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Good day and thank year for standing by. Welcome to the Black Stone Minerals Second Quarter 2021 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. Please go ahead, sir.
Thank you, and good morning to everyone. Thank you for joining us either by phone or online for the Black Stone Minerals second quarter 2021 earnings conference call. Today’s call is being recorded and will be available on our website along with the earnings release, which was issued last night.
Before we start, I’d like to advise you that we’ll be making forward-looking statements during this call about our plans, expectations and assumptions regarding 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 our forward-looking statements in our press release from yesterday and the Risk Factors section of our 2020 10-K.
We may refer to certain non-GAAP financial measures that we believe are useful in evaluating our performance. A reconciliation of those measures to the most directly comparable GAAP measure and other information about these non-GAAP metrics are described in our earnings press release from yesterday, which can also be found on our website at blackstoneminerals.com.
Joining me on the call today 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 & Legal; and Garrett Gremillion, Vice President of Engineering and Geology.
I’ll now turn the call over to Tom.
Thank you, Evan. Good morning to everyone on the call, and thanks for joining us to discuss what was a very strong quarter on both, the operational and financial fronts.
We reported 38.2 MBoe per day for the second quarter of ‘21. Of that, royalty volumes increased by 5% from last quarter to a total of 32.5 MBoe per day. Working interest volumes held stable to last quarter at 5.7 MBoe.
The increase in royalty volumes was mainly due to the Midland and Delaware properties but we also saw nice increases outside of our major shale plays as well, but seen a remarkable rebound in commodity prices since the middle of last year and are currently well above pre-pandemic price levels.
Operator activity continues to grind higher as well. We had 64 rigs operating across our acreage at the end of the second quarter. That’s up slightly from last quarter and is more than double what we saw in the middle of last year. The slower recovery and rig count relative to prices reflect producers holding to their promise to exercise greater capital discipline and focus on returns rather than simple production growth. It should prove good for the long-term health of the industry if it continues.
The higher price environment, increase in drilling activity and leasing efforts in the Austin Chalk contributed to our best financial performance since 2019. We reported adjusted EBITDA for the second quarter of $78.4 million, which is an increase of 31% from last quarter and 8% from the second quarter of 2020. Distributable cash flow for the second quarter was $72.1 million, which equates to $0.35 per unit. That’s also an increase of over 30% from the last quarter. Improved fundamentals and positive outlook across many of the core areas of development justify an increase in the base level of our distribution to $0.20 per unit for the rest of this year, which is a 14% increase from last quarter. We also had a number of items break to the right way for us in the second quarter, including higher than expected gas realizations and a big quarter in terms of lease bonus.
In the past, we’ve taken the proceeds from those onetime cash flow events and repaid debt. Given our very low debt balance, which is currently under $100 million in total, our Board elected to return that additional cash flow to our investors in the form of a special distribution of $0.05 per unit for the second quarter, resulting in a total distribution of $0.25, which is an increase of 43% from last quarter. I want to be clear that absent any disruption in the business or significant positive, the plan here is to recommend distributions, as I said of $0.20 per unit for the third and fourth quarters as well.
On the last call, we discussed the number of new deals with producers around some large high net acreage positions in East Texas. The majority of those deals were signed up early in the second quarter. In our Shelby Trough play, Aethon has turned sales to initial two wells under their development program in Angelina County. We were encouraged by the early results, and Aethon has commenced drilling another four wells in the area, which puts them ahead of schedule relative to what is required under our agreement.
We were seeing big whales out there from BP’s operations prior to mid-2019 and were happy to see that robust activity -- robust activity permits to pick up again with our new partner. Aethon is also gearing up for new Shelby Trough Development in San Augustine County under a separate agreement we entered into in April with them. And that agreement contemplates a minimum of 5 wells drilled in the first program here and ramps up from there.
In summary, we’re optimistic around Aethon ramping up to pre-2020 level seen with BP and XTO combined in this area.
