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. 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 Smit, Capital Markets Coordinator for Matador. Mr. Smit, you may proceed.
Thank you, Danielle, and good morning, everyone, Thank you for joining us for Matador's Q1 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 Q1 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 5 slides identified as Chairman's remarks, slides A through E to add some color and detail. Please let me know if this works this additional information works out to be helpful to you. If you'll begin by looking at Slide A, you'll see that Q1 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 crisis of the novel coronavirus and the abrupt decline in oil 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 6 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. Mad Door's President and the Executive Vice Presidents all then took a 20% paycheck. 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, Maddoor 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 oil production, including all of our forecasted oil production in the 2nd quarter at oil prices ranging from $35 to $48 per barrel and to cut our capital spending by roughly 35% by reducing our rig count from 6 to 3. We are prepared to take additional steps to further reduce spending if necessary. If you will now look at Slide B, throughout the Q1, 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 equipment wells this past quarter was $25,000,000 less than our original estimates for the Q1 of 2020 and we estimate that $15,000,000 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 $11.65 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 2 mile laterals. These results bring us to Slide C, which indicates by the Q4 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 4 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 25,000,000 cubic feet of natural gas per day. The other three production milestones should occur when the 5 Ray wells in the Russell Brace asset area and the 5 Leatherneck wells in the Greater Stebbins area are turned to sales during the summer and when the 13 Boris wells in the Stateline asset area are turned to sales beginning in September October. These are objective measures of our progress.
These Boris 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 will look at Slide B, you'll see that we had approximately 340,000,000 dollars of our elected commitment available at the end of the Q1 and another $200,000,000 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 beyond. We consider Maddoor's current stock price to be a good buying opportunity. Maddoor's assets include 2 successful businesses, 1 in exploration and production and 1 in midstream as well as 152,000,000 barrels of oil and 646 Bcf approved oil and natural gas reserves respectively and 128 1,000 net acres in the Delaware Basin for its 117,000,000 shares outstanding.
Slide E shows the steady growth in our proved reserves and the amount of reserves each individual shareholder proportionately 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. And our first question comes from Scott Hanold from RBC Capital Markets. Your line is now open.
Yes, thanks. 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 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 will start? And what is your sort of base case and maybe stretch case on what the shut in levels could get to?
Scott, it's David Lancaster. 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 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 is that 10% to 15%, I mean, do 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 and frac 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 Stateline wells and the other wells that Joe 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 Mike.
Yes. And I just wanted to add to what David is saying there in regards to how we're shutting these wells in and which wells are getting shut in. I think Glenn Stetson, who is our Head of Production has done a 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. Okay. Sounds good. And just to be clear on just 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 Boris 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 what their original rates are. I mean, one reason that I think we were we said that we'd update again on 3rd quarter expectations and 4th quarter expectations during next time's 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. Appreciate that. Thank you.
Thank you. Your next question comes from Jeff Grampp from North Link Capital Management. Your line is now open. Please go ahead.
Good morning, guys. Great results.
Thanks, Jeff.
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 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'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 it's more than one variable, a lot of its 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 turn the wells on full open and then shutting 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? Yes, Joe. Thanks.
And Jeff, I'll just add to what Joe is saying there. There are some mechanical issues around
which wells we shut in that we say, a legacy 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 the or shut the pumping unit off, secure the wellhead and we're ready to go on that one. Another example is we've got an actual example, 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 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. 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 details there. And my follow-up on the midstream side, Elyse mentioned San Mateo going to a free cash flow positive position next year. I assume that the 2 likely decisions with that free cash flow is either to pay down that bank deck 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 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. 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 the San Mateo's debt or we can also use it to enhance the distributions that are made to each party. And it may be that the best thing that we decide, we'll just have to decide which way the partnership wants to go there. So 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 Q4, you have a D and C CapEx of 56,000,000 dollars with 3 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 like $40 or $50
Yes. Irene, it's David. Well, I think that 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 do that. And I think certainly through the remainder of this year, we're going to stay with the 3 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 4th 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 Q4 with the CapEx estimate that we have. And then we would have additional wells being completed in the Q1 of 2021 as well, because I think most of our Bonney wells at the Stateline 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 and A look on a per barrel basis? Should we kind of use the 1st quarter number and for the rest of the year? And that's all I have.
Can you ask it again, Irene? I'm sorry, you kind of cut out and I didn't understand it completely.
G and A outlook for the rest of the year.
Okay. 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 and A going forward for the rest of the year. I think we would expect that our G and A per BOE would be down some from what we reported in the Q1, because there are some additional G and 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 April. So they will be 2nd quarter items. And there were 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, would 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 and A numbers going forward Irene. Irene, this
is Matt. I just wanted to tack on 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 1st 2 or 3 years in the field.
And so we've asked them and they were very excited about being able go back and run drilling rigs and run frac 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. 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 want 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 view as sort of either curtailments or these restricted flow rates like on the Rodney Robinson, is that included in that number or is it 10% to 15% 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 we say when we're saying 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?
I would imagine that I would say probably maybe John Half, maybe 2 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 Jean gave with the 5 Ray wells and the 5 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 the 13 Borys wells, which are basically straddled 3Q, 4Q with September, October, do 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 rig wells 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 will be more like 2 thirds in September and 1 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 3 or 4 wells at a time during September early October for several reasons.
Number 1, just don't want to swamp the facilities initially. Number 2, to get a feel for what the volumes are going to be. Number 3, it will be the first flows that are headed north on the new pipeline up to San Mateo. So I think we just want to kind of stage things in rather than go out on day 1 and just open all the wells immediately.
That's great. I appreciate Dave and congratulations to everybody on a great quarter.
Thank you, John. Thanks, 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 about 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
will be to bring the light back on or what it might cause? 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, it's a curtail and I'm just wondering about cost or timing. You all don't appear like there's too much involved. 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, 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 in, we'll just go ahead and shut the well in, 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'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 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 the 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. 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, Neal. The answer is yes to that. I think but we never had a lot of A and T credits even with the passing of the new tax act. But yes, I believe there's about probably about $3,000,000 that we have applied or had requested be accelerated into 2020 as a function of the CARES Act. And I think there's another $3,000,000 that we're awaiting just on kind of the more normal cycle coming in, in 2020.
So altogether, maybe something like $6,000,000
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 there a little bit because I wasn't getting the question. But now we really appreciate you. I mean it's 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 1st 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're we want our alignment with the shareholders to be clear.
And I don't want anybody to think I'm a saint because I'm not, it's just the right thing. A really nice thing was without any prompting, our board immediately 1, raised his hand, our audit committee chair and said, I want to volunteer a 25% pay cut too. And they went all around the boardroom and everybody agreed to do that. So 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. And this past 6 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 really help on the best moves was David and them restructuring the hedges to take them so that we got a much larger 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 30 $7 We still have a few $48 but that took a lot of the risk out going forward. And our everybody's it's been all hands on deck to keep things moving. So the credits really do other people, but I appreciate you give me that credit, Neil, and I'll take it.
Joe, and 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.
Hi, Noah. Hello.
I was wondering about the mention you made earlier about the Boris wells and that you expected that they would be even better than the Rodney Robinson 1. So I was wondering what you attribute that to and also wondering with the outperformance you saw in the first six wells, We'd love to hear some more about what the components of that was, whether it's just the rock, back effectiveness.
Yes. Hi, Noel, it's David. Well, I think that that's right. I think that it's largely just a function of it's just a function of the rocks. And clearly, that's an area there at the state line that we feel like is some of the very best reservoir quality are likely to be in the entire Delaware Basin.
And so I think 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.
No, listen, 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, 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 systems we're able to share. We're sharing some of the supervision.
We're able to reduce some of that. Our superintendents are 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.
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. And so Billy and his team are doing a really nice job on the drilling. And I know Chris and his team will do well in the completions and Grant 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. And 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 $9,000,000 already.
And you just feel it and see it and you're getting more time in zone 94% of the time and zone and all good.
Great. Thanks. And 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 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 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 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. So 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 an extra dollar is $60,000,000 or $70,000,000 So I think it's important and something that we're paying attention to.
The other thing that 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 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 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. Jumping back to 2021 a little bit, I know it was talked about a little earlier. But 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?
Richard, it's
David. Well, I really believe that we will be able to keep our we can we'll probably have we can 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 will come on mostly in the Q4, and that will carry over nicely into the 1st part of 2021. And then, of course, at the moment, we expect that we'll have the 1st batch of wells from the western side of Stateline, the wells we're calling Vonnie, that will I think it's another dozen wells that will be coming on right about probably the beginning of Q2. So that will be another boost to our production early in the year.
And then I think the Antelope Ridge team is also expecting to drill 4 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 end of the Q1, 1st to 2nd 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 of growth even at the 3 rigs in 2021.
That's helpful, David. Thank you. 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 or part of the interest there over the next 1 or 2 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.
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 a 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 3rd party contracts are 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 3rd party contracts. And I think our field staff have done a real 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 state line and up to the Stebbins area, which are great areas. And we think just kind of a little there's an element, we're not relying upon it, but there is an element of building 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 gas prices improve and people start drilling more gas wells. Water production, that's going to 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 add to that, Joe, and you kind of said it, but when San Mateo contemplated this expansion, what we would look 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. And as you said, 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 3rd parties.
Right. Thanks so much. I appreciate.
Thank you, Richard.
Thank you. And our next question comes from Sameer 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 on the shut ins, if the hedge book wasn't in place, would you guys have decided to shut in more? And 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, Sameer, it's David. I think it's always difficult to answer 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 setting 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 types of artificial lift tops that maybe 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 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. 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 skater 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 makes $20 work for every well that we're going to drill. But I will say that it's 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.
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 an 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're 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.
Okay, 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. But 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?
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 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 II will be brought into the credit facility. When they are, we feel like that there is very good likelihood that the bank then would 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 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 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 state line begins to travel to the 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 saltwater disposal wells up in the Stebbins area, which are already contributing to the revenue of San Mateo too. 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 to Q4 and beyond into 2021 as we get everything turned on at the state line and Stebbins.
Thank you. And our last question comes from Gail Nicholson from Stephens. Your line is now open. Please go ahead.
Hi. Thanks for fitting me in. The Robinson and the Borosols have a higher NRI. Could you remind me on the 2020 activity level, what is the average NRI? And then how do you think that could potentially change in 2021?
Gale, the it's David. You're right. The Rodney Robinson wells have the 87.5%. All the Burroughs wells have 87.5%. Anything on Stateline, so the Vonnie's will have 87 point 5%.
The wells at Rustler Brakes probably tend to run between 75% 80% on the NRIs, and that's probably pretty good elsewhere too. I mean, 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%. And if they're the federal leases, we often have the full 1.8% or 87.5%. And so as you think about next year, I mean, we probably will continue running 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 Rodney's, but we'll also have, I'm sure, 8 or 10 other wells that will have something closer to 75%.
Okay, great. And then just a follow-up on San Mateo. When you look at 3rd party NDCs for 2020, I do believe that that uptick in 2021 for the amount of NDCs for 3rd party. Is that correct? And can you just kind of 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. But to answer your question, yes, we would expect an uptick in the volume in 2021.
Okay, great. Thank you.
Thank you, Jill.
Thank you. Ladies and gentlemen, this concludes the Q and 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 way everybody on the various areas, drilling, production, marketing, land, land administration, ever group 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 challenges 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. So while $20 oil does present a lot of challenges, we also think there'll be some opportunities 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.