Matador Resources Company

Good morning, ladies and gentlemen. Welcome to the first quarter 2020 Matador Resources Company earnings conference call. My name is Danielle, and I will be serving as the operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session at the end of the company's remarks. 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, 2020. As discussed in the company's earnings press release issued yesterday. I will now turn the call over to Mr. Mac Schmitz, Capital Markets Coordinator for Matador. Mr. Schmitz, you may proceed.

Thank you, Danielle, and good morning, everyone, and thank you for joining us for Matador's first quarter 2020 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 company's 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 recent quarterly report on Form 10-Q. Finally, in addition to our earnings press release issued yesterday, I would like to remind everyone that you can find a slide presentation in connection with the first quarter 2020 earnings release under the Investor Relations tab on our 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 out there, and thank you for participating in today's call. We appreciate your time and interest in Matador very much. Today we're trying something new in this quarterly release. On both our website and on the webcast plan for today's earnings conference call is a set of five slides identified as chairman's remarks, slides A through E, to add some color and detail. Please let me know if this additional information works out to be helpful to you. If you'll begin by looking at slide A, you'll see that the first quarter of 2020 was another good quarter for Matador and a beat across the board. The board of directors and I would like to commend once again the Matador team for their focused and professional response to the dual crises of the novel coronavirus and the abrupt decline in oil prices. Since early March, we have worked together to verify ways that Matador can reduce capital spending and operating expenses while increasing revenues and cash flows to weather these challenging times. The officers of Matador are in here with me and they're available for your questions to and that we all spent a lot of time up here together in the last six weeks. At a meeting of the MADDOR's board on March 10, 2020, I volunteered to take a 25% pay cut. The board joined me in taking a 25% pay cut too. MADDOR's president and the executive vice presidents all then took a 20% pay cut. The other vice presidents took a 10% pay cut and the rest of the staff took a 5% pay cut. According to one prominent energy industry compensation study, Mabdor was the very first company, oil company, to announce any such cuts. Among the other first steps we took were to hedge 90% of our anticipated 2020 Foran, Van Singleton, Throughout the first quarter, the operations group led the way to our goal of achieving lower than expected capital spending and operating expenses. Our capital expenditures for drilling, completing, and equipping wells this past quarter was $25 million less than our original estimates for the first quarter of 2020, and we estimate that $15 million of these savings were attributable to improved operational efficiencies and lower than expected drilling and completion costs. Drilling and completion costs for all operated horizontal wells completed and turned to sales averaged just over 1,000 per completed lateral foot, a decrease of 13% from average drilling and completion costs of 1,165 per lateral foot achieved in 2019. We expect drilling and completion costs per lateral foot to continue to decline throughout 2020, reflecting improved operational efficiencies, reduced service costs, and the impact of drilling longer laterals, with most being two-mile laterals. These results bring us to slide C, which indicates by the fourth quarter of 2020, Matador could be approaching cash flow neutrality. And that's down there in the lower right-hand corner. You can see that we're steadily bringing those costs down, and we think the outlook is positive there. At the end of this quarter, we achieved the first of four important production milestones we set for Matador in 2020. Matador had previously predicted in early 2020 we would incur a significant surge in production when the first six Rodney Robinson wells in the western portion of Antelope Ridge asset area were turned to sales. As recently reported in a separate press release, Robinson wells achieved record 24-hour initial potential test results for Matador from all three different formations tested, collectively testing at rates of approximately 15,000 barrels of oil per day and 25 million cubic feet of natural gas per day. The other three production milestones should occur when the five ray wells in the Rustler Brace Asset area and the five Leatherneck wells in the Greater Stebbins area are turned to cells during the summer and when the 13 boris wells in the state line asset area are turned to sales beginning in September and October. These are objective measures of our progress. These boris wells are likely to be even better than the Rodney Robinson wells and there will be twice as many of them. Collectively, these four groups of wells make up Almost 60% of our expected completions in 2020 and should account for more than 60% of our incremental production this year. As we move forward in 2020, our priorities are to protect our balance sheet and our liquidity and to strengthen our exploration and production and midstream businesses. We will do whatever is required to protect our balance sheet and preserve the necessary liquidity to meet our goals. Many of you have wondered about our bank relationships. If you will look at slide D, you'll see that we had approximately $340 million of our elected commitment available at the end of the first quarter and another $200 million available under the total borrowing base of our reserves-based loans. We wish to express here our sincere appreciation for the support and encouragement we have always received from our bank group and especially this year. These are obviously challenging times for all of us, but challenging times can bring about unexpected opportunities and we will remain open to all such possibilities as we navigate the remainder of 2020 and position ourselves For 2021 and beyond, we consider MADDOR's current stock price to be a good buying opportunity. MADDOR's assets include two successful businesses, one in exploration and production and one in midstream, as well as 152 million barrels of oil and 646 BCF-approved oil and natural gas reserves, respectively. and 128,000 net acres in the Delaware Basin, with 117 million shares outstanding. Slide E shows the steady growth in our approved reserves and the amount of reserves each individual shareholder proportionally owns. The Board, the staff and I remain confident that the outlook for Matador is very positive When you combine these assets with Matador's financial position, proven management team, and operating staff. As I mentioned, our staff, the officers are here, I'm here, and we would be happy to take your questions at this point.