Moving a little south, we have several programs underway to test the development of the Austin Chalk trend in East Texas. As we’ve discussed on the last call, this is an area where we have broad geographic coverage across the play and very high net ownerships in those areas. We have two wells currently drilling and several others planned for the remainder of this year, all of which involve high-intensity multistage completions and that have proven successful in other areas of the Chalk.
Attracting development capital to our existing acreage has always been a major area of focus for us. We will continue to be going forward on that. As part of the effort, we’re very happy to welcome Carrie Clark to our team. Carrie started with us yesterday and comes to us from heading land and legal efforts at university lands, which manages surface and mineral interests, across 2.1 million acres managed by the University of Texas System. Carrie has a lot of experience working with operators to encourage greater activity. And that will be a key part of Carrie’s contribution to Black Stone. We look forward to working with her on that and other initiatives.
We’ve made tremendous progress on the development front that has [Technical Difficulty] with the proceeds from the surface use waivers in favor of solar development on our mineral acreage. Solar developers must secure surface rights, but must also obtain a waiver from the mineral owner as part of the project, so that rigs do not disrupt their project. We received approximately $1.1 million in proceeds from such waivers in 2021 and plan to use a portion of those proceeds to purchase carbon credits. That way, we’re both supporting clean energy development by facilitating solar installation and reducing our own emission footprint through the credits. We expect the credit’s purchase for use in 2021 will meaningfully offset the direct CO2 emissions from our existing production in Shelby Trough and Angelina County. This is a first and modest step, but we look forward to finding additional creative ways to work with this to further our environmental goals.
As you can see, it was another busy quarter. It’s encouraging to see that both general industry conditions continue to improve and to see the tough development work we’ve undertaken over the past couple of years start to pay off. All of this is with a goal in mind of returning greater cash flow for our unitholders. We were able to accomplish that this quarter and see great potential to further that goal heading into 2022.
With that, I’ll turn it over to Jeff.
Okay. Thank you, Tom, and good morning, everyone.
As Tom went over, we had a very strong quarter on a number of fronts. Production rebounded from the first quarter, and of course, commodity prices were much healthier. We saw big gains from WTI and Henry Hub prices, and further benefited from improved differentials, resulting in a 21% uptick in realized prices from last quarter.
Oil differentials continue to move up. That’s a trend we’ve seen since mid-last year, while our gas differential spiked to 127% of Henry Hub. That was due to stronger NGL prices and higher than expected realizations on checks we received in the second quarter related to February production. This combination of gains in production and price, plus a strong quarter of lease bonus payments, led to our adjusted EBITDA and distributable cash flow outpacing the first quarter amounts by over 30%.
But metrics were held back a little bit by our 2021 hedges that we put in place last year, which they are below current market levels. The bright side of the hedge story is that we stand to see meaningful increases in cash flow going into 2022, just from better hedge realizations. We did add to our 2022 hedge portfolio during the quarter at prices averaging around $3 per Mcf for gas, and $62 per barrel for oil. Overall, our average hedge price for 2022 versus this year is 11% higher for gas and 54% higher for oil.
We generated $72.1 million of distributable cash flow for the second quarter or $0.35 per unit. That gave us a lot of flexibility to increase our distribution while still holding some cash and reserve for further debt repayment.
As Tom discussed, we increased the base or sustainable distribution to $0.20 per unit for the quarter. We paid out another $0.05 per unit as a special distribution to reflect cash flows we view as nonrecurring, and we held in reserve the remaining $0.10 per unit.
Our distribution coverage for the second quarter was 1.4 times on the full $0.25 per unit and 1.7 times on just the base distribution of $0.20 per unit. The amount we held in reserve allowed us to fund the $10 million cash portion of our Midland acquisition, which closed in the second quarter, as well as repay another $15 million of outstanding debt under our revolver.
