Black Stone Minerals LP (BSM) 2020 Q2 法說會逐字稿

Good morning. My name is Tia, and I will be the conference operator today. At this time, I would like to welcome everyone to the Second Quarter 2020 Black Stone Minerals Earnings Conference. (Operator Instructions) At this time, I would like to turn the conference over to Evan Kiefer, Director of Investor Relations. Please go ahead.

Thank you, Tia. Good morning, everyone, and thank you for joining us either by phone or online for the Black Stone Minerals Second Quarter 2020 Earnings Conference Call. Today's call is being recorded and will be available on our website with the earnings release that 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 will cause actual results to differ or can cause 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 in the Risk Factors section in 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. Reconciliations 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 from the company are Tom Carter, Chairman and CEO; Jeff Wood, President and Chief Financial Officer; Steve Putman, Senior Vice President, General Counsel; and Gary Gremillion, Director of Engineering. Now I'll turn the call over to Tom.

Thanks, Evan. Good morning to everyone on the call, and thank you for joining us today. I want to start the call once again by saying, we hope that your families are healthy and doing well as we all manage through this difficult period. I also want to thank our employees for continuing to perform at such a high level while taking the necessary steps to ensure we do our part to limit the spread of this virus. It's been a very busy quarter at Black Stone as we grapple with the impacts of lower commodity prices, reduced producer activity and constrained capital and credit markets. We've responded with aggressive actions to lower our internal costs, significantly reduced outstanding debt and intensified our efforts to drive new activity on our existing acreage.

Before getting into some of the specific steps taken in pursuit of these goals, I'll quickly review the environment we are facing right now. Broadly across our acreage, we've seen a 40% to 50% decrease from last quarter in terms of permitting activity, new well adds and active rigs. We added 2.9 net wells during the second quarter, down 25% from last quarter. Not surprisingly, the decrease was most pronounced in the Midland and Delaware basins in the Permian, where we added 0.8 net wells in the second quarter compared to 1.6 last quarter. At the end of the second quarter, we had a total of 29 drilling rigs operating on our acreage, down from 50 at the end of the first quarter and from about 100 operating on our acreage at this time last year. As with new well additions, the majority of the decrease in the rig activity is attributable to the Midland and Delaware area.

On our last call in May, we discussed our initial steps in responding to the industry downturn, including our meaningful reduction in G&A expenses, reduced distributions and initial success in restarting development in our Shelby Trough Haynesville/Bossier play in East Texas. We built on those steps in the second quarter to further strengthen our balance sheet and to offset some of the expected production declines.

In early June, we announced the sale of 2 asset packages in the Permian. Both of those transactions closed in July, and brought in net cash proceeds of $150 million. That cash, together with the retained free cash flow from our operations, enabled us to reduce total debt by over $230 million or 60% from the end of the first quarter of this year.

Our outstanding debt as of July 31st was down to $153 million. While it's been a challenge -- it's been challenging to find many silver linings lately. One of them is the more constructive outlook for natural gas prices, with several of our major equity research firms calling for gas prices well above the strip for 2021. Against that backdrop, we've made significant progress in developing -- in development activity in the Shelby Trough.

In May, we signed a new development agreement with Aethon Energy covering the western side of the Shelby Trough, that arrangement is proceeding as planned, and we expect the first well under the program to be spud in October. Aethon has already devoted its considerable land, geology and engineering resources to this development plan for the area, and we're excited to have them as a partner in this important area.

We've also made progress during the quarter with respect to the eastern side of the play in San Augustine County. We were able to work with XTO Energy to incentivize them to complete and turned to sales 31 drilled, but uncompleted wells or DUCs that were spud in late 2018 and '19. These are expected to begin coming online later this year, with the full 13 turn to sales by the end of the first quarter of 2021.

We continue to work with XTO and other potential operators to move beyond completing DUCs and start drilling activity in the eastern side of the Shelby Trough play. Those long-term development deals take time, but we are very focused on it. And are optimistic that we can get something done, particularly as some of those -- if some of those expectations around higher gas prices start to appear in the forward strip.