Thank you. Ladies and gentlemen, to ask a question, you will need to press star 1 on your telephone. To withdraw your question, please press the pound key. Due to time constraints, we ask that you please limit yourself to one question and one follow-up. Again, we ask that you please limit yourself to one question and one follow-up until all have had a chance to ask a question, after which we would welcome additional questions from you. And our first question comes from Scott Handled from RBC Capital Market. Your line is now open.

Yeah, thanks. Appreciate that. And great quarter, guys. I think a lot of the narrative for the industry in the next couple months is really going to pivot to full storage in the U.S. and curtailment of production. You all obviously have factored some of that in to your guidance. Could you give us a sense of exactly how you see that progressing for Matador? And first question, have you guys shut in production yet? When do you think it'll start? And What is your sort of base case and maybe stretch case on what the shut-in levels could get to?

Hi, Scott. It's David Lancaster. Good morning. So let me try to take those in order. I think with regard to the question you're asking about, you know, the percentage of shut-in, you know, we've shut-in some or will shut-in some of our production in the In the Delaware and in the Eagleford in May and in June, we anticipate relative to, you know, to what our expectations were for what that production could have been, that we'll probably be in the 10 to 15% of our production in those months will be shut in on average. And with regard to your question of have we already started to, we are just beginning to shut in our production units. Thank you very much.

With some of those obviously pretty strong wells coming on in the back half of the year, how do you plan on managing those wells through the course of the back half of this year and into next year? Do you plan on managing the flow rates until prices improve or can you give us a sense of what that path is going to look like?

Yeah, I think, Scott, what we are thinking right now is the most likely thing we will do is probably something similar to what we did with the recent Rodney Robinson wells and that we will go ahead and frack and get those wells drilled out and put online, get initial tests on them and then if need be we may trim the production back on some of those wells for a period of time. I think that a lot of that will depend on how prices are looking as we go through the rest of the year. and those will be kind of game time decisions as we go along but as things exist now and particularly with the state line wells and the other wells that Joe's talked about in particular the Rays and the Leathernecks, our plan is to go ahead and complete those wells, drill them out, get them tested and then we'll make decisions as to the level of production on those wells as we go through the year.

I just wanted to add to what David was saying there in regards to how we're shutting these wells in and which wells are getting shut in. I think Glenn Stetson, our head of production, he and his team have done a really nice job of putting together all the wells that we operate and what the operating expense is on those wells and whether economic and whether not. And so we're kind of poised to react to whatever the market does in regards to increasing that amount or decreasing that amount. We've got all that stuff teed up and ready to go.

Okay. Okay. It sounds good. And just to be clear on just, you know, maybe my question wasn't as clear, but in your guidance, do you assume there's continued curtailment through the rest of this year on the Rodney Robinson and with, you know, the Boris Wells?

