Black Stone Minerals, L.P. (BSM) Q2 2019 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, and welcome to the Q2 2019 Black Stone Minerals L.P. Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will follow at that time. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to turn the conference over to your host Mr. Brent Collins, Vice President of Investor Relations.

Thank you, Ashley. Good morning to everyone and thank you for joining us either by phone or online for Black Stone Minerals second quarter 2019 earnings conference call. Today's call is being recorded and will be available on our website along with the earnings release which was issued yesterday afternoon. 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 on our press release from yesterday and the Risk Factor section of our 10-Q which will be filed later today. 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 blackstoneminerals.com. Company officials on the call this morning are Tom Carter, Chairman and CEO; Jeff Wood President and CFO; Holbrook Dorn, Senior Vice President of Business Development; Brock Morris, Senior Vice President of Engineering and Geology; and Steve Putman, Senior Vice President and General Counsel. I'll now turn the call over to Tom.

Thanks Brent. Good morning and thank you for joining us today. Yesterday, we announced our results for the second quarter of 2019 which reflects strong operational and financial performance across all our asset base. Our total reported production crossed over to the 50,000 Boe per day for the first time in our history, driven by 19% increase in mineral and royalty production over the first quarter's volumes. On the strength of this record quarter, we're increasing 2019 full year production guidance by approximately 5% to a range of 475,000 Boe per day to 505,000 Boe per day from 45,000 Boe to 48,000 Boe respectively. At the end of the second quarter, we had a total of 101 drilling rigs operating on our acreage of which a third were in the Midland Basin, a third in the Delaware Basin and the remaining third operating across the rest of our asset base. That total number is down somewhat from the end of the first quarter which shouldn't be that surprising to those who have been following the rig count in recent months. While the number of rigs running on us was down a bit, we did have a solid quarter with respect to well additions and permits added. During the quarter, we added 5.25 net wells on our acreage. The largest contributor was the Midland Delaware with two net wells; Haynesville, Bakken, Eagle Ford contributed another 1.3; and the remaining two net wells being added outside of our top four plays. In 2018, we added 21 net wells across our acreage and we're on a pace to meet that level of activity again this year. In terms of permitting activity, we saw 471 horizontal permits added on our acreage during the quarter with 248 of those coming in Midland and Delaware Basins and 138 horizontal permits in total across Bakken, Eagle Ford, Haynesville. Black Stone generated $98 million of distributable cash flow in the second quarter of $0.48 per unit. We are maintaining our distribution at $0.37 per unit which equates to a 1.3 times distribution coverage and roughly $22 million of retained cash. This excess coverage funded $21 million in acquisitions purchased during the quarter as well as about $2 million in share repurchase that were done in that period. Our practice of maintaining some distribution coverage allows us to do things that help improve the business while avoiding incremental debt or extensive equity issuances and we think it makes a lot of sense in the current environment. Before turning the call over to Jeff, I want to say a couple of things about the Shelby Trough. I'm confident that many of you listening on this call are well aware of the challenges that exist in the natural gas markets today. With natural gas prices dipping below $2.20 NM, the economics of even best natural gas plays across the country are strained, Shelby Trough included. As we noted in our press release yesterday, our two operators in the area XTO and BP have recently communicated that they are slowing activity in the play. In the case of XTO, we understand that they would -- will pause drilling for approximately 12 months and focus on completing existing drilled uncompleted wells as they await some incremental gathering and treating capacity in the area. Gross production from Brent Miller, the project XTO operates is currently at 250 MMcf per day and we think it will increase to about 400 MMcf per day as they complete those drilled uncompleted wells over the next year. As for BP, they have made a decision to focus on a relatively small portion of acreage covered by our development agreement with them and our expectation is that their gross production volumes at the year-end will be around 330 MMcf per day. One of the key aspects of our agreement with BP is that, they only hold acreage through continuous drilling. As a result, BP will release approximately interest in 100,000 gross acres that we will now be able to market to other operators. BP has been a great partner and has done a lot to help significantly de-risk this asset base. We are confident in the Shelby Trough's long-term potential, given its proximity to LNG export infrastructure and the anticipated growth in global gas demand. We will now be focusing on attracting new operators to the area to exploit the multi-TCF potential that we have there. Driving activity on our acreage is core to what we do, and the team here is focused on continuing to do just that in the Shelby Trough. With that, I will turn it over to Jeff.

