Good morning, ladies and gentlemen, and welcome to the Third Quarter 2020 Matador Resources Company Earnings Conference Call. My name is Sarah, and I'll be serving as the operator for today. [Operator Instructions]. As a reminder, this conference call is being recorded for replay purposes, and the replay will be available on the company's website through November 30, 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, Sarah, and good morning, everyone, and thank you for joining us for Matador's Third 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 are contained in the company's earnings release and its most recent quarterly report on Form 10-Q. Finally, in addition to our earnings release issued yesterday, I would like to remind everyone that you can find a slide presentation in connection with the third quarter 2020 earnings release under the Investor Relations tab of our corporate website. With that, 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, and thank you for participating in today's call. We appreciate your time and interest in Matador very much. Similar to last quarter, we have the 5 slides, as Mac mentioned, and we want you to know that we will stay and answer any questions you have for as long as you all want to talk. I have prepared remarks as part of the earnings release. In the interest of time, to give more time for questions and discussion, I'm going to skip over that and go directly to the slides. The slides are aimed at not just reporting on the quarter, but to give you a feel how well we've done with our goals and metrics for the year. On there, if you look at that slide, in particular, you may remember, at the very first of the year, we said that we had a series of wells to do that we were going to drill the 6 Rodney Robinson wells in January and February and bring them online; and then in April and May that we would have the Ray wells; and then June and July, we'd have the Leatherneck wells; and then in September, we would have both the San Mateo expansion online and operating and drill the first 13 wells in the Boros area at Stateline. We've accomplished all of those projects on time, on budget and in the drilling case, better than budget -- under budget. So that happened, as we said. We also resolved to improve the balance sheet, which we have. We went down from 6 rigs to 3 rigs and took other steps, reducing capital costs, G&A and LOE. And you may remember that Matador was the very first company to take salary cuts. And…

[Operator Instructions]. Our first question comes from the line of Scott Hanold with RBC Capital Markets.

Joe, you all had made a noticeable pivot to look at free cash flow going forward and made a comment through 2021. Can you just give us a sense of how has your mind changed, given everything that's happened over the last year or so on the strategy of Matador? And is that a sustainable change you think is going to occur? And maybe around some of the moving parts around that.

Yes. Thank you, Scott. It's just really a question of what's most important under all the circumstances to create value. And last year at this time or a little earlier, we realized that 1-mile laterals were okay. They were profitable, but they weren't going to be as profitable or as helpful as a 2-mile lateral. So we saw to get the pathway for us was first get to the hurdle where we were capital efficient. That saves money. That makes better wells. That the 2-mile laterals have less declines. They're more profitable. I mean there's just a lot of value getting to be more capital efficient. And to do that, we saw the opportunity in the BLM lease. We paid up for it. We took flak for it. But we've already doubled our -- we doubled our money on it and adding value to our asset base. And we have a lot more wells to drill and a lot more oil and gas to harvest. So that needed to act on that and to get that project going. And at least the first step in that completed put us in an entirely -- going from 1% longer laterals to upper 80s, almost 90%. You can see what a difference that made. Now having done that, and having gone into debt to acquire that, that was temporary debt. We weren't going to do that. Having accomplished that and the expansion of San Mateo, which is a no decline business, that put us in a deal with lower declines on our oil wells and lower declines on our overall cash flow because San Mateo is cash flowing. And now that we have the merger, it will do even better. So that had to be done first. Now that we've done that and…

Yes. And just to confirm, I mean, this is -- so this is a plan. I mean, you talked to your 2021, but this is sort of like a go for plan at this point, right? It's not necessarily just through 2020 plan -- 2021 plan?

No. I mean, I think that, historically, we like having our leverage ratio down there at closer to 2% or below. And it's not that we have a debt problem. It's just under EBITDA because of price. When we went public, oil was at close to $100, and now we're working at $40. But next year or -- I mean, we're going to produce maybe 15 million barrels. I'll use that number that it's easy to multiply. If you have $5 extra price, $45, that would be $75 million. If you were lucky enough to get $50, that would be $15 million by that multiplication. And that gives you a lot of firepower to get the debt down there to two or below, but that's where we'd like to be. But the first step is to think about what builds value, and we thought the really most critical thing would get to where you could achieve this capital efficiency that would build the long-term value. David, would you add to that -- on that?