I think it's fair to say, you know, Scott, that we – have assumed in the second half of the year that we will be able to return those wells to production at something closer to what their original rates are. One reason that I think we said that we'd update again on third quarter expectations and fourth quarter expectations during next time's earnings release Foran, Van Singleton, But for the most part, in what we've provided, I think we expect that we'll be able to produce those wells closer to what we would have originally anticipated in the second half of the year. Okay, I appreciate that. Thank you.

Thank you. Your next question comes from Jeff Graham from Northland Capital Management. Your line is now open. Please go ahead.

Good morning, guys. Great results. Thanks, Gary. Wanted to, sticking on the topic of shut-ins, can you guys talk about any, I guess, expectations that you have or maybe drawing on past experiences you can draw on to kind of gauge expectations for how you guys see these shut-in wells kind of coming back and is that a meaningful risk you guys can kind of think about or plan for as far as, you know, bringing these wells back on? Just kind of curious how you guys envision that playing out.

Well, I'm sorry to interrupt.

Yeah, Matt, I'll go first and then if you'll finish up. But, Jeff, the one thing that we do is we do multiple scenarios so that we don't have just one and go with it. But we look at number of what ifs and to try to build out a plan. So, you know, it's more than one variable. A lot of it's price. You also have lease terms. You also have your hedging to take into account. And so it could be multiple scenarios there of what we may do at different times. The one thing I think that is we're trying to be consistent. We don't want to be, you know, turn the wells on full open. and then cutting them back. We want to try to be consistent and methodical through the process and also where we're on pipe makes it easier than where you're on truck in a few circumstances like that. Matt?

Yeah, Joe, thanks. Jeff, I'll just add to what Joe's saying. There are some mechanical issues around which wells we shut in that we do seriously contemplate and I'll just give you a couple of examples. If we've got a Thank you for joining us today. do the inspection on the tubing, do the overhaul and the ESB, and then prepare to run back in the hole and be ready to do that. So it's kind of the opposite ends of the spectrum. But Glenn and his team have done a really nice job of identifying which wells we want to shut in and how we want to shut them in.

Got it. Great details there. My follow-up on the midstream side, Relief mentioned San Mateo going to a free cash flow positive position next year. I assume that the two likely decisions with that free cash flow is either to pay down that bank debt or maybe extract some cash back to the parent. So I was just kind of wondering how you guys look at the optionality of that free cash flow. And is that a matter of decision? Is that a conversation you have with your partner? And I guess just maybe reminding us how much control you have over what to do with that free cash.

Well, hey, Jeff, it's David. Certainly, San Mateo has its own board of directors. It's made up of representatives from Matador and from Five Point. We have a very good working relationship with our partners at Five Point. I would expect that whatever we would decide would be a unanimous decision between the partnership and everything else has at this point. I'm sure that they would be consulted. We can use that cash flow to pay down some of San Mateo's debt, or we can also use it to enhance the distributions that are made to each party. It may be that the best thing that we decide, we'll just have to decide which way the partnership wants to go there. It wouldn't surprise me if if you know that for the most part we just increase the distributions made to each party and then each party can use those distributions as they see fit. I think in Mavdor's case that would provide a significant part of free cash flow that we would use along with the incentives that we expect to be larger next year to defer any outspend we might have in the Drilling and Completions of Wells for 2021.

Got it. Sounds good. I appreciate the time, guys.

Thanks, Jeff. Appreciate your time.

Thank you. Your next question comes from Irene Haas from Imperial Capital. Your line is now open. Please go ahead.

Yeah. Hi. Good morning. I was wondering, you know, as you look towards fourth quarter, you have a DNC capex of $56 million. with three rigs, probably likely no completion. Can you give us a little color as to how 2021 might unfold? How would you kind of step back into a more normal routine if oil were to stabilize, say, $40 or $50? Yeah.

