Matador Resources Co Q1 FY2021 Earnings Call

Good morning, ladies and gentlemen and welcome to the First Quarter 2021 Matador Resources Company Earnings Conference Call. My name is Sarah, and I’ll be serving as the operator for today. As a reminder, this conference is being recorded for replay purposes, and the replay will be available on the company’s website through May 31, 2021, as discussed in the company’s earnings press release issued yesterday. I would now turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.

Thank you, Sarah. Good morning, everyone, and thank you for joining us for Matador’s first quarter 2021 earnings conference call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the company’s financial performance. Reconciliations of such non-GAAP financial measures with the comparable financial measures calculated in accordance with GAAP are contained at the end of the company’s earnings press release. As a reminder, certain statements included in this morning’s presentation may be forward-looking and reflect the company’s current expectations or forecasts of future events based on the information that is now available. Actual results and future events could differ materially from those anticipated in such statements. Additional information concerning factors that could cause actual results to differ materially is contained in the company’s earnings release and its most recently quarterly report on Form 10-Q. Finally, in addition to our earnings press release, I would like to remind everyone that you can find a slide presentation in connection with the first quarter 2021 earnings release under the Investor Relations tab on our corporate website. I would now like to turn the call over to Mr. Joe Foran, our Chairman and CEO. Joe?

Thank you, Mac, and good morning to everyone. Thank you for participating in today’s earnings conference call. We appreciate your time and interest in Matador very much. I’m going to turn the call back to the operator in a moment to take your questions. But first, I wanted to make a few quick points. First, as you all noticed that we’ve continued to make good progress on our leverage ratio and borrowings. At the end of the fourth quarter, we were about 2.9 and today we’re at 2.5. Second, revenues are up obviously due to commodity prices, but even more importantly, we’ve substantially reduced our costs, not from hitting on our vendors and beating them down so much, but as we work with them, which we greatly appreciate, to make our operations more efficient. We reduced our time on well fracking efficiency and effectiveness, and we want to thank each of our vendors for the way they’ve cooperated and worked with us. These costs have come down dramatically. And as we all know, when you have extra dollar revenue, the royalty owner takes their share, and the government takes their severance tax, sales and use tax and alike, and you’re generally left with about 65% of every dollar. But on the cost side, every dollar saved goes to the bottom line and we get to keep. Finally, I want to stress that we’ve been through a lot in the past year, and there have been many challenges with the pandemic, with the weather, with prices, and working our way through that has been a total team effort. Everybody here at Matador has contributed across the spectrum. You’re likely to hear from guys in the field that they loaded up groceries in the truck, threw it in a bedroll, and slept in their trucks to keep the production on. Teams here have worked together to plan the drilling schedule and to work on costs together, and the geology keeps coming up with new zones. When we went out to the Delaware a few years ago from the Eagle Ford and made that our main area, we based it on three zones. Today, it’s my understanding is, Matt will probably speak up at sometime on a question we are producing from 18 different zones and think we will be over 20 by the end of the year, so just great. Same way on San Mateo: when our production group was ready to turn on the wells, the tops were there waiting for them. We weren’t having to truck out the oil or the water; all of it including the gas were on top, which was good for our ESG as well as the bottom line. So with that, let me turn the call back to the operator for any questions that you may have.

Our first question is from Scott Hanold with RBC Capital Markets. Your line is now open.

Thank you. Congratulations on the strong quarter. It’s good to see that leverage reduction coming quicker than expected. My first question is on some of the recent well performance and cost performance of these longer lateral and federal wells. Can you give us some color on what to expect from the teams like the Boros wells that came on and are holding in there pretty good? I know the Voni wells obviously have the longer laterals. Can you give us a sense of like what the expectations are for those things? Are they holding in a little bit better based on well management? And then along with that, maybe some color on the cost side, because I know you all tried some simul fracs in some of these wells and have seen some pretty dramatic cost reduction and the plan going forward. Is that something you can replicate or plan to replicate on future drilling?

