Black Stone Minerals, L.P. (BSM) Q2 2020 Earnings Report, Transcript and Summary

Good morning. My name is Sia and I will be the conference operator today. At this time, I would like welcome everyone to the second quarter 2020 Black Stone Minerals earnings conference. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions]. Thank you. At this time, I would like to turn the conference over to Evan Kiefer, of Investor Relations. Please go ahead.

Thank you Sia. Good morning to 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 would 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 our actual results to differ or can cause actual results 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 10-Q which we 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. 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 and Garrett Gremillion, Director of Engineering. No I would 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 has been a very busy quarter at Black Stone as we grapple with the impacts of lower commodity prices and reduced producer activity and constrained capital and credit markets. We 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 will quickly review the environment we are facing right now. Broadly across our acreage, we have 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 and 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 two 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 31 was down to $153 million. While it's been challenging to find many silver linings lately, one of them is a 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 made significant progress 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 Energy has already devoted considerable land, geology and engineering resources to its development plan for the area and we are excited to have them as a partner in this important area. We have 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 turn to sales 31 drilled but uncompleted wells or DUCs that were spud in late 2018 and 2019. 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 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 a lower debt balance, our Board of 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 revised guidance. Overall, I am very pleased with the progress we have made in a number of important areas. And with that, I will 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 [indiscernible] checks received during the quarter for production that we had not previously accrued. That's 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 lesson in the coming quarters as the lower rig counts should result in fewer of these new checks representing prior periods and that expectation is incorporated into the revised guidance that I will 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 distributions that we announced for the second quarter that represents coverage of approximately 2.1 times. As Tom mentioned, we have made great strides in reducing our outstanding debt during the year. The $153 million outstanding as of July 31 represents a reduction of 58% of total debt at 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 two asset sales transaction. 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 in 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. 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 non-operator. And if anything meaningfully changes in our outlook, we will provide further updates. 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 remainder of the year. The other updates are pretty self-explanatory. We expect slightly lower lease operating cost and a slightly higher rate for production and ad valorem taxes, given there is a fixed component to that metric. We do not make any revisions to our G&A guidance. We are still tracking to meet or reduce 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 2021 was $23.4 million, but I will note that we did incur about $5 million of restructuring charges in the first quarter that ran through G&A. So we are 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 continued working remotely. Sia, with that, I will open the call to questions.

[Operator Instructions]. And the first question will come from Stephen Decker with KeyBanc. Please go ahead.

Hi guys. Good morning. I just wanted to get a sense to the level of shut-ins that you guys might have had in the second quarter?

Well, so Stephen, this is Jeff. We are modeling about 30% with a lot of that concentrated in the Bakken. That's been 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 in looking at the revised guidance levels, it's at around those levels do and then assuming they generally start to come on through the remainder of the year.

Got it. Okay. Thanks. 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 where you are 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 are trying to do right now is balance a nice return for our investors at these levels with the idea that we can 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 are 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 that the idea of this $0.15 is that that should be a sustainable level. Now, of course, we are not variable until we are in this sort of environment. But we would 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 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 would be comfortable increasing that payout ratio.

Okay. Great. I appreciate the time.

Thank you Steve.

The next question will come from Brian Downey with Citigroup. Please go ahead.

Hi. Good morning. I hope everyone is well. Thanks for taking the question. 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 in the next year? Working interest volumes continues to decline. But trying to get a better sense of the other benefits that should mainly impact next year, given the activity can be seen laid out there?

Yes. Brian, thanks for the question. This is Jeff. Look, generally it's going to be a little, 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. It's frankly tough to look at out that far at the moment. But if you just look at mineral and royalty volumes, we are going to be offsetting declines in the Shelby Trough but these new volumes will certainly be offsetting that decline. Working interest 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 2021, we are 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 would just add that we are working not only the Shelby Trough. We are also working in Louisiana and the Haynesville, but we are 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 are working very hard on it and we expect some production growth eventually once we move through this cycle.

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

I guess I would say that there is 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 a ways off. And so I think we are 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.

Great. I appreciate it.

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

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

I would give a quick answer on that. It mostly has to do with our contractual relations with our operators 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 are going to try to create out there. So it has to do with specific contracts and I will just say that we are 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 with other operators, where you can reach to other operators?

Well, it's basically this month.

Okay. Understood. Just lastly on the distribution again. I just kind 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 they are not variable per se, but is there a view that maybe you move the payout ratio down in periods where there is more activity in the M&A market? Or just generally how you are thinking about financing acquisitions? Thanks.

Yes. TJ, this is Jeff. Look, that's a great point. I think it's something that we will think about really hard with the Board once we get through this period of greater turbulence right now. But we are really focused on is 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, that's basically for us, it's an acquisition that you don't s have to pay for, right. It's a new stream of cash flows that you don't have to put front payment on. So that's really what we are focused on. The world starts to really brighten and the banking market loosens up a little bit and capital becomes a little more available and we are supplement an active M&A program with a little more retained cash flow, then I think that's certainly something that we will discuss. But for 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 are taking care of those two things.

All right. Thanks Jeff.

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

Yes. Thanks for taking my questions and good morning. First question is, Jeff, what are your latest thoughts on hedging?

Good morning Pearce. So, as you know, we put in a pretty significant round of hedges a little earlier this year. I would say, we will just continue to be opportunistic around adding levels. Obviously levels for 2021 have improved and hope they will 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 2022 hedges. So we are going to continue to be programmatic about this. It served us very, very well in this quarter with a lot of protection throughout hedges. And so I think we are 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. Thank you. 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 have made on the balance sheet. What metrics are you looking at to define, hey, we think the balance sheet is in good shape? There is a leverage ratio right now is low, but are you looking more at just the absolute level of debt? Where I am going with this is just to better understand when you feel like the balance sheet is at the level to support a higher payout similar to what someone was asking earlier?

Yes. Pearce, this is Jeff. I will start with that. And then anyone is welcome to chime in. Look, we have historically looked at a number of things, right. So it's absolute debt level, 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 for debt to trailing EBITDA. And we continue to look at all of those things. I think what I would say is that in times like this where you have got a corporate banking market that is really pulling their talons in pretty dramatically. So you don't know if a lender that is there for you today is going to be there for you tomorrow. We have 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 base can be determined by a lot of things, including what sort of advance rate the banks are willing to give you and that can change over time. So we are just being generally more conservative across the board. I don't think there is some specific target I can point you to right now that says, man, as soon as we hit 0.5 times on our leverage ratio, we are 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.

Well, that makes sense. Thanks so much for the helpful answer, Jeff.

Thanks Pearce.

The next question will come from Derek Whitfield with Stifel. Please go ahead.

Good morning all. I 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 on the Bakken in approximate barrels per day for Q2?

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

We can follow-up, if needed.

I know that 30% is the Bakken and just trying to find it.

Yes. I think you know if you look, Derek, I would think that that's probably in the 1.3 to 1.5 MBOE a day. So 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 will see who else wants to comment. I mean we have got tremendous acreage focused on gas. Tom mentioned the Chalk and the work that we are trying to do there. We have got hundreds of thousands of acres across the Chalk in Texas and Louisiana. So we have talked before. There is a company that's drilled a very nice on the East Texas side of the Chalk. It continues to be a very, very nice performing well. And that was using modern, one of the first really modern completion techniques in that area of the Chalk. And so we are encouraged by that, but obviously it's one well and it's very early. But I tell you, I just don't know, it's tough to say right now how that could translate into lease bonus. What we have 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 a large contiguous acreage position, is to say to producers, hey, let us work with you truly as a partner and less with maybe we will lessen them or forgo upfront bonuses in exchange for a more identified development program. Ultimately, we would rather see revenues through royalties than through lease bonuses. 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, that's got circuitous around your question. I think as gas prices tick up, you would 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.

That makes sense. Very helpful all.

The next question is from Phil Stuart with Scotiabank. Please go ahead.

Good morning guys. I appreciate you taking comments this morning. I guess my first question is around the natural gas production for 2Q. It was held up a little bit better than we were expecting. I am just kind of curious what the biggest drivers of that were? Or is it just kind of the lower declines that the wells in the Shelby Trough 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?

Hi Phil. Good morning. 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 would say is that that's just part of owning such a giant portfolio of acreage, right. You just hope that you are 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 portends to anything specifically as other than just in a more constructive gas environment which we have seen. We would hope that activity broadly starts to come back a bit and we saw that in the second quarter, at least in Louisiana Haynesville.

Okay. Great. And then I guess my follow-up, just a clarification on the XTO deal for the 13 DUCs. The agreement is that they have to compete 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 one more quick follow-up on that. If we take 1Q 2021 as the starting point, assuming that those 13 DUCs are turned to sales in 1Q 2021, 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 will be enough to hold Shelby Trough production flat kind of 1Q 2021 to 1Q 2022? I am just kind of trying to think of that on an asset level basis.

Yes. Phil, unfortunately, I think we are just going to have to hope we would be in a position to give 2021 guidance on our normal timeframe. But it's just tough for me right now to comment on that, to be honest.

Okay. Sounds good. I appreciate the time guys.

Thanks Phil.

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 that done in 2021.

[Operator Instructions]. Okay. And at this time, there are no further questions. I would 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.