Good morning, ladies and gentlemen. Welcome to the First Quarter 2020 Matador Resources Company Earnings Conference Call. My name is Danialle, and I’ll 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, Danialle, 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 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 planned for today’s earnings conference call is 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 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 identify 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 too, and that, we all spent a lot of time up here together in the last six weeks. At a meeting of the Matador Board on March 10, 2020, I volunteered to take a 25% paycut. The Board joined me in taking a 25% paycut too. Matador’s President and the Executive Vice Presidents all then took a 20% paycut, the other Vice Presidents took a 10% paycut, and the rest of the staff took a 5% paycut. According to one prominent energy industry compensation study, Matador was the very first company -- oil company to announce any such cuts. Among the other first steps we took were…

Thank you. [Operator Instructions] And our first question comes from Scott Hanold from RBC Capital Markets. Your line is now open.

Yes. Thanks. I appreciate that and great quarter, guys. I think, a lot of the narrative for the industry in the next couple of months is really going to pivot to the 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 the percentage of shut-in, we’ve shut-in some -- or will shut-in some of our production in the Delaware and in the Eagle Ford in May and in June. We anticipate relative to what our expectations were for what that production could have been, that will 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 in the Eagle Ford in the last couple of days, and we will proceed to shut-in our production in the Delaware starting tomorrow.

Okay. That’s great. I appreciate that. And that 10% to 15%, I mean, you guys, with some of those obviously, pretty strong wells coming on in the back half of the year, do you plan on -- 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?

Yes. 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 with frack and get those wells drilled out and put on line, get initial tests on them and then if need be, we may turn 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 Stateline wells and the other wells, which was talked about, in particular the Rays and 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 is saying there in regards to how we’re setting these wells in and which wells are getting shut-in. I think, Glenn Stetson, he’s our Head of Production, he’s done -- 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 where they’re economic and where they’re 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. It sounds good. And just to be clear on just -- maybe my question wasn’t as clear. But, in your guidance, do you assume there is continued curtailment through the rest of this year on the Rodney Robinson and with the Boros wells?

I think, it’s fair to say 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. I mean, one reason that I think we were -- we said that we’d update again on third quarter expectations and fourth quarter expectations during next times earnings release was just to give us the opportunity to see how things go over the quarter. But -- so I think, like I said, some of those things will probably be game-time decisions, but in the -- and I think we’ve made some allowance for that in the current guidance that we have. 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 Grampp from Northland Capital Management. Your line is now open. Please go ahead.

I 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 the 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 bringing these wells back on? Just kind of curious how you guys envision that plan out.

I’m sorry. Joe, go ahead.

Yes. Matt, I’ll go first and then, if you will, finish. But, Jeff, the one thing that we do is we did 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, 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. But one thing I think that is we’re trying to be consistent, we don’t want to be -- turn the wells on full open and then shut them back. We want to try to be consistent and methodical through the process. And also, where we’re on pipe that makes it easier than where you’re on truck and a few circumstances like that. Matt?

Yes. Joe, thank you. Jeff, I’ll just add to what Joe is saying. There are some mechanical issues around which wells are shut-in and that we do seriously contemplate, and I’ll just give you a couple of examples. If we got a say a legacy vertical well that’s on rod pump and it’s making -- let’s say, it’s making 20 or 30 barrels a day, that well is pretty easy to shut-in. We go by and secure or shut the pumping unit off, secure the wellhead and we’re ready to go on that one. Another example is, we’ve got a in actual event, we got a well in the Delaware that has an ESP that’s due for an overhaul. And so, we talked about that earlier and just decided the appropriate thing to do is go ahead and pull that ESP out, do the inspection on the tubing, do the overhaul in the ESP and then prepare to run back in the hole and be ready to do that. So, that’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. Great details there. My follow-up on the midstream side, release 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 Matador decision, is that a conversation you have with your partner, and I guess this maybe reminding us how much control you have over what to do with that free cash?

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. And we have a very good working relationship with our partners at Five Point. And so, I would expect that whatever we would decide would be a unanimous decision between the partnership and everything else has to this point. So, I’m sure that they would be consulted. There are -- 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. And may be the best thing that we -- we’ll just have to decide which way the partnership wants to go there. But, it wouldn’t surprise me if 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 Matador’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.

Yes. Hi. Good morning. I was wondering, as you look towards fourth quarter, you have D&C CapEx of $56 million with three rigs, probably likely near 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, right, $40 or $50?

Yes. Hey, Irene. This is David. Well, I think it’s probably a little early yet 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 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 either 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 CapEx estimate 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 Bonnie [ph] wells at Stateline would be beginning to complete a lot of those wells. We’ll have some additional Rodney Robinson wells by that time too.