Yes. Good morning, Scott. This is David. I’ll take the production side of the question and the well performance side. Then I’ll ask Matt to step in and talk a little bit about the costs in the fracs. Look, I think we’re extremely pleased with the wells that we’ve drilled at, I mean frankly all over the basin. But Rodney Robinson and Stateline, those have been some exceptional wells. You are correct. The Boros wells have continued to be very strong. We had about, as I recall, about 6 million BOE increase in our reserves this past year attributable to just revisions upward, and a lot of that was due to some of the Boros wells as well as Rodney’s and others that have continued to do well. I think when we put the little shareholder letter out, the first of the quarter, we talked about how those 13 wells had made something like 3.8 million BOE already in the first six months of production, so they’re hanging in there very well. I think the Voni wells are off to a very, very good start, so very pleased with those. So we’re anticipating that those wells will probably actually be even a little better than the Boros wells. I think that you don’t always see the, although the back piece is excellent, those wells – we’ll see the little kick from the longer laterals as we get more history on these wells. And my prediction would be that we’ll see the proportionate increase in EURs going forward. So, all good right now. So Matt, you want to talk about the cost?

Yes. Scott. Good morning. We’re really excited about the drilling and completion costs and most excited probably about the efficiency related to both. So just kind of a little background on this: we’ve now drilled over 75 of these 2-mile laterals, so we’re getting better as we go. And kind of what I’d like to point to, Scott, if we just look back at the first round of Boros wells that we drilled in the summer of last year, we spent about $800 per completed lateral foot on that. These Voni wells were 16. And so that’s 20%, 25% better just on the cost. I will say one most important thing to us is that we don’t sacrifice any quality in doing that. Our MAXCOM team continues to hit it out of the park. They’re up to, earlier this morning, I thought it was 116 drill records. And Billy just tells me right before the call, it’s 117. And so we calculate that’s probably a $15 million cost savings related just to MAXCOM, and they’re staying in zone well over 90%, 95% of the time. I’ll just point to, well, it’s not the first Boros or the Voni wells, Scott, it’s one of the later Boros wells that we just finished, it’s a Wolfcamp B well. The previous record on the Boros was about 31 days and the guys did it in about 16.5. So that’s a 14.5 days that they saved. As we said in the past, if you contemplate that being $100,000 per day, that’s about $1.4 million in savings. They continue to knock it out of the park on the drilling side. And on the completion side, we’ve improved our efficiency there. Let’s say in 2018, we were completing about 900 feet per day. This year, we’re averaging 1,550 feet per day. We just finished a couple of Stebbins wells or Ted wells up there, and we average 2,265 feet per day. So, that helps us from a couple of different ways. Number one, the service company realizes that they’re going to get to pump more frac stages per day. So, they adjust that into their costs and they were paying less for wellhead equipment, trailer supervision, all the daily rental items that we have out there. So Glenn and his team come in and they’ve modified their flow back procedure where we’re using less equipment saving several hundred thousand dollars. So just all in all, it’s just a great team effort, and we anticipate that we’ll just keep drilling them faster and completing them better.

Yes. Matt, can you give a little color on the simul frac? How that went and if it’s applicable on doing that going forward?

Yes. Sure, Scott. It’s a really good tool for a full well pad, which we have probably 60% of the remaining pads for the year, it will be a four-well pad. Our first experience we anticipated that we would save about $220,000 per well; we actually calculate that we’re saving about $250,000. So we’re off to a good start. We averaged around 2,200 feet per day with simul frac. For the first crack out of the box, I think it’s a home run there and we’ll be looking to improve as we go forward. 750 stages there on the Voni’s; that without a hitch between the Boros and Voni’s, it’s 1,550 stages. That’s a lot of frac work.

Yes. That’s pretty impressive. And my follow-up, and I guess, Joe, you kind of led me into my question and maybe we can hear from Matt. But obviously, 18 zones, potential of 20, and it feels like this is kind of a question that comes up about once a year. Like strategically as you go forward, how should we think about like, what zones are you finding that are going to be most strongly economic? And should we start to think about you guys, as you start looking into 2022, to really refine and target some of the better zones first? How do you see that development strategy going forward?

Yes. Scott, I’m going to say this first part and then let Matt really get more specific. But overall our guidance is still that proper growth at a measured pace. While there’s an abundance of zones to go after, we put plenty of rigs; the first key is, Matador has gone from – at the time we went public down there, bottom of 150 to one of the approximately 20 largest EMP companies by market cap. We’re more of a tortoise than a hare, but we like to do it at a measured pace and stay profitable. Many thanks to the geological group that Matt has helped build that keep coming up with good ideas, and we’ve been able to squeeze in testing those zones as we drill these multitude of wells to stay fresh. Just give enormous credit to the asset teams and Matt for coming up with ideas and being confident enough to test them out. It’s worked out pretty well, and Matt, many thanks to you and to the asset managers, the team leads we have for affirming your ideas. Go ahead, Matt.

Thank you, Joe. It really is a full team effort here. It starts with the land and legal group kind of getting the units put together and then the GSI team and the engineers working together to identify these targets. But how we’ve done this in a lot of ways is focusing on what has worked in a lot of our early assets, the X and Y sands, we started out with those and Wolf and pushed those to Rustler Breaks and then hats off to Trent Goodwin and his team for pushing those up into the Stebbins asset area with great success. One of the zones that we really like right now has been the First Bone. The Ray well and Rustler Breaks is kind of flying under the radar right now. But that’s a great well, and you’ll see us continue to push that zone around the basin, but there’s a lot left to do in this basin. Letting the rocks speak for themselves and keeping an open mind to what we cast and how we look at things around the basin has been a winning approach for us.

That’s good color. Appreciate it.

Thank you, Scott.

Our next question is from Neal Dingmann of Truist Securities. Your line is open.

Good morning, all. Thanks for the time. Joe, my first question maybe for you or David, you guys obviously are doing a great job of hitting your leverage goals, probably even ahead of what I think a lot of us were thinking. I’m just wondering what y’all consider – I’m wondering, let’s say once you get to that 2 times, which I think is very possible and likely this year, would y’all consider at that point maybe a more robust shareholder return? Would you prefer even continue to pay down the debt with perhaps the lion's share? Or would you consider maybe external, internal growth? Just wondering sort of plans if you do hit that target as I think ahead of schedule? Nice job on that, by the way.

Yes. Neal, candidly, we’re going to consider all three of those alternatives. That’s one of the things that we’re hoping that COVID will ease itself so we can get back on the road and meet with our shareholders in-person and hear from them what they think, as well as meet with a few analysts that may come by and want to get together where we can discuss and hear your thoughts. Look at what some of the other companies are doing and consider all three of those or parts of all three of those. So you might not have concentration on one; you may have some debt reduction and some raising the dividend. But look, we just paid our first dividend here, so give us a little break. That was just 30 days ago. I was waiting for the next, Joe. That’s going to be a continuing time to reduce, and we’re not in any big rush to add rigs or anything if it’s got to make sense, profitable sense. That’s why we’ve always tried to work, does it really add value? It’s not growth for growth’s sake; it’s quality growth. A lot of efforts are put around here to say, where does this take us? It’s a high-class problem. I have to look at those three, but it’s nice to have the flexibility that we can do any of the three or any part of the three and still raise the value of Matador. San Mateo, I don’t want San Mateo left out because they’ve not only contributed to the EBITDA, to the cash flow but the operational advantages that we’ve had when our guys were targeted on the Rodney Robinson or the Boros wells. If it was an outside midstream company, they might not have been as responsive and they were waiting for us when Chris and Cliff completed those wells and had them ready to turn on. So we’re really glad that Greg joined us and Matt Spicer joined us, and they’ve really pushed the midstream ahead.

Joe, just want to add to that. Specifically on the EEE pipeline, which is what we call the gas trunk line that runs from the Black River plant there and Rustler Breaks area onto the Stateline. We had to with permitting and process, and a lot of that was BOM, and a lot of it was state, a lot of it was fee, and COVID happened and people quit coming to work. Almost certain that the San Mateo folks got it done when a lot of people wouldn’t have. They went above and beyond. They climbed mountains to get people to come to work and approve permits. We put two crews to work, which got it done and got it done just in time. Otherwise, I think we’d have been sitting there for weeks, if not months, with well drilled and completed and waiting to produce.

Yes. That’s great, Matt. And Joe, interesting to hear your perspective on all three. I’d really love to hear your opinion, given you guys are such big holders. And my last question is just on undrilled inventory in broader terms, how you guys think about Tier 1 locations left in key areas like Stateline, Rustler Breaks, and others. Thank you, guys.

Neal, and also it’s true that we are big owners, and that has a definite influence with our stock ownership. We made a lot more from the stock going up than we do from our salary compensation. That’s an important part of our culture. We expect the other staff to be buying stock and being interested in that. We’re pleased, you’re in the worst times of last year when the price war and the pandemic were going, and our stock was challenged more. We had over 200 staff get out there and buy stock during that time, and I think the interest is paying off this year. The inventory looks really good. I mean, one thing it’s helped is all those different zones that Dave talked about. We believe we have a thousand or more 8-plus locations. And that’s when a lot of these businesses come down to is semi 8-plus locations. We define that as giving a 15% rate of return at $35 a barrel. Well, we’re above that, but we really hadn’t added to those locations; we’re redundant in the numbers on it. But we’ve got plenty of locations. We drilled last year 49, 48 wells, so let’s call it 50. We think we’ve still got a 20-year inventory on 8-plus locations, but one of our shareholders really emphasized in our meetings that’s why we say we like getting out and talking to him. He put his finger right on it: in today’s world, any of those 8-plus locations that you got, if you don’t have plenty for years ahead, you’re going to struggle at some point. We’re trying to stay ahead of that drilling curve on that, and touch wood, it’s working right now. We’re confident that we’re building that depth of staff to keep that going.

Yes. So the inventory looks solid. We’re optimistic about the Tier 1 locations that we have remaining. The important part is to make sure we maintain an adequate pace of drilling, and that’s always our focus, confirming that we can maintain a competent pace while keeping costs under control.

That’s great. Thank you, Joe, and David.

Thank you. Our next question comes from the line of John Freeman of Raymond James. Your line is now open.

Good morning, guys. Congrats on another great quarter. Just following up on Scott’s earlier questions on the cost side. I guess this is a little bit of a loaded question, but it just looks like you all are so far ahead of the game here. Obviously, the CapEx came in 11% below your expectations. This quarter, you’ve already had 40% of your wells for the year that have been turned to sales at $657 a foot. So when I look at the original guidance of $730 foot for the year, it looks like on those remaining wells that you all have for the year you’d be expecting them to be up about 20% on a per foot basis. I realize you all had some 10% service cost inflation in the back half of the year. So that explains some of it, but just if there’s anything else that we should think about in terms of what goes into those cost assumptions. It just looks like you all are doing a phenomenal job on the efficiency side. Or maybe it’s just as simple as you all want to wait for another – there was an initial for Greater Stebbins wells this summer to come online. Then maybe you evaluate where you are at that point on a CapEx trends, but just anything on that front, please?

Yes, John, this is Matt. I’ll answer your part of the question. I’m sure Dave will have some comments too. You’re right, we do assume that the 10% increase in costs, and we’re starting to see a little bit of that. Probably the biggest thing to talk about would be the cost of sand, regional sand that we’re buying from the mines there in Texas. We’ve seen a pretty good jump, up to 40% in the price of sand. I think there are two components to that. Number one is just kind of supply and demand: the rig count went down and then the mines kind of reduced their production. They had the capability to increase that and probably help with some there; they probably will at some point in time. The other is the cost to get that sand location, which is directly related to fuel prices. Consequently, the price of crude is up. Diesel is up, and that’s not necessarily a bad thing for us. We also think that just on the horsepower side of things, the pressure pumping folks are probably going to be looking for some sort of increase in the future. We’ve kind of built that into – but to your point too, about the wells up in the Stebbins Area and Ranger, Arrowhead areas, a lot of those wells will require an extra string of casing due to the aquifer up there. So those wells are inherently a little more expensive to drill. The ones we’ve drilled so far actually have been under what we budgeted, so we’re doing well there, but that would account for some of the discrepancy in the cost that you’re looking at.

Yes. I think, John, this is David. A number of those wells are new pads too, so their costs are going to be a little bit higher. I do think it’s just a little early in the year to jump out there. Very happy with how the costs came in the first quarter, but even some of that we will probably push into the second quarter because we had some timing issues there too. Not so much on our side, but some of the non-op stuff was a little slower than we predicted in the first quarter. So we’re very pleased where we are, and things are looking good. But I think we’ve got the range being pretty well for right now, and probably need another quarter to look at it before we consider making any changes.

And John, this is Matt again. I just want to clarify one thing I said on that 40% increase in the profit cost that ends up being about 6% or 7% of the completion costs, with things up there. I don’t know, 2% or 3% of the AFE cost. So it’s not terribly impactful.

That’s really helpful. And then maybe just my follow-up, David, you kind of started mentioning on the non-op side, maybe coming a little bit slower. That was the other part I was going to ask about was if given the price we’ve seen in the commodity, if you were seeing anything on the no-op upside that would cast a doubt that possibly there might be some upward bias on the original non-op wells that you all had sort of planned in the budget. If they get seven net wells planned in the budget, if you’re just seeing anything on that front, either from an activity side, or maybe how the costs were sort of trending on that, the non-op side?

