Black Stone Minerals LP (BSM) 2022 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Black Stone Minerals First Quarter 2022 Earnings Conference Call. (Operator Instructions)

I would now like to hand the conference over to your speaker today, Evan Kiefer, Vice President of Investor Relations. Please go ahead, sir.

Thank you, Ren, and good morning to everyone. Thank you for joining us either by phone or online for the Black Stone Minerals first 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'll be making forward-looking statements during this call about our plans, expectations and assumptions regarding the 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 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 be found on our website at blackstoneminerals.com.

Joining me on the call today from the company are Jeff Wood, President and Chief Financial Officer; Steve Putman, Senior Vice President, General Counsel; Carrie Clark, Senior Vice President, Land and Commercial; Gary Gremillion, Vice President of Engineering and Geology; and Thad Montgomery, Vice President of Land.

I'll now turn the call over to Tom.

Good morning to all of you and thanks for joining us on the call today for our first quarter financial and operating results. We generated almost $100 million of adjusted EBITDA in the first quarter. That was an increase of 27% over the fourth quarter of '21. Distributable cash flow for the mid-quarter came in at over $92 million. These results benefited from the continued rise in oil and gas properties in the first quarter.

Realized prices were up 16% over the fourth quarter. Drilling activity remained robust during the first quarter. We had 88 rigs operating on our acreage as of March 31. That's down slightly from 95 at the end of last year and higher than the 59 rigs at this time last year. Despite relatively steady rig activity, we saw a decrease in royalty production in the first quarter compared with the last quarter's levels.

Much of the decrease came from Shelby Trough. Aethon is meeting or exceeding its minimum well requirements in the Shelby Trough under our development agreement covering Angelina and San Augustine counties. The timing of when these wells are brought on line can result in some variability in production volumes, especially since these wells typically generate over 20 million cubic feet of gas when turned to sales, and we typically have high royalty interest in them relative to some other wells.

So they make a big difference timing-wise. Overall, we are very excited about the drilling activity in the Shelby Trough. We have separate development agreements with Aethon covering our minerals acreage in Angelina and San Augustine County. In Angelina, Aethon has successfully turned 6 wells to sales, 4 of which came online in April of 2022 and have commenced operations on 4 additional wells.

In San Augustine County, Aethon is currently drilling 2 wells and has another 2 wells awaiting completion operations. From there, our overall activity levels across the Shelby Trough are expected to increase quickly over the next few years, leading to 20 to 30 wells a year in the area drilled by Aethon alone. We remain very happy to have chosen such an experienced and well-capitalized operating partner for this important development area.

Aethon's drilling results thus far in the Shelby Trough have been very encouraging, and we expect this to be a mutually beneficial partnership for many years to come. Further benefiting the volume picture in the area, XTO Energy has resumed drilling 3 wells on Black Stone Shelby Trough acreage in San Augustine County that were originally spud in 2019. As we discussed last quarter, we have fully farmed out all of Black Stone's working interest in the Shelby Trough as well.

We will benefit from the carry provisions in those deals while ensuring that we have no ongoing capital burdens associated with Aethon's aggressive development program. Recent world events have highlighted the global strategic importance of U.S. gas reserves, and we believe the Haynesville Shale is the best positioned play to benefit from continued growth in LNG export volumes over time.

I've discussed over the past several calls our ongoing efforts to bring additional operator capital onto our extensive minerals in East Texas. Last year, we entered into agreements with several operators to drill Austin Chalk wells in East Texas. These operators use high-intensity completions in an area where prior generations of un-stimulated wells yielded solid results.

The outcome of that test program was very encouraging and several of our key operators in the area have now committed to rig contracts for ongoing development of the field. Currently, 4 operators are actively engaged in redevelopment of the field with 2 rigs running continuously in the play. To-date, 7 wells with modern completions are now producing in the area, an additional 5 are currently either being drilled or completed.