No. I don't think so. I think, Scott, we do feel like that the plan that we have going forward can be sustainable and one that will generate cash not only next year but in the future as well. So that's -- I think that's the path that we're trying to embark upon.

Okay. Well, I appreciate that clarification. And as my follow-up question. Consolidation, obviously, has hit the energy space. And in particularly, you all are in a position where there a lot of the SMID cap counterparts are going away. Where do you fit into that conversation? And obviously, you're in a unique position where, again, from a SMID cap perspective, there are not many close peers aligned with you. Does it make sense for you to be part of the consolidation going forward?

Scott, at this present time, I don't see much of an advantage. Look, we're achieving what everybody wants to have, which is production is going up, costs are coming down. We're starting to return, thanks to the banks. We have grown from a standing start. You remember when we went public in 2012, we had no production in New Mexico. And now we're probably going to be -- we're currently in the top 10 in both gas and oil. And as this consolidation happens, we'll probably move up to 5 or 6, we're at 7, I think, currently. So we're ahead of WPX and some of these marathon, some of these other much bigger companies. So we think we're playing with them and that our numbers or returns are as strong as anybody. Now having said that, we don't think we need a partner, we also recognize we're a public company, and we play a straight game. So if someone were to make a serious offer, we'd give it a serious consideration. But in the meantime, Scott, is that if you look at the ownership of Matador and the Executive Group, we make far more from our stock going up with our ownership. I'm the largest single shareholder. But Matt and David, the whole group own a multiple of most of their peers and other companies. We make far more from our stock going up than we do from our salary. So our primary interest is getting the price up. So the no premium deals don't have much -- we don't see the appeal. The staff is complete. The others don't have a midstream, which is, again, gives us a big advantage operationally and financially. And that's built out pretty well in our areas. And -- but again, we -- as you've heard us say often, we reserve the right to get smarter. And if some opportunity is presented in front of us that is good for our shareholders, we'll do it. But we're shareholders, too. I mean, that's about it. We have a big ownership. So we're motivated. We just haven't seen the deals -- any deals that would be a good fit culturally or financially or from a property asset base. And we think we have a really good path ahead of us now that we've proved up, Stateline, Rodney, other deals and have the midstream. Does that answer -- Matt, would you add anything to that?

No. I think you said it well, Joe. I think -- from my perspective, I think the notion is just we're continuing to create value. We're not opportunity poor. We're opportunity rich. So we've got a lot of things that we can do. That being said, like you said, if the right deal comes along and it's accretive to what we're doing, we certainly would be willing to look into it and do what's best for the shareholders.

Our next question comes from the line of Gail Nicholson with Stephens.

You guys had a really strong growth, wells that came online. When you look at your -- look at the actual performance of those wells versus your predrill expectations, how do things compare? And then also, specifically, the Lower Wolfcamp B well looks a little bit gassier than your normal Wolfcamp B mix. Can you just talk about what you saw there?

Yes, sure. Hi, Gail, it's David. Well, first of all, I think, clearly, we're very pleased with all the wells that we turned to sales this quarter, in particular, the Boros wells. I think, as we mentioned in the release, they uniformly came out better than we anticipated. We knew they were going to be very good wells. We knew when we bought that two years ago, it was going to be an excellent area. And I think these first wells have certainly borne that out in a big way. With regard specifically to the Wolfcamp B, first of all, I think we're very pleased with the results of both the Wolfcamp B wells. The Upper Wolfcamp B, I believe, had around 37% oil cut, which honestly is quite very close and in line with sort of what our Wolfcamp B wells have been at Rustler rigs. So I think that was certainly in line with expectation. And then even though the Lower B well is a little bit gassier, those wells have extremely high pressure. That well was making 15 barrels a day and -- I mean, 15 million cubic feet of natural gas per day and a whole bunch of oil and the gas itself is very liquids rich. So you're probably talking 1,300, 1,400 BTU gas there. So I think that it's a very strong natural gas well, along with a lot of liquids content. And from the midstream standpoint, it's even more exciting. So I think that -- I think we were very pleased with all the results. You probably got 1,000 foot of Wolfcamp B there at the Stateline. And so we've tested 2 intervals. And I can guarantee you that Ned Frost, who's sitting at my right this morning, probably has got 2 or…