Okay. I have one follow-up. How does the G&A look on a per barrel basis? Do we kind of use the first quarter number and -- for the rest of the year? And that’s all I have.

Can you ask it again, Irene? I’m sorry. It kind of cut out and I didn’t understand it completely.

G&A outlook for the rest of the year.

Okay. I think, if you -- I think, if you’ll kind of just look in the slide deck that we provided, 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 BOE 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 the Joe referenced just a few moments ago. Those actually didn’t begin until the 1st of April. So, they will be second quarter items. And there are also some changes that we made. We’ve referenced in previous releases that some of the staff have moved into positions in the field or maybe in our measurement area in San Mateo that -- so, we’ve had folks I think, what would 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 focused to cut down on some of the contract expenses that we had, and we’ll begin to see more of that begin to find its way into the G&A numbers going forward, Irene.

Thank you.

Irene, I just wanted to tag on to what David’s talking about these folks transferring job responsibilities. A lot of them are people that have gone through our MaxOps -- or Billy’s MaxOps and MaxCom 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. And so, we’ve asked them and they were very excited about being able to go back and run drilling rigs and run frack spreads and do all that stuff. I think that 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, so they’ll continue to gain experience in it. They will be even better when they come back.

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 belabor the shut-in thing. But, I just wanted to verify, David, when you said that roughly 10% to 15% of production shut-in is kind of what you’re assuming. When you say shut-in, does that include in that number what I would view as sort of your curtailments for these restricted flow rates, like on the Rodney Robinson? Is that included in that number or is it just physical shut-ins?

Yes, John. It’s David. Yes. Thank you for giving me a chance to clarify that because that is true. I mean, when I said shut-ins, I’m thinking shut-ins or curtailments or restricted flow. I’ve got that all sorted 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 curtailments like what’s happening with Rodney Robinson?

I would imagine that -- I would say, probably, maybe John, half, 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 you 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 get those 10 in 3Q, and then 13 Boros wells, which basically straddle 3Q, 4Q with September-October, you just take half of those Boros and put them in 3Q for right now and the other the remaining half in 4Q?

Yes. I think, what’s most likely to happen is that the Ray wells will end up being Q2 completions. And I think the Leathernecks will end up being to Q3 completions. And the Boros wells, I think that -- maybe it’ll be more like a two thirds in September and one third in October. But, there’s 13 of them and they will 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 swamp the facilities initially. Number two, to get a feel for what the volumes are going to be. Number three, it’ll be the first flows that are headed north on the new pipeline upto San Mateo. So, I think we just want to kind of stage things in rather than go out on day one and just open all the wells immediately.

That’s great. I appreciate, Dave. And congratulations to everybody on a great quarter.

Thank you, John.

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

Good morning, all. My first question is probably for David or Matt. I’m just wondering, David, when you think of that, we haven’t heard too much you’ve made some 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 is really not too much timing or cost involved. But, I just wanted to sort of double check that from the experts.

Neal, I didn’t exactly understand your question. Are you just asking about how difficult is to bring thee well back on or what it might...

Yes. Just really, Matt, from the shut-ins, is there -- we’ve heard Schlumberger talk about a lot of stimulation needed to bring things back. And again, I get it if you curtail, and I just wondered about cost or timing. You all don’t appear like there’s too much involved. And I just want to sort of double check that.

Yes. Neal, I think it will 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, there 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 left, a well that’s on gas lift, we’ll just go ahead and shut the well and leave the gas, the valves in place. We’ll put the compressor on standby for that time period. And when we’re ready to go back to work there, we go back out, open the well up, if it’s built 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 -- it’s probably very few of the wells that we would shut in and 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 either change out the artificial lift system or overhaul what we got in place.

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

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

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

Thanks, Neal. I appreciate. My feelings were hurt there a little bit, because I wasn’t getting that question. But, no, we really appreciate it. I mean, it’s the right thing to do. And I’m not heroic by any means. It just was the right thing to do. We were looking at prices going from first of the year at $62 a barrel down to $20. And we’ve got shareholders that had -- the shares lost 90% of their value. I mean, what else could you do? And we’re ready to -- we were ready to take a second cut but it appears that things have been turned around and maybe that won’t have to be done. But, we want our alignment with the shareholders to be clear. And I don’t want anybody 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, one raised his hand, our Audit Committee Chair and said I want to volunteer 25% paycheck too, and they went all around the Board room and everybody agreed to do that. So, I think that’s a better example of people trying to do the right thing and anything that I did and the executive team did and everybody pitched in. And these past 6 weeks, there has really been a lot of extra effort from people trying to do the right thing and reposition Matador and making clear that, we had a plan, a good plan to address, work through the coronavirus as well as these poor pricing, and we were really helpful. And the best moves was David and them restructuring the hedges to take them so that we got a much percentage, 90%, 100% for the rest of this quarter coverage on the hedges. It was a base price of -- a 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 everybody’s -- it’s been all hands on deck to get -- to keep things moving. So, the credit is really to other people. But, I appreciate you giving me that credit, Neal. And I’ll take it.

