on, on our assets. And we look forward to talking with you next quarter.

This now concludes the presentation. You may now disconnect.