Speaking of our debt balance, we ended the second quarter with $96 million of total debt and a total debt-to-EBITDA ratio of just 0.4x. That’s the first time since 2015, we’ve been under $100 million of debt, and as of this past Friday, that balance was down further to $81 million. We also provided updated 2021 guidance in the earnings release from yesterday afternoon. Production through the first half of 2021 has exceeded our original guidance expectation. Production is anticipated to trend lower in the second half of ‘21, driven in part by declines in mature plays such as the Bakken and Gulf Coast and by lower natural gas volumes in the Shelby Trough from existing PDP declines in advance of the expected ramp-up in new drilling activity under our new development deals.
Despite the increase in rig count through the second quarter, we do anticipate that trend to flatten through the remainder of the year, as operators maintain their capital discipline. Therefore, we have not incorporated into the revised guidance any significant volumes beyond those for which we have a line of sight. However, we often do see some volume adds in the form of new unidentified wells across our acreage, and that is part of what drove the beat through the first half of the year relative to our original guidance. Other changes to that original guidance include a slightly higher range for lease bonus, given the big quarter we just had, lower production costs as a percentage of revenue, that’s due to the fixed component costs and higher expected prices, and a small move up in our estimated cash G&A.
And with that, Delfin, we will open the line for questions.
Thank you, Jeff. [Operator Instructions] And here’s our first question coming in from Mr. Brian Downey from Citigroup.
You announced the increase to your base distribution to $0.20 per unit, and noted your low debt balance of only $81 million at the end of July. Given where the balance sheet currently sits, how are you thinking about distribution payout or coverage into next year, particularly once those less attractive hedges roll off versus A&D and other potential uses of that cash?
Brian, this is Jeff. I’ll start with that. I mean, look, I think we’ve said for a long time now, one of the big benefits of the massive debt reduction that we went through in ‘20 and early ‘21 is that we’d be in a position to really prioritize increasing payouts. So, we started that a bit, although we still even with the special distribution at 1.4x coverage felt pretty healthy, but I think part of this, as we think about the sustainability of that $0.20 and then as you mentioned, potential for going higher than that in ‘22 as hedge prices increase. Look, there’s sort of four things you can do with your excess cash flow, right? You can pay down debt, you can save it for acquisitions, you can do buybacks or you could increase distributions. And I think where we are at least today is to prioritize increasing distribution. So, I would expect that as we anticipate production coming down a bit in the back half of this year, that coverage will just naturally come in on that $0.20 planned distribution. Of course, the Board’s got to approve that, and we’ll see if things change. But the idea is to pay off that 20% coverage will come down a little bit. But then as we get into ‘22, I would think that we would maintain lower levels of coverage than we have in the past, just as you mentioned, because of the debt levels.
That makes sense. And then a separate topic, you highlighted your new sustainability initiative and surface use waivers supporting mineral development, which I found interesting. How much runway is there on utilizing your mineral acreage for similar types of initiatives, perhaps quantifying potential proceeds over the coming quarters? And if you could remind us if you own any notable amount of surface acreage itself that could be used as well?
Brian, this is Tom Carter. I’ll take a shot at that. First, I would say that our efforts around this part of the growing part of responsibility of all of us is nascent, and we are looking at multiple different ways to go at this, and there are a lot of them. In this particular case, as you may or may not know, we don’t own any substantial amount of surface acreage any longer but in Texas and in a lot of other estates, the mineral estate is the dominant estate, which means that there’s a right to drill a well to access the minerals, and you can obviously, if you can imagine, if a bunch of drilling rigs show up on surface that has been leased to a solar farm, the disruption that would cause. So, these folks seek surface use waivers by the mineral estate before they put those arrays out there. And we -- that’s where we come into play, and we do interrupt our rights to use that. We usually secure pre-agreed upon drill sites so that drilling can occur, but the solar folks know where they’re going to be. If you put all that together, I think there’s an opportunity for the mineral estate and the surface estate owners to work together to facilitate operators being able to put these lands together so that they can effectively build these farms. It’s getting more and more competitive every day.
