Black Stone Minerals, L.P. (BSM) Q4 2021 Earnings Report, Transcript and Summary

Good day and thank you for standing by. Welcome to the Black Stone Minerals Fourth Quarter Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [Operator Instructions]. Please be advised that today's conference is being recorded. [Operator Instructions]. I would now like to hand the conference over to your speaker today, Mr. Evan Kiefer, Vice President of Investor Relations. Mr. Kiefer, the floor is yours.

Thank you, Chris. Good morning to everyone and thank you for joining us either by phone or online for the Black Stone Minerals fourth quarter and full year 2021 earnings conference call. Today's call is being recorded and will be available on our Web site along with the earnings release, which was issued last night. Before we start, we'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 Factor sections from our 2021 10-K, which we expect to file later today. We may refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. A reconciliation of those metrics 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 Web site 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 Legal; Garrett Gremillion, Vice President of Engineering and Geology; and Thad Montgomery, Director of Land. I'll now turn the call over to Tom.

Thank you, Evan. Good morning to everyone on the call. Thanks for joining us today to discuss our fourth quarter and full year '21 financial and operating results. We posted another solid quarter and are entering 2022 with good momentum across our business. Oil and gas prices continued to strengthen in the fourth quarter. As a trend, we benefitted from '21. Realized prices in the fourth quarter were just over $73 per barrel of oil and $5.40 per Mcf gas. On a Boe basis, prices were up 14% from the third quarter and doubled from the levels we saw in the fourth quarter of 2020. Not surprisingly, the more constructive commodity price environment has been positive for overall activity and volumes trends as well. We had 95 rigs operating on our acreage at the end of the year, which is up over 60% from the 59 rigs operating at the end of the third quarter, and has more than doubled the 38 rigs we saw at the end of 2020. Our royalty volumes in the fourth quarter totaled 35.2 MBoe per day, which is up by 7% over the third quarter royalty volumes driven by increases in our Bakken, Louisiana, Haynesville and Midland, Delaware production. Our working interest volumes have continued to trend down in the fourth quarter as our legacy working interest production rolls off from the Shelby Trough wells where we've participated prior to our farmouts of that interest in 2017. As a result, royalty volumes now represent 90% of our total production volumes. Our royalty volumes trended up throughout the year. The average volumes for 2021 were relatively flat to 2020 royalty production levels. So as those of you who have been with us for a while know well, our overall volume growth has been slowed over the past couple of years due to declining natural gas production and our concentrated acreage position in the Shelby Trough, Haynesville/Bossier plays in East Texas. After maintaining very active drilling programs in the area, XTO and BP shut down their Shelby Trough programs in 2019; and in doing so, released the rights to much of the acreage. We made it a top priority to bring in a new operator in the area. And in 2021, we did that through two separate development deals with Aethon Energy. Aethon continues to ramp up its activity in the Shelby Trough. In Angelina County, Texas, two wells are currently producing under our agreement with Aethon and another eight wells are being drilled or completed. In San Augustine County, Aethon is currently drilling three wells under a separate development agreement covering that area. We have also renewed existing and added new farmout agreements covering the area to relieve Black Stone of any direct capital burdens working in. Our overall activity levels with Aethon across the Shelby Trough are expected to increase quickly over the next two years, leading to what may be 20 to 30 wells a year from that area. That will add to our total Haynesville volumes from East Texas and Louisiana over the coming years. The Haynesville has always been an important contributor to our total production mix, and we believe the play is uniquely well positioned to benefit from continued growth in LNG export volumes. So that program is up and running with a very experienced and well capitalized operator. We're working to repeat that success in other areas where we have significant mineral and royalty positions, either by attracting capital to unleash acreage or working with the existing operator to accelerate drilling activity on the acreage. We have prioritized this organic growth strategy for some time now and have added horsepower through our new hires to our team to focus on this effort. Clearly, volumes from new drilling activity on existing acreage provide a higher return to our shareholders than adding volume through acquisitions. We think the organic focus is particularly appropriate in the current high commodity price environment, which enhances economics when we are showing acreage packages to potential operating partners and in our view creates more downside risk when paid -- in our view creates more downside risk when paying for acquisitions. Our extensive footprint in the Austin Chalk is an important component of our growth efforts. As you probably know, we have -- on previous calls, we have been working with existing operators and marketing unleased acreage packages in the area. We continue to make progress on those efforts and are seeing some encouraging results of the initial deals struck last year. Thus far, five wells have been drilled and turned to sales and another two wells are at various stages of drilling or completion under these agreements. Not surprisingly, we've seen some variability across such a large acreage position. And in general, we remain very optimistic that there's a sizable fairway or fairways ripe for development using the latest generation of high intensity completions. And, of course, we're not stopping with the Shelby Trough or Austin Chalk. We're currently actively looking to do other parts of our mineral portfolio that could benefit from this combination of constructive commodity prices and improved technology, and where new development can drive further volume growth. We're optimistic about the years ahead. We have a strong balance sheet, a robust portfolio of growth opportunities and a great team focused on turning these opportunities into additional volumes, all with the goal of returning more cash to our shareholders. With that, I'll turn the call over to Jeff to go through some of the details of the quarter and our outlook for next year.