Hey, Irene, it's David. Well, I think it's probably a little early yet to – to speculate on that. So I would be pleased for oil to be back at $40 or $50 in 2021. And if it were, then I'm sure we would probably consider perhaps adding a rig back. But at this point, we don't have any plans to do that. And I think certainly through the remainder of this year, we're going to stay with the three rigs and I think our initial plans for going into next year would probably be similar and I think we would be cautious as we always are in terms of when we decided to move forward with increasing activity. I think that actually in the fourth quarter, if I recall correctly, you're right, the number of completions is down but we still do have A few wells being completed even in the fourth quarter with the CAFE system that we have. And then we would have additional wells being completed in the first quarter of 2021 as well because I think most of our body wells at State Line would be beginning to complete a lot of those wells. And we'll have some additional Rodney Robinson wells by that time too.

Okay. May I have one follow-up? How's the G&A Thank you very much.

We gave you a pretty good indication of what we see for G&A going forward for the rest of the year. I think we would expect that our G&A per VOE would be down some from what we reported in the first quarter because there are some additional G&A steps that we've taken, in particular the pay cuts and things that Joe mentioned. Foran, Van Singleton, Some of the staff have moved into positions in the field or maybe in our measurement area in San Mateo. So we've had folks, I think, what did you say, Matt, 27 or something, that have actually gone from positions here in the Dallas office to other assignments. And I think that's all working out real well, but that's helped us to cut down on some of the contract expenses that we have. and we'll begin to see more of that begin to find its way into the G&A numbers going forward, Irene.

I just wanted to tack on to what Dave was talking about, these folks transferring job responsibilities. A lot of them are people that have gone through our max ops and buildings max ops and max com programs and they've been out in the field. That's where they learned. They spent the first two or three years in the field. We've asked him, and they were very excited about being able to go back and run drilling rigs and run frack spreads and do all that. So I think from a timing perspective, it's worked out really nice for us to have experienced field folks that we could bring into the office for a couple of years and then send them back out into the field. We'll continue to gain experience, and they'll be even better when they come back.

Great. Thank you.

Thanks. You're next.

Thanks, Adam.

Thank you. Your next question comes from John Freeman from Raymond James. Your line is now open. Please go ahead.

Thank you. Good morning, everybody. Not to belabor the shut-ins theme, but I just wanted to verify, David, when you said that roughly 10% to 15% production shut-ins is kind of what you're assuming, when you say shut-ins, does that include in that number – What I would do is sort of either curtailments or these restricted flow rates like on the Rodney Robinson. Is that included in that number? Or is it just physical shut-ins?

Yeah, John. It's David. Yeah, thank you for giving me a chance to clarify that because that is true. When I said shut-ins, I'm thinking shut-ins or curtailments or restricted flow. I've got that all sort of in the same bucket.

Okay, and then is it possible, David, it may not be, but is it possible to sort of break out like how much of that you think is physical shut-ins versus sort of the curtailment like what's happening with Rodney Robinson?

You know, I would imagine that I would say probably maybe John Paff, maybe two-thirds of it is more physical shut-ins and the other is due to curtailments.

Okay, great. And then just my follow-up question, just to make sure that I've got the completion cadence right. So based on the details y'all gave with the five Ray Wells and the five Leatherneck Wells, which you said summer of this year, if we take the prior guidance that had those coming on roughly around July, so I assume you gave those 10 in 3Q and then the 13 Boros Wells which are basically straddle 3Q, 4Q with September, October. If you just take half of those boroughs and put them in 3Q for right now and the remaining half in 4Q?

Yeah, I think what's most likely to happen is that the Raywells will end up being Q2 completions and I think the Leathernecks will end up being Q3 completions. and the Boris Wells, I think that maybe it'll be more like two-thirds in September and one-third in October, but there's 13 of them and they'll come on just a little bit at a time through those months. I think we're going to put them on three or four wells at a time during September and early October for several reasons. Number one, just don't want to Thank you, John. Thanks, John.

Thank you. And your next question comes from Neil Zingman from SunTrust. Your line is now open. Please go ahead.

Morning, all. My first question is probably for David or Matt. I'm just wondering, David, when you think about it, we haven't heard too much. You mentioned the curtailments and shut-ins. I'm just wondering, what's the time or cost needed to bring that back? It sounds like, or at least appears like, on your press release, there's really not too much timing or cost involved, but I just wanted to sort of double-check that from the experts.

For Neil, I didn't exactly understand your question. Are you just asking about how difficult it would be to bring the work back on or what it might cost?

Yeah, just really, Matt, from the shut-ins, we've heard Slumber J talk about a lot of stimulation needed to bring things back. And, again, I get it if you're curtailed. I'm just wondering about cost or timing. You all don't appear like there's too much involved, and I just wanted to sort of double-check that.

Yeah, Neil, I think it'll vary from well to well, but I think for the most part, let's just take the legacy wells that are on pumping units. I think, like I said earlier, I think that's pretty simple. You turn the unit off, close the valves, and when you're ready to come back on, you go back out and open them up. I think some of the wells that have different type of artificial lifts, it may be a little bit different cost structure. One of the things that we'll do, we'll just talk about gas lift. We haven't talked about that yet. So when we'll shut a gas lift, a well that's on gas lift, and we'll just go ahead and shut the well and leave the gas lift valves in place. We'll put the compressor on standby for that time period, and then we're ready to go back to work there. We go back out, open the well up. If it spills enough pressure to start flowing on its own, it will. If not, then we'll just start up the gas compressor and start gas lifting. If you move forward to wells that are flowing, which are probably very few of the wells that we would shut in that would flow, I think those would build up natural pressure and kick off on their own. So I don't think we anticipate a whole lot. There are a few wells that we probably will take this to be an opportunity to change out the artificial list system or overhaul what we've got in place.

Very good details. And then my second question is for David. David, around the CARES Act and tax credit, I'm just wondering if you all might be eligible for any AMT tax credits in 2021 and if you could look to potentially accelerate these into 2020.

Yes, Neil, the answer is yes to that. I think that we never had a lot of AMT credits Even, you know, with the passing of the new Tax Act, you know, but yes, I believe there's about probably about $3 million that we, you know, have applied or have requested, you know, be accelerated into 2020 as a function of the CARES Act. And I think there's another $3 million that, you know, that we're awaiting just on kind of the more normal cycle, you know, coming in in 2020. So altogether, maybe something like $6 million.

Very good. Thanks. And Joe, I just want to say nice job leading by example with the salary reduction and all. I think you guys really stand out.

Thanks, Neil. I appreciate my feelings were hurt here a little bit because I wasn't getting a question. But, no, we really appreciate you. I mean, it was the right thing to do. I'm not heroic by any means. It just was the right thing to do. We were looking at prices going up. Foran, Van Singleton, Bryan Erman, George Gregg Krug, Brian Willey, William Lambert, and I don't want anybody to think I'm a saint because I'm not. It's just the right thing. The really nice thing was without any prompting, our board immediately raised his hand, our audit committee chair, and said, I want to volunteer 25% pay cut too. And it went all around the boardroom and everybody agreed to do that. So I think that's a Foran, Van Singleton, worked through the coronavirus as well as these poor pricing, and we were really helped. One of the best moves was David and them restructuring the hedges to take them so that we got a much larger percentage, you know, 90%, 100% for the rest of this quarter, coverage on the hedges, you know, with a base price of a, you know, bottom price of about $35 to $37. We still have a few $48, but that took a lot of the risk out going forward, and it's been all hands on deck to keep things moving. So the credits really do other people, but I appreciate you giving me that credit, Neal, and I'll take it. I'll still consider you a saint, Joe. Nice, Neil.

Thank you. And your next question comes from Noelle Parks from Coker and Palmer. Your line is now open. Please go ahead.

Good morning. Hello. I was wondering about the mention you made earlier about the forest wells. and that you expected that they would be even better than the Rodney Robinson one. So I was wondering what you attribute that to and also wondering, you know, with the outperformance you saw in the first six wells, would you love to hear some more about what the components of that was, whether it's just, you know, the rock stack effectiveness?