All right. Thank you, Tom, and good morning, everyone. So, we reported total production for the second quarter of 52.2 Boe per day, that's a 12% increase over last quarter. Royalty production specifically was up almost 20% from Q1, while our working interest production continued to decline as planned. The production growth came primarily from the Permian, where we continue to see very strong results across our core Delaware and Midland acreage. Oil prices rebounded in the second quarter, but we did see wider oil differentials. Natural gas prices on the other hand, fell over 16% in the second quarter. We don't report NGLs separately, but those prices fell substantially as well. We include NGL sales as part of our natural gas revenues and as a result our realized natural gas prices were down over 20% quarter-over-quarter. Our hedging program provided some protection against the drop in gas prices. We had realized hedge gains of about $2.9 million for the quarter as well as a large unrealized gain caused by the forward curve for gas moving down over the quarter. We posted approximately $128 million of oil and gas revenue and $6.7 million of lease bonus in the second quarter. Lease bonus was up from Q1, but still at a run rate below our original full year guidance and I will come back to guidance in just a moment. Overall, adjusted EBITDA for the second quarter was $108 million, and as Tom mentioned distributable cash flow for the quarter was $98 million. We generated very healthy distribution coverage for the quarter, and retained sufficient cash to fund our acquisition and repurchase activity without additional borrowings. Because of that, our overall leverage levels and liquidity position remain in great shape. At the end of the quarter, we had $436 million of debt outstanding and our debt to trailing 12-month EBITDAX or our leverage ratio was approximately 1.1 times. We had over $240 million of liquidity available to us at quarter-end based on our current $675 million borrowing base. We paid down over $40 million since quarter end. So, as of now, our revolver balance is under $400 million and the liquidity number has increased to over $290 million to date. As part of the earnings release yesterday afternoon, we announced updated guidance for 2019. We've raised total production guidance by 5% to a midpoint of 49 Boe per day for the full year. As I mentioned earlier, lease bonus continues to trend a bit below our original expectations. As we've said before, that's a part of our business that can be a little lumpy and can be difficult to predict, but based on the trend this year-to-date we're going to move the full year estimate down to $20 million to $30 million. Our current expectations around costs are generally in line with our original guidance with the exception of both DD&A and cash G&A and both of those we now expect to be slightly lower than our original estimates. So overall, we've remained in very strong financial position despite the choppy capital markets and expect to see continued solid operational performance through the year. And so, with that, Ashley, I'll turn it back to you to open the call for questions.

[Operator Instructions] Your first question comes from Phil Stuart with Scotia Howard Weil.

Good morning, guys. Congrats on a good quarter.

Good morning, Philip.

I really appreciate the additional commentary on the Shelby Trough activity from XTO and BPX, particularly on XTO. I guess you all talked about I guess gross production from their main development there, increasing from 250 million cubic feet a day to 400 million cubic feet a day. Just kind of curious well, A, wanted to make sure those numbers were correct? And then B, kind of if you had a time line of that ramp? Is that pretty ratable over the next three or four quarters, or if you guys expect a significant ramp in any one quarter?

Yeah. Hi, Phil, it's Brock Morris. So, yeah, the increase we expect is real. We've currently got some production constraint because of as we mentioned lack of -- or some constraints in the midstream gathering and treating capacity. That's going to be kind of resolved up to about 400 million a day in the coming few months. At the same time, they're going to be completing a number of DUCs and there were a couple of wells currently drilling that will get completed also over the next six to nine months. And as those wells come online, you will see kind of a general growth to that 400 million a day gross rate probably over the next three quarters.

Okay. That's very helpful. And then I guess pivoting to the Permian Basin. Just curious, obviously a good bit of rig activity there and a lot of permitting. Just kind of curious, what your kind of near-term outlook is on the ability of your mineral position to grow production over the six to nine months there? And if that's enough to kind of grow corporate oil volumes while kind of maybe fighting some declines in Eagle Ford and/or Bakken?