Okay. Thank you and good morning, everyone. As Tom mentioned, we had another good quarter and ended the year on a high note in terms of both royalty and total production. Royalty production was up 7% from last quarter. Those production gains primarily occurred in our Bakken, Permian and the Louisiana Haynesville acreage. The further good news is that the increase was driven primarily by higher oil volumes, which were up 14% from third quarter levels. A lot of good things happen when new well activity picks up. We benefit from the relatively high production rates in the first month of a well. And since most times we receive an initial check for a well several months after that well actually began producing, we may book several months of historical revenue and production at the same time when we get that first check. That, of course, occurs more often in times of increasing activity which is what we saw in the fourth quarter and specifically what we saw in the Bakken and Permian, which drove up our oil volumes. Prices continued to climb in the fourth quarter, boosting our oil and gas revenues to over $150 million for the quarter. Our oil differentials remained steady at about 95% of WTI where we saw a big divergence in gas prices between the average spot price and the average Henry Hub contract settlement price for the quarter. Normally, those two metrics track very closely. In the fourth quarter, the average spot price was 475 compared to the average settlement price of 583. Portions of our gas production are priced off of each of these. And as a result, our realized gas price of $5.40 was 114% of the daily spot average, that's pretty consistent with what we've seen in prior quarters, it was just 93% of the contract settlement price average. We recorded adjusted EBITDA of $77.6 million for the fourth quarter. That was up slightly from last quarter. And distributable cash flow for the quarter was $71.3 million, also up from last quarter. On the back of those results and the positive momentum going into 2022 that Tom mentioned, we were able to raise our distribution again to $0.27 per common unit. That's an 8% increase from last quarter. Even with that increase, our distribution coverage for the quarter was 1.3x and we retained about $15 million of cash. For the full year, we generated $292 million of adjusted EBITDA from 38,000 Boe per day of total production. Distributions paid for the full year totaled $0.945 per unit and we retained about $70 million for acquisitions and debt repayment. In conjunction with the earnings release, we put out our 2022 guidance yesterday. As we look forward to the full year of 2022, we forecast royalty production to be relatively flat to 2021 levels. We expect to see continued production gains in the Permian and Louisiana Haynesville plays, offset by the natural production declines in the legacy XTO and BP Shelby Trough wells that Tom discussed. Given the expected ramp up in drilling there by Aethon, we expect our Shelby Trough production to return to a growth path later this year. Working interest volumes will continue to decline into 2022, given the existing farmout programs we have in place, including the one with Azul Resources who has joined in the San Augustine Shelby Trough program as a new farmout partner. We expect lease bonus, operating expense and production costs to be roughly in line with 2021 levels. G&A is expected to increase slightly due to just normal cost inflation and some selective hires we've made to drive our organic growth initiatives forward. And while we don't normally give distribution guidance, I will note that cash flows will benefit in 2022 from the step up in our average hedge prices. The fixed prices on our oil hedges move up by about 70% from 2021 levels and hedge gas prices increased by about 16%. And as a final point, our balance sheet remains in great shape and we have ample liquidity. We ended the year with $89 million drawn under our revolver, which has a $400 million borrowing base. And as of Friday, that debt balance was down to 58 million in advance of paying the distributions which happens tomorrow. With that, Chris, we will open the call up for questions.

Thank you, sir. [Operator Instructions]. Our first question comes from Leo Mariani of KeyBanc. Your line is open.

Hi. Good morning here guys. A couple of quick questions here for you. You clearly mentioned that you saw a really nice benefit in the fourth quarter due to I guess what appear to be sort of prior period adjustments. I know there's time lags between when you get the checks for the production, when you actually have to book these volumes here. So could you all quantify that here in the fourth quarter in terms of was it 1,000 barrels a day or just anything like that you could say in terms of kind of what was more prior period volumes versus kind of what the actual maybe run rate volumes were for the quarter here?

Hi, Leo. Good morning. Sure, happy to do that. This is Jeff. So yes, I think just to clarify your point for everyone on the call, I know we mentioned it a bit in the prepared remarks. But we get new wells added across the system all the time. And typically, that operator may take a few months before we get that first check. And so when a new well comes on that we had not seen before and therefore hadn't accrued into our financials, then -- let's say we got that check in December and production actually came on in September. Well, not only are we booking the September production that we saw on that check, but we're going to establish a new accrual for the September through December volumes for that specific well as well. So it can just provide a lot of positive momentum to our overall volumes quarter-over-quarter. And as I mentioned, that happens with greater frequency as activity levels overall are picking up. So we saw about 4,000 Boe a day that we were impacted through new well activity in the fourth quarter.

Okay, that's very helpful. And obviously you guys significantly kind of outperformed your guidance in '21, which you all had actually raised as well earlier in the year, but certainly it's good to see. And when I look at kind of momentum right now on the 95 rigs, just like you said, up 51% versus last quarter, it certainly probably doesn't appear to be slowing down at current commodity prices. So when you look at your guidance for '22, I don't want to put words in your mouth, but I'm assuming that perhaps you're not necessarily assuming some of the same benefits of flush production on the bigger wells, maybe it's more kind of a base production rate. But it seems like with such high activity, you could see something similar in '22, which is getting some of these extra checks on flush production, some of the wells which could make the volumes a little better. Is that kind of maybe a way to think about in '22?

Yes, so let me clarify. So the reason why we might have pretty sizable adjustments related to some of that first check issues is because we only accrue what we can see, right. So we can't make accruals for wells that we don't know about, obviously, but 65,000, 70,000 wells across the system and they weren't added all the time. We don't have direct visibility to those. So we don't get daily production estimates, for example, from producers. So we do our best to accrue volumes. So that's in the actual financials. When we forecast, that's a little different than what we actually accrue for GAAP purposes. And so we try to take into account increasing activity when we forecast. Now, if you look historically, at least in normal periods of activity, we've tended to be a little conservative in our forecast. I think that does come from just not being able to have great visibility into all that new activity. But it's not quite the same thing as when we're adjusting those accruals for new well activity. What I will say, and I know we've said this for a number of years but it's really important, you do have to remember that that Shelby Trough production, as we got into 2019, was about a third of our total production base in this company. And so when BP and XTO stopped, that was a pretty big spinning wheel that stopped spinning. And those wells, because they're jumped back and they're massive wells, hang on for 12 or 18 months. And then you really start to see the meat of the decline curve in those Shelby Trough wells. So that's what we saw in '21 and we think we're still seeing in '22. The good news is, is that with all the activity that Aethon has going on out there, we do expect '22 to be the year where we start to fully offset that decline with the Shelby Trough volumes. But that's going to be in our forecast. That's two plus a day that we view as volume decline just from the Shelby Trough from those legacy wells from '21 to '22. So that colors that forecast a little bit. And obviously in a lot of the other areas, Perm and Bakken, Louisiana Haynesville, we expect to see that continued activity level resulting in higher volumes coming out of those wells.

Okay, that's very, very helpful in terms of describing that dynamic and the guidance for '22. Maybe just last one for you guys here on just M&A. It sounds like maybe you all are being a little bit more cautious given that we're in a higher price environment. And it seemed like the strong preference there internally is to still just try to get a lot of this unleased acreage out there in the portfolio. So maybe just give your thoughts overall on the M&A environment.