Yeah, hi, Noel. It's David. Well, I think that that's right. I think that it's, you know, it's largely just a function of the rocks. And, you know, clearly that's an area there at the state line that we feel like is, you know, some of the very best reservoir quality or likely to be, you know, in the entire Delaware basin. And, you So I think we're just, you know, we're just very optimistic about, you know, the potential for those wells. I mean, you know, we've liked the look of the section from the Avalon through the lower parts of the Wolf Camp, you know, ever since we've been working in the basin and we think it's an area that offers a lot of opportunity and, you know, I mean, proof will be in the pudding, of course, but I think we're, you know, we're very optimistic and so far the The drilling on those wells has gone well, and so we're anxious to get that stage behind us and get to start fracking some of these wells here before too very long and see what we got.

I'll just add to what David has said there. One of the things that we're excited about is having those rigs on there at the same time. There's lots of synergy, lots of efficiencies that you get just by having all the rigs right there close by. We're sharing everything. Some of the mud systems we're able to share. We're sharing some of the supervision. We're able to reduce some of that. Our superintendents, our troubleshooters, if you will, they're staying on location. They're able to access all four of each at the same time. There's just a lot of efficiencies that go along with that. This is a big batch of long laterals for us, but it's not the first. We've drilled well over 30 of these two-mile laterals already. Billy and his team are doing a really nice job on the drilling. I know Chris and the and his team will do well in the completions and Glenn and his team will do well in production. So we're excited about those wells.

This is Billy here. I'll just add on to that. In the MAXCOM room, you see the different asset managers, you see the geologists in there, you see the engineers and when we have that many rigs running in the same place at the same time, you get all this group energy there and they're all looking at different things they're doing. Out of that, I mean, I know you see in the slides there, we've had 84 records across different asset areas and categories to the tune of saving $9 million already. And you just feel it and see it. And you're getting more time in zone, 94% of the time in zone. And all good.

Great. Thanks. And I just wanted to turn to hedging for a minute. With what we've seen with the gas trip looking better than it has been in a while, are you more inclined to look at getting more aggressive on gas hedging going forward, either in the near term or sort of longer term when we hopefully get past the coronavirus? Is that looking more likely, less likely, more inclined to just see what the spot will bring you?

I think, Noel, it's probably more likely. I mean, we already, as you noted in the release, have entered into some hedges for natural gas in the winter months. So we've got some hedges down between November and March already that have 250 floors, and I think they've got about 375 on the top end. and we certainly have begun to monitor the move in gas prices and I would expect that things continue to look favorable and I think we feel like that they will, that that's probably something that we would look to do to be able to lock in a little bit better natural gas price for next year would help us out quite a bit. We do have 40% of our production that's natural gas. When you're talking about producing 60 or 70 BCF a year, that extra dollar is 60 or 70 million dollars. I think it's important and something that we're paying attention to.

This is Joe. The other thing is just to Note that we're right now about 60% oil, 40% gas, and we have a number of knobs that we can turn either in the Hainesville or the Eagleford or out there in New Mexico, particularly in the Russell or Brakes area, where we should rapidly increase our gas production if we should choose to do so. So we're monitoring the hedging, but We'd kind of like to have a backup, use the hedging to back up what we're doing, either in oil or gas, to try to reduce the risk of commodity pricing. Great.

Thanks a lot.

Thank you, Noel. Thanks, Noel.

Thank you. And your next question comes from Richard Tullis from Capital One Securities. Your line is now open. Please go ahead.

Thanks. Good morning, everyone. Joe, congratulations on the strong quarter, particularly on the cost side. But jumping back to 2021 a little bit, I know it was talked about a little earlier, but with 4Q production benefiting from the state-bind wells coming online later this year, what level of drilling completion capex do you think would be necessary in 2021 or rig activity, if you'd rather look at it that way, to kind of Keep production flattish with the new oil production outlook for this year, around 41,000 a day.

Good morning, Richard. It's David. Well, I really believe that we will be able to keep our – you know, we can – we'll probably have – we could have small growth, I think. Let's say, you know, low single-digit kind of growth – Thank you very much. and then, of course, you know, at the moment, we expect that we'll have the first batch of wells from the western side of state line, the wells we're calling Vonnie, that will, you know, I think it's another dozen wells that'll be coming on, you know, right about probably the beginning of the second quarter. So that'll be another, you know, boost to our production early in the year. And then I think the Antelope Ridge team is also, you know, expecting to drill four more wells on the Rodney Robinson track beginning in the end of this year. And those wells also would probably get fracked and turn to sales about the same time, you know, end of the first quarter, first of the second quarter, kind of like the other Rodneys did this year. So I think we feel like that, you know, that we're likely to have a pretty nice boost in production in the early part of 2021. And that would, I think that would help to sustain and, you know, even some, you know, some level potentially of growth even at the three rigs in 2021. That's helpful, David.