The reward for these process steps on balance sheet strength and future development activity is our ability to return more cash flow to the unitholders. We made a difficult, but prudent decision last quarter to reduce distributions and to retain more of our cash flow. With the lower debt balance, our Board felt, our Directors felt comfortable increasing our payout ratio. We believe that $0.15 per unit for the second quarter balances our goal to provide a strong cash return to investors with our ability to continue reducing absolute debt levels going forward. Even as we expect our production to contract through the rest of the year as indicated by our revised guidance.

Overall, I'm very pleased with the progress we have made in a number of important areas. And with that, I'll turn the call over to Jeff.

Thank you, Tom, and good morning, everyone. We generated 34,000 BOE per day of mineral and royalty production in the second quarter, down 7% from last quarter and generated 42.6 MBOE per day in total production volumes. We benefited in the second quarter as we normally do from a wedge of checks received during the quarter for production that we had not previously accrued. As a normal benefit from owning such a large mineral portfolio, and it helped to offset some of the production declines and curtailments we experienced in the quarter. We expect that benefit to lessen in the coming quarters as the lower rig count should result in fewer of these new checks representing prior periods. And that expectation is incorporated into the revised guidance that I'll discuss here in a moment.

We reported $72.4 million of adjusted EBITDA for the second quarter. That's actually up slightly from what we reported in Q1. Distributable cash flow for the quarter was $64.4 million, down just slightly from last quarter. And at the $0.15 per unit distribution that we announced for the second quarter, that represents coverage of approximately 2.1x.

As Tom mentioned, we have made great strides in reducing our outstanding debt during the year, a $153 million outstanding as of July 31 represents a reduction of 58% in total debt since the beginning of this year. We are maintaining a healthy liquidity cushion relative to our borrowing base, which was lowered slightly in July to $430 million in conjunction with the closing of the 2 asset sale transactions. Our total liquidity as of the end of July was approximately $280 million.

We did update certain of our guidance measures for 2020 in the earnings release yesterday afternoon. We lowered total production guidance for the full year by approximately 4% and the expected production mix is now weighted more towards gas. This should come as no surprise given that much of the shut-ins and the rig count declines have been focused in oilier plays like the Midland Delaware and the Bakken. We are building in continued shut-ins and reflecting the overall decrease in permitting and rig activity in that revised production range, which implies production levels in the back half of 2020 in the mid 30,000 BOE per day range. And with that, I just want to caution all of you that even in normal times, a large diverse mineral and royalty position is hard to forecast, and it's even harder in times like this of rapid change. So this is our best look as of now with limited information as a nonoperator. And if anything meaningfully changes in our outlook, we'll provide further update.

We also lowered our lease bonus guidance from the original range of $20 million to $30 million to a revised estimate of under $10 million for the year. We are not seeing much in the way of operators' willingness or ability to pay large upfront bonus payments, and we expect that trend to continue through the remainder of the year. The other updates are pretty self-explanatory. We expect slightly lower lease operating costs and a slightly higher rate for production and ad valorem taxes, given there is a fixed component to that metric.

We did not make any revisions to our G&A guidance. We are still tracking to meet our reduced -- our G&A reduction targets for the year as reflected in our original guidance of $39 million to $43 million. Total G&A through the first half of 2020 was $23.4 million, but I'll note that we did incur about $5 million of restructuring charges in the first quarter that ran through G&A. So we're making continued progress there. That's as a result of our smaller team working that much harder. So I want to join Tom in recognizing our employees for accomplishing so many important initiatives during the quarter, and for doing so in a safe and responsible manner while we adjust to continue working remotely. Tia, with that, I will open the call to questions.

(Operator Instructions) And the first question will come from Steven Dechert with KeyBanc.

Just want to get a sense of the level of shut-ins that you guys might have had in the second quarter?

Well, so Steven, this is Jeff. We're modeling about 30% with a lot of that concentrated in the Bakken. That's been the sort of the poster child for shut-ins in the second quarter. We are seeing more of those come online, and we expect that to continue through the year. But in making our estimates for this quarter, and then looking at the revised guidance levels, it's at around those levels and then assuming they generally start to come on through the remainder of the year.