Yes. Along those lines, just to give you a feel, is our completion group had 750 separate fracs. So for 24 hours a day for 2 months, they were out there fracking those wells. And no hitches. Unbelievable, great performance by them. Just think of that, the magnitude of 750 fracs, 24x7 for 2 months. And the same thing to our production group and our guys in the field, Jason and Doug, for coordinating the 3-pipe system getting to the Rodney Robinson because you can produce them if you weren't on pipe that you couldn't get trucks up that road that would have handled it. So coordinating, having all 3 pipes, gas, water and oil, they're, at the same time, getting them online, bringing them on was just a great feat. And that's why I mentioned to -- that our group fully moved up steps, get to the point where they could do a project of this scale, proving that they could, gives us a lot more options to do and number of zones here gives us a lot of options. So we're still in the appraisal phase of both projects. And that's exciting in itself. So thank you for the question.

I think sometimes, us like, sell turnkeys don't really fully appreciate everything that goes into bringing on a massive project like Boros. San Mateo gives you a huge financial benefit. And I feel like sometimes the market does not appreciate the kind of turning of the free cash generation of the San Mateo side as well as the incentive benefits. Can you just kind of talk through '21? And how you see San Mateo like kind of underpinning and helping that free cash flow generation outside of the commodity price environment?

Yes, Gail, this is Matt. Kind of walk you through a little bit of that, and thank you for the question, we're really excited about San Mateo and how it contributes to the free cash flow discussion for Matador in the aggregate. So if we just contemplate that -- and as Joe said, we'll use simple numbers here. If San Mateo throws off $130 million in EBITDA next year, we'll get half of that. So we'll get about $65 million. We anticipate there'll be maybe $5 million that will go towards interest expense. So that gets us down to $60 million. We also think that maintenance CapEx for San Mateo for the year will probably be around $40 million. So we'll be responsible for half of that. So you take $20 million off of that, that gets you down to $40 million. Then you add in the incentives, like you mentioned. We're going to get to $15 million for San Mateo I. We think there's probably going to be $15 million, maybe $20 million for San Mateo II. So you add all that up, you end up with about $70 million, maybe $75 million in free cash flow that San Mateo will throw off in 2021. So -- and that's with the current volume. So if we were able to add additional third-party volumes, it would get even better than that. So we're very excited about the free cash flow story with San Mateo.

And Matt, you're exactly right. It's not fully appreciated how doing these in tandem, drilling the wells, expanding the plant, works for a win-win situation because we've gotten the drilling incentives, both for San Mateo I, San Mateo II, even though it's merged. And you provide the oil, gas and water, the midstream business to San Mateo. So they prosper as well. And I think you're exactly right that it's an underappreciated asset and that, again, will provide value for years to come.

Yes, Gail, if I put on my San Mateo hat, what I'm really looking for is a midstream company as an anchor tenant that's going to do what they say they're going to do, and we've got that with Matador. So when we did the expansion, the only volumes we contemplated in the economics were Matador volumes. So that project works if we don't get any third party. On the Matador side, the wells that we're drilling in the Stateline and up in the Stebbins Area and even at Rustler Breaks are wells that we would drill with or without a drilling incentive. And so as Joe said, it's just a really nice way to work up both business units together.

Our next question comes from the line of Gabe Daoud with Cowen.

Maybe wanted to start a little bit on CapEx and understand there's timing differences between accrual and cash, CapEx, but if I just kind of look at the financials. Through 3Q, it looks like there's maybe about $140 million difference between cash and accrual, if I look at total upstream capital and then 100% of San Mateo CapEx. So I guess, I was just curious if we should expect to see that reverse in 4Q or moving forward?

Well, Gabe, this is David. Look, all I can say is that the -- as you know, the CapEx numbers that we report each quarter are the accrued CapEx. And that's whether that cash has actually gone out the door or not, we're required to report it and we do report it on an accrual basis. And so every operation that's been completed by the end of the quarter is included in that accrued CapEx number. You're very correct that because we consolidate San Mateo that the cash flow always reflects 100% of the San Mateo capital spend, the cash flow statement does. And in this past year, Matador has been responsible for less than 50% of that because of the fact that we still had some portion of the carried interest that we had negotiated. So really in 2019 and 2020, