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 31st 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. 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 planned 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 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. We've all spent a lot of time up here, together, in the last six weeks. At a meeting of the Matador'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. Matador'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, Matador was the very first oil company to announce any such cuts.
Among the other first steps we took were to hedge 90% of our anticipated 2020 oil production, including all of our forecasted oil production in the second quarter at oil prices ranging from $35-$48 per barrel. To cut our capital spending by roughly 35% by reducing our rig count from six to three. We are prepared to take additional steps to further reduce spending if necessary. If you will now look at slide B. 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. 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 Breaks asset area and the five Leatherneck wells in the Greater Stebbins area are turned to sales during the summer, and when the 13 Boros wells in the Stateline asset area are turned to sales beginning in September and October. These are objective measures of our progress.
These Boros wells are likely to be even better than the Rodney Robinson wells, and there'll 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'll 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 loan.
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 Matador's current stock price to be a good buying opportunity. Matador'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 for its 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 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 one 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. Our first question comes from Scott Hanold from RBC Capital Markets. Your line is now open.
Yeah, thanks. Appreciate that. 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 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? First question, have you guys shut in production yet? When do you think it'll start? 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. 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%-15% of our production in those months will be shut in on average. 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. We'll proceed to shut in our production in the Delaware starting tomorrow.
Okay. That's great. I appreciate that. That 10%-15%, do you guys, 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, that 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. Those will be game time decisions as we go along.
As things exist now, and particularly with the Stateline 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.
Yes, Scott, this is Matt.
Yeah.
Good morning. I just wanted to add to what David's saying there in regards to how we're shutting these wells in and which wells are getting shut in. I think Glenn Stetson who's 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 or not. We're 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. Sounds good. Just to be clear, 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 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. 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 was just to give us the opportunity to see how things go over the quarter. I think, like I said, some of those things will probably be game time decisions, and I think we've made some allowance for that in the current guidance that we have. 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 Markets. Your line is now open. Please go ahead.
Good morning, guys. Great results.
Thanks.
Thanks, Jeff.
Wanted to stick 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 gauge your expectations for how you guys see these shut-in wells coming back? Is that a meaningful risk you guys can think about or plan for as far as bringing these wells back on? Just curious how you guys envision that plan out.
Oh, sorry, Joe, go ahead.
Yeah. Matt, I'll go first, and then if you'll finish up. Jeff, 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. 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. It could be multiple scenarios there of what we may do at different times. The one thing I think that is we trying to be consistent. We don't want to be, you know. Turn the wells on full open and then shutting them back. We want to try to be consistent and methodical through the process. Also where we're on pipe makes it easier than where you're on truck and a few circumstances like that. Matt?
Yeah, Joe, thanks. Jeff, I'll just add to what Joe's saying there. 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, say, a legacy vertical well that's on rod pump, and let's say it's making 20 or 30 barrels a day, that well's pretty easy to shut in. We go by and shut the pumping unit off, secure the wellhead, and we're ready to go on that one. An actual example, we got a well in the Delaware that has an ESP that's due for an overhaul.
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 on the ESP, and then prepare to run back in the hole and be ready to do that. 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 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. I was just kind of wondering how you guys look at the optionality of that free cash flow. Is that a Matador decision? Is that a conversation you have with your partner? I guess just 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 that'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. 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 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.
Yeah. Hi, good morning. I was wondering, as you look towards fourth quarter, you have a D&C 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 speculate on that. I would be pleased for oil to be back at $40 or $50 in 2021. If it were, then I'm sure we would probably consider perhaps adding a rig back. 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. 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 CapEx estimate that we have. Then we would have additional wells being completed in the first quarter of 2021 as well, because I think most of our Boros 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. May I have one follow-up? How's the G&A look on a per barrel basis? Should we kind of use the first quarter number and for the rest of the year? 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.
Oh, G&A outlook for the rest of the year.
Okay. I think if you'll 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 Joe referenced just a few moments ago. Those actually didn't begin until the 1st of April, so they will be second-quarter items. 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. We've had folks, I think, what'd you say, Matt, 27 or something.
Right
that have actually gone from positions here in the Dallas office to other assignments. 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 had, and we'll begin to see more of that begin to find its way into the G&A numbers going forward, Irene.
Great, thanks.
Irene, it's Matt. I just wanted to tag on to what Dave was talking about, these folks transferring job responsibilities. A lot of them are people that have gone through our MaxOps and 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. 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. 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, which they'll continue to gain experience, and they'll be even better when they come back.
Great. Thank you.
Thank you, Irene. Anytime.
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 thing, but I just wanted to verify, David, when you said that roughly 10%-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 view as sort of either curtailments or these restricted flow rates like on the Rodney Robinson? Is that included in that number, or is the 10-15 just-
Yes
physical shut-ins?