Got it. And then just the question here. With this nice debt paydown that you guys have had recently, is there sort of a plan in place to get the amount of cash flow you're paying out closer to 100%?

Well, again, this is Jeff. And Tom may want to weigh in on this as well. Look, as we kind of mentioned in the prepared comments, right, what we're trying to do right now is balance a nice return for our investors at these levels with the idea that we could continue to pay down debt. We don't know how this is all -- the way the world is going to turn over the next 12 to 24 months. So we're going to continue to be cautious and prioritize the balance sheet. But obviously, with the significant pay down that we had in recent months here, we felt more comfortable raising the payout ratio. I think the idea on this $0.15 is that, that should be a sustainable level. And now of course, we're not variable until we are in these -- in this sort of environment. But we'd like to provide as much certainty and stability around that distribution. We just think that's meaningful to our investor group. So that's certainly the intention. And that given the expected some expected production declines and some rollover in hedges. That probably does require that the payout ratio creeps up a bit over time. I don't know that we would get to 100 because I still like the idea of retaining some cash flow from debt repayment or share repurchases or acquisitions down the road or whatever it may be. But I think you can see that, we'd be comfortable increasing that payout ratio.

The next question will come from Brian Downey with Citigroup.

I guess given the recent Shelby Trough development and incentive agreements that you recapped, could you discuss directionally where you see your natural gas volumes trending into next year? Working interest volumes continue to decline, but trying to get a better sense for the other benefits that should mainly impact next year given the activity cadence you laid out there?

Yes. Brian, thanks for the question. This is Jeff. Look, generally, it's going to be a little early, right, the Aethon program will ramp up over the course of 2021 and then step up further as we get into 2022. Obviously, we haven't put any production guidance as far forward as 2021. That's frankly tough to look out that far at the moment. But if you just look at royalty and mineral and royalty volumes, we should -- we're going to be offsetting declines in those Shelby Trough, but these new volumes will certainly be offsetting that decline working volumes which are almost exclusively gas will continue to decline just because, again, we haven't booked capital under that business since 2017. So not trying to skirt your question here, Brian, but as we look into '21, we're going to have a lot of positive things going on in gas. It's really just going to depend on sort of the more general level of activity across a lot of the other plays, too, as to whether we are fully arresting that decline or starting to grow gas as we get into later reaches of 2021.

Jeff, I'd just add that, we're working not only the Shelby Trough. We're also working in Louisiana in the Haynesville, but we're also working on other plays as well. And we have every hope and expectation of growing our production as we can get some of these projects spooled up, but it does take time. But we're working very hard on it, and we expect some production growth eventually once we move through this cycle.

Great. Obviously, you think these 2 agreements recently, but any additional comments on sort of what you're seeing compared to commentary from last quarter on the operator attitudes towards gas acreage?

I guess I would say that there is -- there's still a lot of uncertainty on operators on any kind of activity right now. Certainly, the industry is getting more comfortable with gas, but I think gas has got quite a ways to go yet. I think most people think LNG exports are still ways off. And so I think we're just -- we're being very cautious about getting too far out in front of what we expect. But we do see a good long-term outlook for gas.

The next question will come from TJ Schultz with RBC Capital Markets.

Outside of completing the 13 DUCs. You mentioned pursuing deals in the Eastern Shelby Trough and that does take time. Is there any notable reason why you were able to move forward with the development deal in Angelina County, but it's taking more time in San Augustine, or is it just producer-specific plans? And is there a gas price you're looking for that moves those discussions forward?

I'll give a quick answer on that. It mostly has to do with our contractual relations with our operator in the eastern part of the play, and we are currently about to reach a point in our contract where we can begin to look at bringing in additional operators out there. In the event the existing operators don't want to develop at the pace that we're going to try to create out there. So it has to do with specific contracts. And I'll just say that we're working pretty hard to regenerate that area as well, and we hope to have some definitive things to say about that before too long.

Okay. When do you reach the point to -- with other operators, or you can reach out to other operators?

Well, it's basically this month.