Thank you. And just for my follow-up, you know, at San Mateo, adjusted EBITDA kind of flattish the last couple of quarters. What are current thoughts on, you know, potentially monetizing all a part of the interest there over the next one or two years? If you could update us on that.

Yeah, Richard, we're up. Foran, Van Singleton, As far as the EBITDA going fairly flat, you've had a reduction in rigs, so there's third-party contracts. They're not as plentiful as you might like, but it's also we have a growing production profile out there, and we need that capacity just to take care of ourselves and hope to add to it with more third-party contracts. contracts and I think our field staff have done a real good job of servicing those other companies and you know we like to think that we're getting a good reputation for delivering good service out there and keeping them moving so you know it's a matter of time when you build those pipelines to attract other gas and we built the pipelines particularly the expansions through the state line and up to the Stebbins area, which are great areas. And we think just, you know, kind of there's an element. We're not relying upon it, but there is an element of buildings, and they will come combined with our own production profile and the needs of some of the other third-party relationships that we already have. So there may be a little pause here and stay a little flat, but we expect that growth to pick up. particularly as people, you know, gas prices improve and people start drilling more gas wells. Water production, that's been fairly consistent and so is oil. So I think the outlook is pretty good. David, anything?

I think that was a good answer. You know, I would just add to that. Joe, you kind of said it, but... When San Mateo contemplated this expansion, what we looked at is the anchor tenant to make the economics work, and the anchor tenant is Matador. And so the fact that we're running the rigs on the San Mateo acreage does make the economics work for the expansion going forward. At some point in time, things will come back, and we'll be there at San Mateo. We'll be there with the capacity and ready to go for third parties.

All right. Thanks so much.

I appreciate it.

Thank you, Richard.

Thank you. And our next question comes from Samir Panwani from Tudor Pickering. Your line is now open. Please go ahead.

Hey, guys. Good morning. This is a bit of a hypothetical question, but, you know, on the shut-ins, if the hedge group wasn't in place, would you guys have decided to shut in more? And, you know, following on to that, what price do you think the company needs to generate full cycle returns on new drilling on an unhedged basis?

Hi, Samir. It's David. You know, I think it's always difficult to answer, you know, hypothetical questions. So, I mean, we kind of are where we are. I think there are a lot of considerations that go into making decisions on shutting in wells. And, you know, not only do you have situations with regard to different wells have different levels of operating expenses, Different wells are producing from different zones. Different wells have different kinds of artificial lift types that maybe make them easier or more difficult to shut in. Different wells have all kinds of different lease obligations. So there's many different considerations, I think, that all of we operators have to go through in terms of deciding what and how much we're going to shut in and it's not just simply, you know, it's not just simply a matter of price, you know. So I don't, you know, you have volume commitments and things like that, you know, for gas production. So I think you have to take all those things into account and I don't know that, you know, I think the hedge book helps, you know, I think that the, It's only one of any number of considerations that you try to take into account when you're making these kind of decisions.

Okay, that's helpful. And the second part of that question was, you know, as you think about, you know, what price do you think the company needs to be generating full cycle returns on new wealth?

You know, again, I don't mean to, you know, to be... I'm not going to tell you that I think that's a You know, that makes $20 work for every well that we're going to drill. But I will say that, you know, it's, again, to me it's just not a one variable, you know, situation. We have certain wells, you know, that, you know, like all operators, you've got a portfolio of locations and a portfolio of opportunities. And some, you know, are going to have higher returns, you know, than others. And in this period where... and many more. I can tell you, several years ago when we looked back and did some of our own studies, 2016 was another time when prices were very low. Then there was an increase in prices following that. We think those are some of the most economic wells that we ever drilled because of the fact that we were able to construct them for a very low cost. It's not something I think you can leave out of the equation when you're thinking about this.