We also remain engaged with additional potential operators to commence development on surrounding acreage. Things continue to move in the right direction in this important acreage for Black Stone, and we are working hard to create a scenario where multiple operators are drilling multiple wells per year in the area. We are nicely positioned with key organic growth projects ramping up, a very constructive pricing environment and a leverage ratio of 0.2x.

That combination of factors allowed for sizable distribution increases announced last week. The $0.40 per unit or $1.60 annualized is the highest distribution level since our IPO in 2015. High prices certainly contributed to that, but we were also able to increase our payout ratio given our very low debt balances and an increasing line of sight on volume growth going forward. We are excited that the hard work through the down cycle has enabled us to come back even stronger and return more cash to our shareholders.

With that, I'll turn it over to Jeff to go through some of the details of the quarter.

Well, thank you, Tom, and good morning, everyone. After several consecutive quarters of production growth, our oil and gas volumes came in a little bit lower in the first quarter. The royalty volumes in the first quarter totaled [29,600] BOE per day, that was down 16% relative to fourth quarter royalty volumes. As Tom mentioned, there were some high net Shelby Trough wells that returned to sales just after the end of the quarter.

And in addition, XTO shut in some existing production in the Shelby Trough as it resumed drilling operations on 3 wells in San Augustine County. Both of those factors contributed to the fall off in our gas volumes. The decrease in oil volumes was primarily a result of lower suspended revenue volumes received in this quarter as compared to last quarter.

Our staff successfully worked with producers in the second half of last year to release suspended production volumes across our mineral position and particularly in the Permian and the Bakken, which, as we mentioned on the last call, increased reported oil and gas volumes by almost 4,000 BOE per day in the fourth quarter.

Given the temporary nature of these items and combined with the generally positive industry environment and the ramp-up in activity we expect to see in the Haynesville and Austin Chalk through our organic growth programs, we expect that growth trajectory to resume throughout the year, and we're sticking to our original production guidance for the full year of 34,000 to 37,000 BOE per day.

Spot prices and our differentials both improved in the first quarter, resulting in realized prices for BOE of over $51 per barrel. That's a 16% improvement over what we saw last quarter. Combined with higher hedge settlement prices, our total oil and gas revenues rose by 18% over the fourth quarter of last year. Our financial results also benefited from a very solid quarter of lease bonus at almost $5 million.

Cash operating expenses were generally in line with expectations so that higher revenues translated into higher adjusted EBITDA and distributable cash flow as well. Our DCF per unit for the quarter rose by $0.10.

As Tom said, with our low debt balance and solid progress on our organic growth efforts, our Board of Directors supported paying out a much higher percentage of our DCF to our shareholders for the first quarter. That distribution of $0.40 per quarter this quarter -- per unit this quarter represents a 48% increase over the distribution with respect to the fourth quarter of 2021.

Turning to the balance sheet, our total debt balance was $69 million at the end of the quarter and is down further to just $44 million today. The borrowing base on our revolving credit facility was reaffirmed at $400 million last month. We could have pushed that number higher. But frankly, with such little debt outstanding, we elected to maintain it at that $400 million level.

With that, Ren, we will turn the call over for questions, please.

(Operator Instructions) Your first question comes from the line of Leo Mariani from KeyBanc.

First off, I was hoping maybe you could quantify a little bit the impact of those first quarter shut-ins that you saw. It sounds like that definitely was a big contributor to the lower volumes this quarter?

So this is Evan, and I'll start on that. So with XTO drilling those 3 wells that Jeff mentioned, we think the shut-in impact of that just in Q1 alone is going to be about 500 BOE a day, maybe a little bit above that, but kind of in that range for the Q1 impact.

Okay. And I guess just wanted to kind of follow-up a little bit on one of the prepared comments. If I sort of heard your comments correctly, Jeff, I think you kind of said that you expected first quarter to kind of be at the bottom on production for the year. And then you expected to see volumes kind of start to ramp here in Q2 for the rest of the year as the activity kicks in, in the Haynesville and Chalk. Is that generally right?