Okay. Understood. Just lastly on the distribution again. Just trying to think of it in the context of M&A, really, how big a factor does the M&A market play into, say, your payout ratio. I know you're not variable per se. But is there a view that maybe you move the payout ratio down in periods where there's a more active M&A market, or it just generally, how you're thinking about financing acquisitions?

Yes, TJ, this is Jeff. Look, that's a great point. I think it's something that will think about really hard with the Board, once we get through this kind of period of greater turbulence right now what we're really focused on is kind of balance sheet first, and then returning sufficient cash to our investors and then really trying to get as much as we can out of the existing asset base, right? I mean to the extent that we can get a new play, whether it's the chalk or the other part of the Shelby Trough, like that's basically for us, it's an acquisition that you don't have to pay for, right? It's a new stream of cash flows that you don't have an upfront payment on. So that's really what we're focused on.

If the world starts to really brighten, and the banking market loosens up a little bit and capital becomes a little more available, and we can supplement an active M&A program with a little more retained cash flow, then I think that's certainly something that we'll discuss. But right now, I think it's really focused more on balance sheet and current assets and then maintaining the right payout ratio to make sure we're taking care of those 2 things.

The next question will come from Pearce Hammond with Simmons Energy.

First question is, Jeff, what are your latest thoughts on hedging?

Pearce. So as you know, we put in a pretty significant round of hedges a little earlier this year. I'd say, we'll just continue to be opportunistic around adding levels. I mean, obviously, levels for '21 have improved and hopefully continue to improve. So I think that we will look, as we always do, to systematically build our hedge portfolio over the course of the year. And then at some point, as we get closer towards the end of the year, look to potentially adding some initial 22 hedges. So we're going to continue to be programmatic about this. It served us very, very well in this quarter with a lot of protection through our hedges. And so I think we're just going to continue that corporate philosophy. And it all just kind of goes into that comment, I made earlier about trying to provide a decent level of visibility and certainty around the distribution.

Great. And then my follow-up, and this touches on an earlier question pertaining to the balance sheet. But first of all, congratulations on the success you've made on the balance sheet. What metrics are you looking at to define? Hey, we think the balance sheet is in good shape because the leverage ratio right now is low. But are you looking more at just the absolute level of that? Where I'm going with this is just to better understand when you feel like the balance sheets at the level to support a higher payout similar to what someone was asking earlier.

Pearce, this is Jeff. I'll start with that, and then you're welcome to chime in. Look, we have historically looked at a number of things, right? So it's absolute debt levels. It's degree of cushion between outstanding borrowings and the borrowing base, and then we pay a lot of attention to our leverage ratio as well so debt to trailing EBITDA. And we continue to look at all of those things. I think what I'd say is that in times like this, where you've got a corporate banking market that is really pulling their talents in pretty dramatically. So you don't know if a lender that is there for you today. It's going to be there for you tomorrow.

We've got a great bank group that has been with us for years and years. So I feel very comfortable with that group, but it's just a difficult and changing time. So I think the perspective right now is on all of those things with just an added layer of conservatism. So again, we think about absolute debt levels. We think a lot about what's the cushion to the existing borrowing base because, again, that borrowing basis is -- can be determined by a lot of things, including what sort of advance rate that banks are willing to give you, and that can change over time.

So we're just being generally more conservative across the board. I don't think there's some specific target, I can point you to right now that says man, as soon as we hit 0.5x on our leverage ratio, we're going to open things back up. It's just going to have to continue to monitor the environment. And our attitude is going to continue to prioritize balance sheet just given how rough the times are.

The next question will come from Derrick Whitfield with Stifel.

Certainly want to commend you guys on offering forward guidance in this challenging environment and for your success in driving activity across your Shelby Trough position. For my first question, I wanted to follow-up on your curtailments. Could you possibly quantify the curtailments in the Bakken and approximate barrels per day for Q2?

Derrick, I don't have that off the top of my head. We can follow-up with you on that. Or maybe we could even -- can you give me just 2 seconds.

And we can follow-up if needed. I can move on.

I know that's top 30% the Bakken, was trying to find...

Yes, I think if you look, Derrick, I would think that that's probably in the 1.3 to 1.5 MBOE a day, or just kind of estimate of what those shut-ins probably meant for the Bakken.