Yes. Leo, this is Jeff. I'll start and anyone else can chime in here around our table. But look, I think you basically just summed up our current thinking very well, right. We see a lot of opportunity across the portfolio where we've had success now two times around with the Shelby Trough acreage in East Texas. We're really starting to see some momentum. We're excited about what's going on in the Austin Chalk. And frankly, there is just a lot of areas where we have concentrated acreage positions that we think can really benefit from completion technology and can really -- obviously in the economics look pretty good in this sort of pricing environment. So we're really focusing our efforts and why we brought Carrie on and have added on to her team and that's really her focus. And I will tell you Tom's invigorated about this as I've seen in a long time as there's just a lot of opportunities around the portfolio. To the extent that we can start adding cash flow streams through bringing people onto our existing acreage, we've said this time and time again, that's like doing an acquisition we don't have to pay for it. So when you think about IRRs and how you generate long-term returns for our shareholders, we think that's just a very productive way to do it. And we're fortunate enough to have large contiguous high net positions where you're relevant to the producers that you're talking to in those discussions. And so a lot of stars have to line up for that stuff to work and a lot of hard work has to go into it. But that's where we're focused. We will get back to acquisitions someday, but we think frankly this is the time better spent on chasing those organic deals at the moment.

Okay, great. Makes a lot of sense. Thank you.

Thank you, Leo.

Thank you. Our next question comes from Derrick Whitfield of Stifel. Your line is open.

Good morning all and congrats on your quarter end update.

Hi, Derrick.

Regarding the Austin Chalk, you noted in your prepared remarks that the wells are showing some variability and significantly improved well performance relative to prior generation completions. Can you perhaps speak to the nature of the variability you're seeing? And if it's productivity or production mix related?

Yes, Derrick, this is Tom. I'll speak to it a little bit. The Austin Chalk play has gone through at least four or five different result [ph] cycles over the last several decades. And it is one that is known for a lot of variability. And we are working on our portfolio with operators in areas that have been very active and very productive and very economic in the past with a lot of wells, hundreds of HBP [ph] units that were pretty darn good wells in the last generation without any fracture stimulation in those wells. In addition to that, operators and people want to look in areas that haven't been as successful in the past. And that's generally rock quality and other things like that and trying to put new technology to work out there and see if that works. The variability so far has been more around the areas that didn't work before have not worked as well with the new stimulation. However, and it's early innings but the volume of control is building up rapidly. In the areas where the wells were pretty good before and it's a massive fairway, the wells that have been drilled in those areas, in the areas that were good before and fracture stimulated look tremendous. And there's a ton of inventory just in that area, but we expect to keep working on other areas as well. So the variability has been the areas that were good before, they look pretty darn exciting. But it's challenging and we will continue to do it to expand those areas and areas that haven't worked before.

That makes sense. And it's quite encouraging that you guys are being able at this early point to map that out, so congrats to you guys on that. And then maybe shifting over to the Haynesville with my follow up, can you speak to the importance of your farmout agreement with Azul and your expectation for activity under this agreement? And then perhaps more broadly on Shelby Trough development, could you speak to your timing expectations for the eight wells that are being drilled or completed in Angelina County?

Hi, Derrick. This is Jeff. I'll start. The Azul agreement is just bringing in a new partner, which has resulted in the full breadth of our working interest there farmed out. So it's a new entity, backed by Carnelian, good group of guys, well capitalized, and so we're happy to have those guys in the fold. But again, all of these farmouts that are in place, and we now have three farmout partners, are just there to make sure that a very, very active well program under Aethon and the Shelby Trough continues to be appropriately capitalized, and frankly not capitalized by us, because we're out of the working interest business. So that's just adding another strong partner to that end. And in terms of the Aethon development, obviously, that's an incredibly important program. And what we're seeing is that they were required to drill under that agreement a minimum of five wells in the first program year. In San Augustine, I think they're going to exceed that and probably hit eight, and that eight ramps up to 10 and then eventually to 12. And then on the Angelina side within the next couple of years, that program is supposed to ramp up to 15 wells per year. And so in terms of specific timing of those, they're just keeping track with those program years and in fact exceeding our expectations a little bit. But that's what's kind of got us excited by the -- within a couple of years, the program envisions a minimum of 27 wells per year being drilled across Angelina and San Augustine in just the Shelby Trough. So I think it just highlights why we're so happy that this is Aethon, given they're one of the most prolific Haynesville drillers, seeing their technical wherewithal we think is very, very strong. And these are deep and high pressured wells. You want the right people drilling them. So yes, I think it's going to be a very important relationship going forward. And so far, they've been terrific to work with.