We all still consider you Saint, Joe.

Thanks, Neal.

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

I’m wondering about the mention you made earlier about Boros wells, and that you expected that they would be even better than the Rodney Robinson ones. So, I was wondering what you attribute that too. And also wondering, with the outperformance you saw in the first six wells, would love to hear some more about what the components of that was, whether it’s just rock, frack effectiveness.

Well, I think that’s right. I think that it’s largely just a function of the rocks. And clearly, that’s an area there at the Stateline that we feel like is some of the very best -- some of the very best reservoir quality are likely to be in the entire Delaware basin. And so, I think we’re just -- we’re just very optimistic about the potential for those wells. I mean, we’ve liked the look of the section from the Avalon through the lower parts of the Wolfcamp ever since we’ve been working in the basin. And we think it’s an area that offers a lot of opportunity. And I mean, proof will be in the pudding, of course, but I think we’re very optimistic. And so far, the drilling on those wells has gone well. And so, we’re anxious to get that stage behind us and get to start to 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, a lot of the efficiencies that you get just by having ever all the rigs right there close by. We’re sharing some of the mud [ph] 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 regions the same time. There’s just a lot of efficiencies that go along with that. And this is a big batch of long laterals for us, but it’s not the first. We drilled well over 30 of these 2-mile laterals already. So, Billy and his team are doing a really nice job on the drilling. And I know Chris and his team will do well with 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 manager, you see the geologists in there, you see the engineers. And 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. And out of that, I mean, I know you see in the slides there, we’ve had 84 records across the 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 and in zone 94% of the time, and zone and all good.

And then, just wanted to turn to hedging for a minute. What we’ve seen with the gas strip looking better than it has been in a while. Are you more inclined to getting more aggressive on gas hedging going forward, either in the near term or sort of longer term when we get -- 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 know, 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 has 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, but that’s probably something that we would 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. So, we do have 40% of our production that’s natural gas. And when you’re talking about producing 60 BCF or 70 BCF a year of that, an extra dollar is $60 or $70 million. So, 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 Haynesville or the Eagle Ford or at there in New Mexico, particularly in the Rustler Breaks area, where we could rapidly increase our gas production, if we should choose to do so. So, we’re monitoring the hedging. But, we kind of like to have a backup to use the hedging to backup what we’re doing, either in oil or gas, to try to reduce the risk of commodity pricing.

Great. Thanks a lot.

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. Something back to 2021 a little bit. I know you talked about a little earlier. But, with the 4Q production benefiting from the Stateline wells coming on line 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 -- we can -- we’ll probably have -- we could have small growth, I think, let’s say, low-single-digit kind of growth next year, even if we just maintain the 3 rigs. I think that -- and some of that will be timing related. But, as you have noted, we do have a significant influx of production from the first 13 wells there at the Stateline that’ll come on mostly in the fourth quarter. And that’ll carry over nicely into first part of 2021. And then, of course, at the moment, we expect that we’ll have the first batch of wells from the western side of Stateline, the wells, we’re calling Bonnie, [ph] that will -- I think it’s another dozen wells that will be coming on right about probably the beginning of the second quarter. So, that’ll be another boost to our production early in the year. And then I think the Antelope Ridge team is also 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 turned to sales, about the same time into the first quarter versus the second quarter, kind of like the other Rodney’s did this year. So, I think, we feel like 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 even some level potentially in growth, even after three rigs in 2021.

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

Yes. Richard, we’re a public company and as such we try to play a straight game. We’ve sold things in the past, we sold first Matador, and we sold part of our Haynesville to Chesapeake and we sold a plant to EnLink. So, that’s a hard one to predict, particularly in the time of volatile pricing. But if we got a serious offer, we would give it serious consideration. As far as the EBITDA going fairly flat, you’ve had a reduction in rigs. So, there’s third party contracts, 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. And I think our field staff have done a really good job of servicing those other companies. And we like to think that we’re getting a good reputation for delivering good service out there and keeping them moving. So, it’s a matter of time when you build those pipelines to attract other gas and we built the pipelines, particularly the expansion through the Stateline and up to the Stebbins Area, which are great areas. And we think just kind of -- there’s an element -- we’re not relying upon it, but there is an element of building and they will 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 out, particularly as people -- 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?

No. I think, that was a good answer.