Perfect. And then as my second question, regarding your lease bonus guidance, I understand and certainly appreciate the direction you guys have taken that. With that said, could you speak to potential meaningful unleased exposure that you have in gas basins outside of the Haynesville that could convert in a more bullish gas environment?

Sure. This is Jeff, and we'll see who else wants to comment. But I mean, we've got tremendous acreage focused on gas. Tom mentioned the chalk and the work that we're trying to do there. We have got hundreds of thousands of acres across the chalk in Texas and Louisiana. So we talked before, there's a company that's drilled a very nice well on the East Texas side of the chalk continues to be a very, very nice performing well, and that was using modern -- one of the first really used modern completion techniques in that area of the chalk. And so we're encouraged by that, but it's -- obviously, it's 1 well, and it's very early. But I'll tell you, I just don't know. It's tough to say right now how that could translate into lease bonus. What we found to be very successful in times like this is that you need to be more of a partner with your operators now than maybe you do in really good times where capital is more available. So what we found in ways to be successful, especially in areas where we have such large contiguous acreage positions is to say to producers, let us work with you truly as a partner and let's -- maybe we'll lessen or forego upfront bonuses in exchange for a more identified development program.

Ultimately, we would rather see revenues through royalties than through lease bonus. And so we make that trade-off sometimes and frankly, more often in times like this and more often, where we have really large positions where that development plan can be even more meaningful. So look, that's a circuitous route around your question. I think as gas prices tick up, you probably see some spots, that pop up where we do see a bit of a resurgence in lease bonus, but our focus is really on mineral and royalty volumes more than it is on lease bonus.

Next question is from Phil Stuart with Scotiabank.

I guess my first question is on natural gas production for 2Q. It was held up, I guess, a little bit better than we were expecting. Just kind of curious what the biggest drivers of that were? Was it -- is it just kind of the lower declines that the wells in the Shelby Trough area typically exhibit over the first 12 to 18 months? Or was there maybe some contribution from another gas play within the portfolio that kind of helped improve that number?

Phil, this is Jeff. In the second quarter specifically, we saw a little bit more of a spike than we were expecting in our Louisiana/Haynesville volumes. That was probably the biggest single contributor to our gas volumes exceeding expectations a bit. I guess what I'd say is that, that's just -- that's just part of owning such a giant portfolio of acreage, right? You just hope that you're going to get a shark fin from something as you go forward. And this time, it was Louisiana/Haynesville more than others. I don't know that, that's -- portends to anything specifically other than just in a more constructive gas environment, which we've seen, we would hope that activity broadly starts to come back a bit, and we saw that in the second quarter, at least in the Louisiana/Haynesville.

Okay. Great. And then I guess my follow-up, just a clarification on the XTO deal for the 13 DUCs. I think the agreement is that they have to complete all 13 DUCs to get the royalty relief. Is that the case? I just wanted to clarify that.

That's correct. So they need to not just complete, but turn to sales by the end of the first quarter of next year for those 13 DUCs.

Okay. Great. And then I guess maybe just 1 more quick follow-up on that. If we take 1Q '21 as the starting point, assuming that those 13 DUCs are turned to sales in 1Q '21. Do you think those 13 DUCs plus the line of sight that you have on the Aethon wells that will be completed? Do you think that would be enough to hold Shelby Trough production flat kind of 1Q '21 to 1Q '22? Just kind of trying to think of it on an asset level basis.

Yes. Phil, unfortunately, I think we're just going to have to hopefully be in a position to give '21 guidance on our normal time frame, but it's just tough for me. Right now to comment on that, to be honest.

The one comment I would make is, we are spending a lot of effort trying to get additional drilling going on in the eastern side of the play. And we hope to get that done in '21.

(Operator Instructions) And at this time, there are no further questions, I'd like to turn the conference back over to Tom Carter for any closing comments.

Well, thank you all for joining us today, and we look forward to speaking with you next quarter. And good luck to everyone. Thank you so much.

Ladies and gentlemen, thank you for participating in today's conference call. You may now disconnect.