In addition to that, there are a lot of other things that we are researching, and I don’t want to get too far out over my skis on this but it could be as much as -- and I don’t want any of our operators to fence on this too much, but as long as commodity prices are robust and economics for drilling are good, we may seek to encourage some of our lessees to also seek ways to mitigate carbon production by buying their own credits or other types of sequestration. This is just a new area that we’re looking at, and I think it behooves everybody in the oil and gas business to be as progressive as we can be at addressing this issue for the long-term runway of our business. So we’re just getting started. This was just an effort to tip our hat to the knowledge that we see this as an important factor in the future for all of us in this.
And our next question is from Mr. Pearce Hammond of Piper Sandler.
My first pertains to production, first half production better than expected. Second half looks a little weaker relative to our expectations. Just curious what accounted for that, what do you think accounted for that stronger production in the first half? And then do you think maybe you’re being conservative in the second half? It just seems like a bit of an abrupt change from the first half to the second half?
This is Jeff. Yeah, look, as I said in the prepared comments, right, we really tried and when we put out production guidance, we try to rely on things that we have a real line of sight on. And so there is a lot of serendipity that happens across our asset base, and we certainly saw that in the first half of the year. Frankly, some of those mature plays that I mentioned that we expect to see declines from like in the Gulf Coast and in the Bakken, just continue to outperform our expectations. That can’t happen forever, but it’s been pretty consistently happening here over recent quarters.
So, I think in general, we have a conservative bench when we give guidance just because we try not to forecast a lot of things that we can’t see, even though we tend to have some good things happen across our acreage every quarter. So look, the hope would be that we are being a little conservative but I think the good news here is that we put this $0.20 base distribution with an eye towards our revised guidance and what that means for production levels for the second half of the year. And I think we should still be able to fund that distribution level and obviously, if we continue to see some things outperform, that may give us further flexibility in terms of additional debt paydown or whatever. But yes, we realized that it may look a little conservative given the outperformance in the first half of the year, but frankly, we’d probably rather be on that side of things.
And then my follow-up, congrats on all the progress you guys have made in East Texas with the various operators. And clearly, it seems like things are moving at a bit of a faster pace, which is good. So I’m just curious, back to production, when do you see that inflection point when all of this new activity that’s getting spooled up starts to really show up and offset some of those declines?
Pearce, I know you know this because you cover the story so well, but just context for others, right? I mean, between BP and XTO and that Shelby Trough area, which between royalty and working interest was only a third of our production as we were coming out of ‘18. That was a 30-plus wells a year on pretty high net acreage for us, and when BP and XTO stopped drilling, the PDP profile of those existing wells were flat for a year or so and then started to turn over pretty quick. So we’re in that sort of high decline curve on the existing last big round of PDP, last big round of wells that were drilled by BP and XTO.
And well, as you mentioned, we’re very encouraged by Aethon’s early results. It is early and it just takes a while for those programs to get ramped up and to really provide that inflection point that you’re talking about. So I think, we’re expecting that in ‘22, that inflection point and that relatively steep decline in the existing PDP, of course, is a big driver to some of those declines in second half of ‘21 versus first. But I will tell you, based on only well results, based on the fact that they’re running ahead of their required performance under the agreement, we’re really optimistic about Aethon’s activity there. And of course, the other big part of that inflection point is going to be -- we’ve got four to five wells that are going to be -- that have either already been spud or will be spud over the course of this year in the Austin Chalk, and we’re excited there just given the extent of our ownership around that play.
And if you take our contractual situations out there at full compliance, you could see upwards of 30 wells a year moving up to from where we are to 30 wells a year in the Shelby Trough portion of the Haynesville Bossier. And if our initiatives, our collective initiatives in the Chalk pan out, which we’re optimistic about, we could see that ramping up to 20 to 30 wells a year. So, you put those two things together, we’ll be growing into those shoes, if you will, but it could roll back up pretty quickly.
[Operator Instructions]
Well, it looks like that’s all the questions, and as always, we thank you for joining us, and we look forward to discussing matters with you next quarter. Thanks so much.
And this concludes today’s conference. Thank you for your participation. You may now all disconnect. Thank you so much.