Yes, I think that's generally right. If you look at just what the guidance would imply, we would expect that that production would climb up to that mid-30s range for the rest of the year and hopefully, with a little bit of a growth trajectory on to that.

Okay. And then I guess also, could you all comment on sort of the current M&A environment? You're currently kind of rapidly paying down the debt here. As you look at the landscape just in a high price environment, are deals just still kind of pricey out there right now?

Yes. Look, there's a lot of deals, I think, coming over the [transom] that doesn't really surprise us, right? If you had assets that you were sitting on through the downturn and all of a sudden, oil and gas popped up to $107, it's probably a good time to sell it. So we are remaining, I would say, very cautious around our M&A activity. The team is really highly focused on what we think are just much higher return projects, right?

To the extent that we can bring producers on to existing acreage that we already own, that's an acquisition we don't have to pay for right, a new cash flow stream. And frankly, in this price environment, we do see more risk in doing deals because there's just almost definitionally more downside to prices at these levels.

So I think you're going to see us remain pretty quiet on the M&A front and stay very, very focused on driving more activity to existing acreage. And then we'll get back to M&A maybe once things tend to normalize a bit.

Yes. I mean it sounded like you all were fairly confident that you can probably maybe get some new operators in the Chalk. I know you've got a big position over there. But given the successful results and these prices, I would think guys would want to get out there in drill?

Yes. I mean, that's what we're seeing. I mean, the good news is, right, you've already seen this translation from a test well program to those operators who had existing physicians already now committing to rig contracts to start to ramp up development, and we are working very hard not only to help spur additional activity from existing producers in the area, but then also, of course, to bring in new operators to surrounding acreage that's unleased at the moment. But yes, it's -- I mean the iron is hot, right? This is the time to strike on all that.

Your next question comes from the line of Derrick Whitfield from Stifel.

With my first question, I wanted to focus on the Austin Chalk. In your prepared remarks, you noted the 3-well test program in the book when filled demonstrating greatly improved production rate. Could you offer some color on the degree of performance you're seeing in these results had in comparison to past results?

Sure, so this is Gary Gremillion in engineering. So the free test well program included a well by Navidad called Hooper over 5 months. That well has made 1.25 Bcf of gas, 218,000 barrels. The second well, the [LR], which was a good infill test for the main field, it's been producing for 2 months with some very encouraging rates.

The third well, the [MAN] has been producing for 3 months and is also better than the un-stimulated offsets for sure. So there's a couple more wells that are coming online. The oldest well with the newer vintage completion in the field has been producing for 25 months. That well has cumed 4.3 Bs of gas, 625,000 barrels. So with the older producers still hanging in there and producing at really healthy rates, 4 million a day, over 1,000 barrels of condensate a day, we're very encouraged by what we're seeing.

Great. And then shifting over to the Haynesville, could you comment on the expected timing of completions with the 3 XTO wells and if you're expecting additional activity beyond those 2 wells from that deal?

So we -- XTO is finishing drilling the third well at the moment. I actually am unsure of their completion schedule for those 3 wells, but we would expect that they'd be on before year-end. And then my understanding is that they're going to kind of use that area in the Haynesville as a place to kind of place rigs when they can, and it's available on their drill schedule.

Great. And so -- go ahead, please.

I was just going to tell you -- this is Jeff. We haven't gotten any specific new drill schedule timing from XTO. So Gary is exactly right. We think that this could be kind of a swing play for them. They may see -- move rigs around from Shelby County into here and back and forth. But there's no specific drill schedule at this time for XTO in the area.

And Jeff, if I could just one clarification question on oil for the benefit of modeling. When we think about Q2 oil production and really think about in light of the impacts noted during Q1 and recent events in the Bakken. Could you offer some directional guidance on how to think about Q2, i.e., flat up, down, et cetera, versus Q1?