Thanks, Jeff. That makes sense and it's very helpful.

Thanks, Derrick.

Thank you. [Operator Instructions]. Our next question comes from Joseph McKay of Wells Fargo. Your line is open.

Hi. Good morning, guys. Congrats on a great quarter. Just had a little question on the 2022 guidance. In terms of the natural gas cut, the 72% compared to the 74% and kind of 75% level you came at in 2021. Can you just talk about kind of what's driving that and I guess the trajectory of that? Is that kind of a step down we expect to see in 1Q and then hold steady throughout the year, or is that something that you expect to kind of exit the year maybe closer to 70%? Just a little more color around that if you can?

Yes. Sure, Joseph. Thanks for the question. This is Jeff. And then I'm going to let Evan answer the second part of your question. But I think the general step down in gas from 74% to 72%, and obviously the corresponding step up in oil, is just we are -- I know all of our answers tend to circle back to this. But a lot of that is just, the Shelby Trough is 100% dry gas. And so this kind of last year hopefully step down in production volumes in the Shelby Trough is almost completely from gas. And what we're seeing, frankly a little surprisingly, is areas like the Bakken where we're forecasting it to be flat to slightly up whereas a year ago, we would have expected that to be a declining asset. But we've seen more new drilling activity come with higher oil prices. And then, of course, we think that the middle [ph] is going to continue to grow. So that transition a little bit in terms of product mix is really driven by that combination. Shelby Trough continuing to trend down relative to '21 prior to what we think is going to bottom out and start a growth trajectory again, and then just being -- continuing to be optimistic around some of the oilier plays, like the Permian and the Bakken. And I'll let Evan kind of address the mix throughout the year.

Yes, thanks. So this is Evan. Talking about just production and kind of mix throughout the year, overall, we feel a little bit of a step down starting in Q1 and thinking just oil first. Given where we see rig counts and overall activity, we do expect a slight increase in oil volumes kind of throughout the year. And then kind of discussing on the gas side, it really is a Shelby Trough story. We got early in the year the decline in those assets. And as the additional wells come online that Aethon is currently drilling, we see that kind of inflection point more towards the middle and second half of the year as we start to see those growing. So it is an initial step down and then kind of slight increase overall throughout the year, really kind of driving more towards the second half of the year with gas volume growth.

Got you. Thank you. That's helpful. Then just kind of follow up, I wanted to touch on one of the comments around G&A for 2022 in terms of marketing undeveloped acreage. Are there any -- is that any plans beyond kind of the normal course of business stuff, or it's a larger kind of divestiture plans? How are you thinking about proceed use just given the balance sheet is in great shape? And then maybe just kind of following on that, how are you thinking about the payout ratio as you guys move throughout 2022?

Yes. Joseph, it's Tom. There's no divestiture plan. Just because we're being even more selective than we historically have on the acquisition front, that doesn't mean we're in the market to divest any of these assets. What we want to do is take the assets and just generate the absolute maximum amount of cash flow that we can out of them. So look, your point is a very good one. We've been maintaining some coverage just because the business has outperformed and historically, we've used that to pay down debt, obviously at sub $60 million of debt today. Again, we're about to pay the distribution. So that will step up a bit. But we're getting pretty close to zero in terms of total debt on the balance sheet. I think what that means over time is just that you should see payout ratios go up. So with very little debt left to repay, I think the general thinking of the Board, and of course this could change but it's something we talk about every quarter, is that we'll return more of that cash flow to our shareholders through higher distributions. Again, we'll see other things. We do have the preferred outstanding, which we think is a great security and Carlyle has been a wonderful partner. But someday we'll need to think about what to do with that. But in the meantime, I think with the strength of the balance sheet, it just means that the payout ratio goes up.

Got it, all right. That's it for me. Thanks, guys.

Thanks, Joseph. I appreciate it.

Thank you. And I see no further questions in the queue. I will hand the call back over to Tom Carter for closing comments.

Okay. Well, thank you all for joining us today. And we'll talk to you next quarter. Have a good day.

This concludes today's conference call. Thank you all for participating. You may now disconnect. Have a pleasant day.