John, it's David. 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. David, it may not be, but is it possible to sort of break out how much of that you think is physical shut-ins versus sort of the curtailment, 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. Just my follow-up question, just to make sure that I've got the completion cadence right. 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, I assume you get those 10 in 3Q, and then the 13 Boros wells, which are basically straddle 3Q, 4Q with September, October. Do you just take half of those Boros and put them in 3Q for right now and the other remaining half in 4Q?
Yeah. I think what's most likely to happen is that the Ray wells will end up being Q2 completions. I think the Leathernecks will end up being two Q3 completions. The Boros wells, I think that maybe it'll be more like two-thirds in September and one-third in October. 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 swamp the facilities initially. Number two, to get a feel for what the volumes are gonna be. Number three, it'll be the first flows that are headed north on the new pipeline up to San Mateo. 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 it, David. Congratulations to everybody on a great quarter.
Thank you, John.
Thanks, John.
Thank you. Your next question comes from Neal Dingmann from SunTrust. Your line is now open. Please go ahead.
Morning, all. My first question, probably for David or Matt. I'm just wondering, David, when you think about we haven't heard too much, you've 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 Neal, I didn't exactly understand your question. Are you just asking about h ow difficult it will be to bring the wells back on or what it might cost?
Yeah. Just really, Matt, from the shut-ins, we've heard Schlumberger talk about a lot of stimulation needed to bring things back. Again, I get it if you're curtailing. I'm just wondering 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.
Yeah, Neal, 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. 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. When we'll shut a well that's on gas lifting, we'll just go ahead and shut the well in and leave the gas lift valves in place.
We'll put the compressor on standby for that time period, and then 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 the 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. 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've got in place.
Very good details. 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, Neal, the answer is yes to that. We never had a lot of AMT credits, even with the passing of the new tax act. Yes, I believe there's probably about $3 million that we have applied or have requested be accelerated into 2020 as a function of the CARES Act. I think there's another $3 million that we're awaiting just on kind of the more normal cycle coming in in 2020. Altogether, maybe something like $6 million.
Very good. Thanks. 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, Neal. I appreciate. My feelings were hurt there a little bit because I wasn't getting a question. No, we really appreciate you. 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 from the first of the year at $62 a barrel down to $20. We've got shareholders that the shares lost 90% of their value. What else could you do? We were ready to take a second cut. It appears that things have been turned around. Maybe that won't have to be done. We want our alignment with the shareholders to be clear. 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, one raised his hand, our audit committee chair, and said, "I want to volunteer a 25% pay cut, too." It went all around the boardroom, and everybody agreed to do that. I think that's a better example of people trying to do the right thing than anything that I did and the executive team did, and everybody's pitched in. This past six weeks, there has really been a lot of extra effort from people trying to do the right thing and reposition Matador and make it 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 helped.
One of the best moves was David and them restructuring the hedges to take them so that we got a much larger percentage, up 90%, 100% for the rest of this quarter coverage on the hedges, and with a bottom price of about $35-$37. We still have a few $48, but that took a lot of the risk out going forward. It's been all hands on deck to keep things moving. The credits really do other people, but I appreciate you giving me that credit, Neal, and I'll take it.
Joe, and I'll still consider you a saint, Joe.
Thanks, Neal.
Thank you. Your next question comes from Noel Parks from Coker & Palmer. Your line is now open. Please go ahead.
Good morning.
Hi, Noel.
I was wondering about the mention you made earlier about the Boros wells, and that you expected that they would be even better than the Rodney Robinson one. I was wondering what you attribute that to, 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 the rock effectiveness.
Yeah. Hi, Noel, it's David. 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 reservoir quality are likely to be in the entire Delaware Basin. I think we're just very optimistic about the potential for those wells. 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.
We think it's an area that offers a lot of opportunity. Proof will be in the pudding, of course, but I think we're very optimistic. 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 fracking some of these wells here before too very long and see what we got.
Noel , this is Matt, 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 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 rigs 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 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 his team will do well in the completions. Glenn and his team will do well in production. We're excited about those wells.
Hello, 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. 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 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. 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. Just wanted to turn to hedging for a minute. With what we've seen with the gas strip 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. We already, as you note in the release, have entered into some hedges for natural gas in the winter months. 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. We certainly have begun to monitor the move in gas prices, and I would expect that if 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, and when you're talking about producing 60 or 70 Bcf a year, that extra $1 is $60 million or $70 million. 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 out 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. We're monitoring the hedging, but we kind of like to have a backup, use the hedging to back up what we're doing in 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. 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.
Good.
Jumping back to 2021 a little bit, I know it was talked about a little earlier, with 4Q production benefiting from the Stateline 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 could have small growth, I think, let's say low single-digit kind of growth next year, even if we just maintain the three rigs. Some of that'll be timing related. 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 the first part of 2021. 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. I think it's another dozen wells that'll be coming on right about probably the beginning of the second quarter. That'll be another boost to our production early in the year.