Yes. Phil, this is Jeff. Appreciate the question. Yes, look we think we continue to be very well positioned in the Midland and Delaware Basins. So we expect to see continued growth there. As you mentioned, right, I mean, both the Eagle Ford and the Bakken are relatively mature positions for us. I say that and yet they're at least in the Bakken outperforming our expectations here for the past few quarters. So we'll see what happens going forward. Short answer is we expect to continue to see growth. I'd tell you that some of the carnage here in the market over the Permian over the last few days, I think maybe it's been a little bit overblown right. And I'll further say, that things like Concho's announcement of some of the testing they did in the Delaware with some of the testing there is well above anything that we would have assumed in our acquisition assumptions when we're looking at Permian acreage. So we certainly don't think that that condemns the Delaware or the Permian overall in terms of production volumes going forward. So anyway, obviously, we'll come out with updated guidance for 2020 at the beginning of that year and that will include our thoughts on oil production going forward. But we certainly expect to see continued growth out of Permian.

Okay, great. And then I guess one more quick modeling question for me. On oil realizations, are you all expecting oil realizations to potentially pick up a little bit relative to WTI as some of the long haul pipes come online in the next couple of quarters out of the Permian down to the Gulf Coast? Just kind of curious really, if you all are able to piggyback off of the operators' I guess gross take away on the oil side in the Permian?

Yes, Phil again this is Jeff. I mean, that's always a little tough to tell for us, because we don't have perfect visibility as to which of our operators have dedicated pipeline transportation agreements, but maybe avoid some of the specific differentials. What I can say is that you can see it in our financial results that with this quarter specifically that our oil differentials have widened over the past several quarters that's primarily due to the Permian. So just given that, I would expect that we would stand to benefit when pipeline constraints free up and those Permian differentials shrink the TI. That should benefit us just given the fact that we've seen some widening over the past few quarters.

Okay, guys. Make sense. Appreciate the time.

Thanks, Phil.

Your next question comes from Pearce Hammond with Simmons Energy.

Good morning and congrats on a solid Q2. My first question pertains to the acquisition you announced. You acquired roughly $21 million of properties in Q2. And I'm just curious number one, what's the market like right now on acquiring properties? Has it cooled off a little? Is it still pretty tight? So what does that look like? And then secondarily, what can you tell us about the acreage or the acquisitions that you added in the Permian Basin specifically?

Pearce, this is Holbrook. The market has been somewhat volatile. I think you start to feel prices come back a little bit earlier this summer, when people got real nervous about where oil was going and then as oil seems to have found some footing in the mid- to high-50s, the markets tightened up a little bit again. And then you're still seeing a lot of capital moving in both the Midland and Delaware basins. And I think Delaware continues to price at a higher royalty acre metric than the Midland Basin.

Okay, great. And then as far as your specific acquisitions were they more weighted to the Delaware versus the Midland or evenly split?

We frankly really like both basins and we're agnostic and we select for what we think are the best returns or risk reward opportunities. It just so happened probably 80% of our Permian dollars have been spent in the Delaware this year, but that wasn't by design.

Great. And then my follow-up is just picking up on Phil's question from earlier on the Shelby Trough. Thanks for the helpful commentary on the gross production from both XTO and BPX. If you look at your Q2 volumes, gas volume of roughly 226 million cubic feet a day which you reported what percent of that is from XTO and BPX within the Shelby Trough? I'm just trying to get that kind of gross number down to some sort of NRI or net number?

Yeah, Pearce this is Jeff. I mean, our two operators in the Shelby Trough are – I mean those are the two operators. So virtually 100% of our Shelby Trough volumes are XTO and BPX.

Okay, okay. All right, perfect. And that's it for me. Thank you.

Thank you, Pearce.

[Operator Instructions] And your next question comes from Tim Howard with Stifel.

Hi. Thanks for taking my question. So just given what you know in the Shelby Trough and I understand you're anyway trying to release it, but how you're thinking about the production growth outlook into 2020? Can you provide any preliminary comments?

Sure, Tim. I'm going to start and then Tom may want to weigh in a little bit. So, obviously we haven't put guidance out for 2020. What I'll tell you about the Shelby Trough wells is that they come on very strong, and then they tend to stay pretty strong for 12 to 18-plus months. So, really even with a pretty meaningful cessation of activity in that – if that were to happen, you really wouldn't see a lot of rollover in volumes until 2021 and beyond. And then it maybe just a couple more points to that. One is, we don't expect a full cessation of activity nothing else. We know XTO is going to continue to complete their DUCs and that BP will continue to do some drilling activity in what we call the Laceyville area. And then second, look we think this is really unique area such a large contiguous acreage position over a delineated resource play that is majority controlled by a single landowner us. So in a way, we're pretty excited about getting the stack out there. Now in this gas price environment, there's going to be – as we mentioned, there's going to be challenges but this is a long-term resource base that we own in perpetuity and that whether it's tomorrow or a couple of years down the road is going to be a meaningful contributor to Black Stone. And Tom, I don't know if you have additional comments there.