Yes, I mean I would say we would hope that oil volumes would recover a bit in Q2 from Q1. I would point out, again, as I mentioned in my prepared remarks that that -- the quantum of oil that we saw, Permian and Bakken from the suspense work that the team here did through the end of last year propped up Q4 oil volumes specifically. So I wouldn't expect that we would see that level again. But yes, we're certainly expecting to see a little bit better oil volumes in Q2 than what we recognized this quarter.

(Operator Instructions) Your next question comes from the line of Ken Reese from Sagepoint.

I'd like to step away from the micro for a while and just kind of look at some of the macro things that have been drawing on. I like your analysis on the current backwardation in oil and gas. And to that point, if senior management across energy companies right now, if their thought is to constrain increased production, to keep prices high, I'm wondering why you put these hedges in?

And if you could talk about the hedging and what -- how it's affect the earnings, I would appreciate that. As you know, Canterra had a [blowup] party yesterday. Canterra reports tomorrow they're unhedged as well. So I'd like your thoughts.

Yes. Ken, this is Jeff. I'll start on that. Look, as anyone who's followed the company for a long time knows, we have been consistent hedgers. And so for example, that benefited us greatly in 2021 and hampered result -- I mean sorry, in '20 and hampered results in '21. But what it's done is just created some stability to our cash flow stream that it would otherwise be more volatile.

And what our Board has indicated and our Board is comprised almost entirely of large shareholders of Black Stone is that they appreciate that consistency as opposed to just saying, hey, we're going to be a proxy for lower 48 production and fully swing with prices. So it's just -- it's a corporate philosophy. So yes, undoubtedly, results would have been higher. You can see that in the release, had we not put hedges in, but it's benefited us in other categories as well.

And I don't know, I mean in terms of your opening statement that producers are self-constraining just to keep prices high, I don't know that I fully agree with that. There's capital constraints in the industry. We are seeing pickups in rig activity. There's obviously a lot of factors that go into supply and demand, and we don't presume to be smart enough to be better at predicting those than the people that are buying and selling across the curve every day.

Yes, it's just a corporate philosophy issue for us, and it's what we've done consistently for years, it shouldn't surprise investors and sometimes we benefit and sometimes we get hurt.

What percentage of your production is hedged?

We're about -- we're probably 65% to 70% hedged for '22 and probably in the 10% to 20% hedge for '23 as we stand here today.

(Operator Instructions) Your next question comes from the line of T.J. Schultz from RBC Capital.

Just the one question for me on the distribution, given the increase that we had this quarter, is the plan moving forward to maintain a higher payout ratio as volumes improve, assuming prices stay elevated or do you expect to maintain the current level and just build more cash?

This is Tom. I would say that -- generally speaking, if we can continue to have confidence in flat to growing production and keeping -- we already have low debt balances, then we think moving to a higher payout ratio as long as we have continuity of sustaining those higher distributions and growing them in the future. We will continue to lower our coverage ratio as long as we're not creating excess volatility.

Okay. But is the overarching goal to have a smooth and growing distribution rather than kind of purely variable?

Absolutely.

(Operator Instructions) Your next question comes from the line of Trafford Lamar from Raymond James.

Just one quick question on the lease bonus payments from 1Q, I saw that it more than doubled 4Q, and it was based in the Wolfcamp. Was that a factor of existing leases coming up for release or is that unleased land -- or majority unleased lands being leased?

This is Thad. The majority of that lease bonus came from leases that expired because of the downturn in '20, just not a lot of activity. They expired under their own terms, and we were able to release them quickly, lease them again quickly. One was to Diamondback and another was a small private equity company in midland camp.

(Operator Instructions)

Okay, if there aren't any further questions, we thank you all for joining us today, and we look forward to talking with you again in the future.

Ladies and gentlemen, this concludes today's conference call. Thank you for participating. You may now disconnect.