I would just do that, Joe, and you kind of said it. But, San Mateo contemplated this expansion, what we would look at is the anchor tenants make economics work and the anchor tenant to Matador. And so, the fact that we’re running the rigs on San Mateo acreage does make the economics work for the expansion going forward. And I would say that at some point in time things will come back and we’ll be there and San Mateo will be there with the capacity and ready to go for third party.

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

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

Hi, Sameer. It’s David. I think, it’s always difficult to answer a hypothetical question. 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 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 times of artificial lift tops that may be make them easier or more difficult to shut-in. Different wells have all kinds of different lease obligations. And so, there’s many different considerations I think that all of the 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 -- it’s not just simply a matter of price. So, I don’t -- you have volume commitments and things like that for gas production. So, I think, you have to take all those things into account, and I don’t know that -- I think hedge book helps. I think that it’s only one of any number of considerations that you try to take into account when you’re making these kinds of decisions.

Okay. That’s helpful. And the second part of that question was, as you think about what price do you think the Company needs to be generating full cycle returns on new wells?

Again, I don’t mean to be -- obviously stay here or anything, but I think that’s also kind of a difficult question to answer because of the fact that price and service costs tend to go hand-in-hand. And currently, some of the prices that we’re projecting, that we’re going to be able to drill and complete these wells for are the best that we’ve ever seen. So now, I’m not going to tell you that I think that that means $20 work for every well that we’re going to drill. But, I will say that again, to me, it’s just not a one variable situation. We have certain wells that like all operators, you’ve got a portfolio of locations and the portfolio of opportunities, and some are going to have higher returns than others. And in this period where prices are low and costs are low, it makes a difference in terms of the decisions you make on which wells to drill and whether they’re going to be economic in the long run. So, I just hesitate to give you a specific price because I think there’s a lot that goes into making those decisions, and it’s not just all about price. Cost makes a lot of difference too. And I can tell you, several years ago, when we look back and do some of our own studies, 2016 was another time when prices were very low, then there was a increase in prices following that. And 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. And so, it’s just -- it’s not something I think you can leave out of the equation when you’re thinking about this.

Maybe switching gears 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 one, some of the facilities come on line, both in terms of liquidity and free cash flow?

Well, I think, we think it can do both very well. First of all, with regards 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 1’s assets. So, none of the assets belonging to San Mateo 2 yet are part of the credit facility. We believe that once the merger of San Mateo 1 and San Mateo 2 is completed, which both parties are working on at this time and I think we would expect that to happen down the road here, then the assets of San Mateo 2 will be brought into the credit facility. When they are, we feel like that there’s 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 would have sufficient -- substantially more liquidity just under our -- under the credit facility associated with San Mateo. Secondly, I don’t think there’s any doubt that once the new plant is on line and the new pipelines are in place that we’re going to see a significant increase in the revenues from San Mateo with the -- and specifically from San Mateo 2 as the gas from the Stateline begins to travel from the north and the gas and oil from Stebbins starts to come to the south. And we’ve already added a couple of additional salt water disposal wells up in the Stebbins area, which are already contributing to the revenue on San Mateo 2. So, I think that as we have expected and projected that we’re going to see a nice bump in San Mateo’s financials as -- coming the fourth quarter and beyond into 2021, as we get everything turned on at the Stateline and Stebbins.

Thank you. And our last question comes from Gail Nicholson from Stephens. Your line is now open. Please go ahead.

So, Rodney Robinson and Boros wells 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’re right. The Rodney Robinson wells have the 87.5%, all the Boros wells have 87.5%. Anything on Statelines, so the Bonnies [ph] will have a 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. I mean, we have wells that run, if their fee leases, they’re mostly 75%; if their state leases, they tend to be a little better than that, maybe plus or minus 80, and if they’re the federal leases, we often have the full one-eighth or 87.5%. And so, as you think about next year, I mean, we probably will continue running a couple of rigs at the Stateline and those wells should all have the 87.5%. We’ll drill a few more Rodneys. But we’ll also have I’m sure, 8 or 10 other wells, but we’ll 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, do you believe that that upticks in ‘21, the amount of MVC for third-party, is that correct? And can you just kind of quantify that change, ‘21 versus ‘20?

The answer is, it’s correct. I probably would prefer not to quantify the amount just from the standpoint that, consider that’s sort of confidential between the San Mateo and its customers. But to answer your question, yes, we would expect an uptick in the volume in 2021.

Okay, great. Thank you.

Thank you, Gail.

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 to all of you listening in and participating. We appreciate it. The final thought is, is that the most encouraging to us is everybody on the various areas drilling, production, marketing, land, land administration, every group, accounting, divisional 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 strong -- strongly and next year will be even better. And 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 the better rates of return. We think there will 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. So, while $20 oil does present a lot of challenges and we also think there will be some opportunities to come out of this. So, we appreciate your interest. And anytime we can help you or answer questions for you, please give us a call. And 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.