Well, I think that sums it up. But I would just – I would underscore a couple of things you've said. And that is we have a very large position there. We probably won't be making traditional oil and gas leases there. We will be putting it in the hands of operators at appropriate times that will commit capital to develop it and there is over 25 years of well-identified locations out there. And if you look at the general industry macro outlook for gas over the next 20-plus years, it's got a relatively positive outlook. The infrastructure being built along the Gulf Coast for LNG has seen its zenith in activity in 2019, and this will continue to build out over the next two or three years. So how fast we – or slow this gets back into a full-blown drilling cycle is yet to be determined. We are going to be testing the market on near-term and long-term capital. But if something, we own in perpetuity, we have the right to vary royalty rates to the extent that it will affect economics over time i.e. lower royalty in lower gas prices and higher in high ones. And we're very confident that this resource will get developed prudently over time. Does that mean, we may have some slow cycles in the next year or two or three, it very well could but it may not. So it's a little early to say.

That's very helpful. I appreciate that. And then maybe just update us on I'm not sure when BP released the acreage, but have you had conversations with producers or operators today, I mean, understanding that the natural gas macro is challenging but just any kind of initial thoughts you can provide on that re-leasing process?

Well, a couple of comments. We are – with respect to BP their indications of, and then actual termination of activity on four of five blocks happened rather abruptly in the second quarter of this year. And yes, we have had conversations with others. Yes, anybody that is in the gas business is going to have an attraction to this area. Economics are obviously important to everybody. And as I said, at 20-plus wells a year, there's over 20 years of inventory on this acreage that's come back to us. So, whether we ramp up to two or three wells a year over the next couple of years or 20 wells, I think that's going to be driven by the operator and our own expectations. But this thing has been thoroughly delineated both in the intermediate depths as well as the deeper depths. The quality of the reservoir is outstanding. As always, drilling costs are challenging and our industry does a pretty good job of getting a handle on those over time. And so, it's -- we're really early innings in working to reboot this area, and we'll have to just keep working it a while before we can give you much clarity on the next 24 months.

Appreciate that commentary. And then just pivoting to M&A activity, given it seems like there's more stress happening at the upstream industry company level. Are those conversations of royalty deals or overrides being sold down increasing or decreasing just kind of maybe from six months ago?

This is Holbrook. We have not really seen an up-tick in those structures, to be honest with you. There are a couple of public players. Range announced recently that they sold an additional override across in their Washington County acreage or -- and they’ve been all southwest Appalachia. And there have been a few other companies that have looked at it, but there hasn't been a mad rush to market on that front.

Got it. And then, could you help us -- update us on the hedging strategy into 2020 given the low gas environment. I think gas hedges ticked up for 2020, but just kind of how you are thinking about that as we get into year-end and into next year?

Yeah. Tim, this is Jeff. Look, it's been difficult, right? We typically just hedge on a pretty regular basis. We've certainly done that with oil. We're about 50% hedged of our available volumes for 2020 for gas that we're happy to at least be in that position. Count 2020 has been pretty ugly, so we try not to speculate on prices. But again, when they are this low, it makes a little tougher to lock them in. So, we're probably a little behind where we would normally be for 2020 gas at this point, and that's just been price driven. So we will continue to look to be opportunistic around gas hedges from where we are today.

Got it. And then just last one, an update on the buyback program. How you are thinking about that kind of going forward with this given where BSM is trading….

Yeah, I appreciate the question. So, we've got $75 million authorized repurchase program. We've only repurchased about $4 million worth of shares to date over the past couple three quarters under that program. And part of that is just because windows tend to get tight, I would assume. We'll speak with the Board and look to restart that program maybe even put in a 10b5-1 program that would allow us to continue to buy under certain parameters when we're outside of trading windows. But I think at these levels, we think it's a pretty good investment and you may see us act upon that this quarter.

Thanks for the details.

Thanks, Tim.

[Operator Instructions]

Okay. If we don't have any more questions, we thank you all very much for joining us today, and we look forward to speaking with you next quarter.

Ladies and gentlemen, this concludes today's conference. Thank you for your participation and have a wonderful day. You may all disconnect.