Right now, John, I don’t know that we think we’re going to have a lot of additional non-op for the year. So there were just – there were a few wells, four or five or so in the first quarter that I think we thought would get completed and turned to sales, that the partner, for some reason, just didn’t quite get there. But we know those are being completed. We know they’re going to come on. I think in terms of the total amount of activity, maybe seeing a tiny uptake, but not too much. I still think we expect to see that, and on the cost side, I think that the costs seem to still be coming in half or better than what we were anticipating, and that helps a little bit too in the first quarter.

I appreciate it. Thanks, guys.

Our next question comes from the line of Gabe Daoud with Cowen. Your line is now open.

Maybe just starting with the permitting process; obviously, it’s resumed since the moratorium. It looks like you received another nine since the last update. Could you just maybe set some color on how the process has changed, if at all, if it’s elongated a bit or if it’s still relatively business as usual?

Yes, Gabe, it’s David. Well, as we reported, since the pause was lifted about a month ago now, the authority has returned to the local office, in this case, Carlsbad for us to approve permits in sundries and the rights of way in the lake. We’re pleased to see we’ve gotten new permits through the kind of over the go line and through the system and the staff’s been very cooperative to get a number of sundries that we needed to support ongoing wells we were drilling. We’re optimistic and pleased to see things opening back up a little bit. I do think it’s – we’re still cautious to see if there’s going to be a little more friction in the system going forward and how that may impact things going forward. But it was encouraging to see nine new permits come across. I think we’re optimistic that we’ll continue to get them, but we’re still cautious and watching to see; I don’t know that we can say the process has fully returned to normal yet, but hopefully, it’ll move in that direction.

Got you. Got you. Thanks, David. And then maybe just a follow-up, just hitting on activity levels moving forward. Obviously, you added the fourth rig in March. Could you, David, or even Joe, I guess just help us think about the correct pace for Matador moving throughout 2021? And into 2022, I know you’ll be drilling through a significant portion of the higher working interest inventory. So just trying to get a sense of if you would need to add an additional rig to kind of backfill the loss of those high working interest locations? Thanks, guys.

Well, I’ll try, David, and then you happy to back claim that. Gabe, that’s a multivariable tough question about when we might add another rig. There are no immediate plans to do so. We’re going to watch how costs come in. We’re going to watch how revenues come in. We’re going to watch how the opportunities come in. We’re going to watch how the federal adds on their pace of approvals and permits in sundries and the like; all those things go into that. We just got the rig 30 days ago, so we got to see how that might work out. We’re pleased. We’ve already been through our loan committees on our bank loan. We have plenty of cash flow right now, but that’s the advantage of having a line of credit. I’m really pleased that we have 13 member banks in our credit group and they unanimously approved our loan as it were, no changes. We’ve got their full confidence. But right now, we plan to keep the plan as we have it and let a little more time go by before making change. It’s the right pace right now. We could ramp it up, but we want to also get the debt down, so that’s our first priority. Second is paying the dividend, and the third is we’re going to have growth. We’ve got a great opportunity set. So we could afford to be patient. Most of our federal acreage is now HBP. I think something like 78%, so that becomes optional after that, and the rest of the federal acreage for the most part overwhelmingly has eight years to run, so that’s a lot of option time. We can look at different strategies. We think we have good cards to play.

I think the only thing I would add, Joe, just to clarify, your question about how working interest, Gabe, it is true that as we get closer to drilling the locations or finishing up drilling on Stateline or Rodney Robinson, those are some of the higher working interest wells that we’re drilling currently. It’s still going to take us a while; it will probably be late next year before we’ve been making many changes. Even if we decide to back off on some of those and move to some other areas, it’s still a ways from that happening.

Understood that. Thanks for clarifying that, guys, and a good quarter.

Thank you. Our last question is from Gail Nicholson of Stephens. Your line is now open.

Good morning. I want to lead this quarter set a record for first quarter LOE, despite the storm in February. Can you talk about what drove the LOE performance in the quarter? What was the impact on the LOE from the storm?