Okay, okay, got it. Maybe switching gears, you know, on San Mateo, there was a question earlier on liquidity and free cash flow implications for Matador as the midstream business turns free cash flow positive, but can you talk a little bit about how San Mateo 2 could further enhance this once some of the facilities come online, both in terms of liquidity and free cash flow?

Well, I think we think it can do both very well. First of all, With regard to the liquidity part of the question, the current facility, credit facility that we have in place with regard to San Mateo is tied simply to San Mateo One's assets. So, none of the assets belonging to San Mateo Two yet are part of the credit facility. We believe that once the merger of San Mateo One and San Mateo Two Foran, Van Singleton, We feel like that there is a very good likelihood that the bank group would agree to increase the size of that facility because they'll have substantially more collateral. And with that then, once that's accomplished, then we'll have substantially more liquidity just under the credit facility associated with San Mateo. Secondly, I don't think there's any doubt that once the new plant is online and the new pipelines are in place, that we're going to see a significant increase in the revenues from San Mateo, specifically from San Mateo II as the gas from the state line begins to travel from the north and the gas and oil from Stevens starts to come to the south. And we've already added a couple of additional saltwater disposal wells up in the Stebbins area, which are already contributing to the revenue of San Mateo, too. So, you know, so I think that as we have expected and projected that we're going to see a nice bump in San Mateo's, you know, financials as, you know, coming the fourth quarter and beyond into 2021 as we get everything turned on at the state line. and Stevens.

Understood. That's Greg's color. Thank you. Yes, sir. Thanks.

Thank you. And our last question comes from Gail Nicholson from Stevens. Your line is now open. Please go ahead. Hi. Thanks for fitting me in.

The Robinson & Robinson and the Borosol have a higher NRI. Could you remind me on the 20 activity level, what is the average NRI? And then how do you think that could potentially change in 21?

You know, Gail, against David, you're right. The Rodney Robinson wells have the 87.5%. All the Boris wells have 87.5%. Anything on state lines, so the Vonnies will have 87.5%. The wells at Rustler Breaks probably tend to run between 75% and 80% on the NRIs, and that's probably pretty good elsewhere, too. We have You know, wells that run, if they're fee leases, they're mostly 75%. If they're state leases, they tend to be a little better than that, maybe plus or minus, you know, 80. And if they're the federal leases, you know, we often have the full one-eighth or 87.5%, you know, percent. And so, as you think about next year, I mean, we probably will continue running, you know, a couple of rigs at the state line. And that will, those wells should all have the 87.5%. We'll drill a few more Rodneys, but we'll also have, you know, we'll also have, I'm sure, eight or ten other wells that will have something closer to 75%.

Okay, great. And then just a follow-up on San Mateo. When you look at third-party MVCs for 20, I do believe that that upticks in 21 for the amount of MVCs for third-party. Is that correct? And can you just kind of quantify that change, 21 versus 20?

Thank you. Thank you.

Thank you. Ladies and gentlemen, this concludes 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 very much. For all of you listening in and participating, we appreciate it. The final thought is that what's been most encouraging to us is why everybody on the various areas, drilling, production, Marketing, Land, Land Administration, Evergroup, Accounting, Division Orders. Everybody has really pitched in and made the extra effort. And I know our processes are working better. The communication is better. Coordination is. And we think we're going to finish this year strongly. And next year will be even better. And as challenging as these times are, There are going to be some good opportunities come up. As David mentioned, our drilling costs are down. They'll lead to better rates of return. We think there'll be some opportunities come up. Midstream is growing, and it's a fee-based business, so it's not as subject to the volatility. Our marketing group is encouraged by the outlook for gas prices to rise. While $20 oil does present a lot of challenges, we also think there will be some opportunities to come out of this. We appreciate your interest. Anytime we can help you or answer questions for you, please give us a call. Thank you very much for joining this call. We appreciate your interest very, very much.

Ladies and gentlemen, thank you for your participation today. This concludes the program.