I think the Antelope Ridge team is also expecting to drill four more wells on the Rodney Robinson tract beginning in the end of this year. Those wells also would probably get fracked and turned to sales about the same time, end of the first quarter, first of the second quarter, kind of like the other Rodneys did this year. I think we feel like that we're likely to have a pretty nice boost in production in the early part of 2021. I think that would help to sustain even some level potentially of growth, even at the three rigs in 2021.
All right. That's helpful, David. Thank you. Just for my follow-up, with San Mateo adjusted EBITDA kind of flattish the last couple of quarters, what are current thoughts on potentially monetizing all or part of the interest there over the next one or two years? If you could update us on that.
Richard, we're a public company, as such, we try to play a straight game. We've sold things in the past. We sold First Matador, we sold part of our rainfall to Chesapeake, we sold a plant to EnLink. That's a hard one to predict, particularly in a time of volatile pricing. 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, there's third party contracts are not as plentiful as you might like. It's also, we have a growing production profile out there, we need that capacity, just to take care of ourselves hope to add to it with more third-party contracts. I think our field staff have done a real good job of servicing those other companies.
We like to think that we're getting a good reputation for delivering good service out there and keeping them moving. It's a matter of time, when you build those pipelines to attract other gas. We built the pipelines, particularly the expansion through the Stateline and up to the Stebbins area, which are great areas. We think there's an element, we're not reliant upon it, but there is an element of build it 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.
There may be a little pause here and stay a little flat, but we expect that growth to pick up, particularly as gas prices improve and people start drilling more gas wells. Water production, that's been fairly consistent, and so is oil. I think the outlook is pretty good. David, anything to add?
No, I think that was a good answer.
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. The fact that we're running the rigs on the San Mateo acreage does make the economics work for the expansion going forward. Like you said, Joe, at some point in time, things will come back, and we'll be there. San Mateo will be there with the capacity and ready to go for third parties.
All right. Thanks so much. I appreciate it.
Thank you.
Thank you, Richard.
Thank you. 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? 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. We are where we are. I think there are a lot of considerations that go into making decisions on shutting in wells. 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 types of artificial lift types that maybe make them easier or more difficult to shut in. Different wells have all kinds of different lease obligations. 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. It's not just simply a matter of price. You have volume commitments and things like that for gas production.
I think you have to take all those things into account, and I don't know that I think the 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 kind of decisions.
Okay, that's helpful. 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 obfuscate here or anything, but I think that's also a difficult question to answer because of the fact that price and service costs tend to go hand in hand. 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. Now I'm not gonna tell you that I think that makes $20 work for every well that we're gonna drill. 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 a portfolio of opportunities and some you know are going to have higher returns than others.
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 gonna be economic in the long run. 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. 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. 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. Got it. Maybe switching gears, on San Mateo, there was a question earlier on liquidity and free cash flow implications from Matador as the midstream business turns free cash flow positive. Can you talk a little bit about how San Mateo II could further enhance this once some of the facilities come online, both in terms of liquidity and free cash flow?
I think we think it can do both very well. First of all, with regard to the liquidity part of the question, the current credit facility that we have in place with regard to San Mateo is tied simply to San Mateo I's assets. None of the assets belonging to San Mateo II yet are part of the credit facility. We believe that once the merger of San Mateo I and San Mateo II is completed, which both parties are working on at this time, and I think we would expect that to happen down the road here. The assets of San Mateo II 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.
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 with the-- and specifically from San Mateo II 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. 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 II.
I think that as we have expected and projected that we're going to see a nice bump in San Mateo's financials coming the fourth quarter and beyond into 2021 as we get everything turned on at the Stateline and Stebbins.
Understood. That's great color. Thank you.
Yes, sir. Thanks.
Thank you. Our last question comes from Gail Nicholson from Stephens. Your line is now open. Please go ahead.
Hi. Thanks for fitting me in. The Rodney Robinson and the Boros wells have a higher NRI. Could you remind me on the 2020 activity level, what is the average NRI? How do you think that could potentially change in 2021?
Gail, this is David. You're right. The Rodney Robinson wells have the 87.5%. All the Boros wells have 87.5%. Anything on Stateline, the Bonnies 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 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 80%. If they're the federal leases, we often have the full one-eighth or 87.5%. As you think about next year, 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, eight or 10 other wells that will have something closer to 75%.
Okay, great. Just a follow-up on San Mateo. When you look at third-party MVCs for 2020, I do believe that that upticks in 2021 for the amount of MVCs for third party. Is that correct? Can you just quantify that change 2021 versus 2020?
Well, the answer is it's correct. I probably would prefer not to quantify the amount just from the standpoint that consider that sort of confidential between San Mateo and its customers. To answer your question, yes, we would expect an uptick in the volume in 2021.
Okay, great. 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 the way everybody on the various areas, drilling, production, marketing, land administration, every group, accounting, division orders, everybody has really pitched in and made the extra effort. 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. 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'll be some opportunities come out of this. 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 much.
Well, ladies and gentlemen, thank you for your participation today. This concludes the program.