Sure, Gail. This is Matt. I think the answer to your question is efforts. Our guys, every summer we started getting ready in July and August, which sounds kind of weird when it’s 105 degrees that you start preparing for winter, but we do, and that’s not only on the Matador piece side, but that’s also San Mateo for the saltwater gathering and yes, salt water getting exposal in the oil, transportation, and gas processing and gathering. So it starts early. That helps a little bit, but I think just driving costs down, Glenn and his team, they’ve got 98% of the water that we produce is on spot. They get 78% of the oil that we produce is on spot. That all helps from a cost perspective, just getting out in front of things and making things work. This Winter Storm Uri, we took a different approach. I think a lot of other operators did; our guys and Joe said this before, they went to the grocery store, packed a bunch of groceries, and gotten their trucks. The one thing I’ll disagree with him; he said they slept in their trucks, but I don’t think they slept a whole lot, Joe. They were out there working, and they were in constant communication with the San Mateo folks. We’re doing the same thing. They’re out making this gas point run. Our marketing team here in Dallas, they’ve found homes, found places to sell the gas and manipulated the markets to ensure we didn’t – I mean, they didn’t manipulate the markets. They were able to watch the markets; they made sure that we got our nominations right and got our product sold. Kudos for the team, what I’ve been saying, Gail; the best first quarter we’ve ever had with the worst weather conditions we’ve ever had. Hats off to the entire team.

Great. And then on the San Mateo side, San Mateo generating free cash flow; we should see EBITDA growth throughout 2021. Can you just talk about what are the growth drivers for San Mateo in 2022 forward? And then what is San Mateo’s plan regarding the future repayment of its credit facility?

Well, I think the key growth drivers for San Mateo going forward, I’d say are two specific ones. Number one, the growth in Matador volumes in both the Stateline and the Stebbins Area is expected to be significant over the next couple of years 2021 and 2022. That certainly will drive higher volumes and higher revenues and cash flows for San Mateo. We have a continuing and ongoing effort to increase third-party volumes at San Mateo. I expect we will continue to add third-parties as well. So I would say those are the two primary drivers. I think I’d also just throw in the fact that I think those guys have also done a very nice job of reducing operating costs over the last several quarters. That’s also contributed to better free cash flow from San Mateo. The San Mateo credit facility, we did repay $19 million since April 1. So that paid debt down a little bit. I don’t think at the moment we’re as concerned with rapidly repaying the credit facility there. What we’re more focused on is given the merger of San Mateo 2 into San Mateo 1 and the additional collateral; we are looking to sort of expand the credit facility and that’s probably something we’ll take on as an objective pretty quickly, Gail, looking to have a little better commitment in terms of the electric commitment and just improve the size of the facility in the event that we need that going forward.

Great. Thank you so much. Great quarter, guys.

Thank you, ladies and gentlemen. This ends the Q&A portion of this morning’s conference call. I’d like to turn the call over to management for any closing remarks.

Thank you, Sarah. Really, I thought you all did good on the questions, and we appreciate the substantive nature of the questions, and we appreciate your following us. We feel very optimistic, glad to see the whole staff top to bottom contributing to the effort in a material way. We like the innovation. We didn’t get into that, but there’ve been some innovations done on the technical side. The rig design that Billy and his group came up with is paying off. By way of substance on that, the fourth rig was a state-of-the-art rig that the other ones were, and it’s already off to a real good start. That has worked well. The same thing on the fracking; the guys come up with fracking techniques, and the plants are running well. Sure as I’d say that some will happen this afternoon, but everything is working. It’s been a great effort by the staff to work through these challenges. We feel we’ve come out of those challenges much stronger than when we went in it. It’s almost exactly a year ago our stock had fallen down to one, and this time it was about three. Nobody quit and nobody despaired; they just kept moving through and it’s rallied. Lots of that goes to the bank approval. We appreciate them standing with us because last year they renewed it, no changes, with the 13 different credit committees and reservoir groups. They did it again this spring. Shareholder group, everybody, we just want everybody to know how much we appreciate it. The outlook is very strong, and I think that’ll just generate more opportunities for us. We’ll sign off, and once again, invite any of you to come see us as the nation opens up again. We’d love to have you come by and meet more of our staff and have a longer visit.

And I guess, particularly on June 4, the annual shareholders meeting is.

Thank you, David, for kicking me under the table with that. We’ll be having an annual meeting on June 4. We’ve sent out the annual report, and we really hope you’ll come, and we’ll get back to normal again. So thanks a lot. Come see us.

Ladies and gentlemen, thank you for your participation today. This concludes the program. You may now disconnect.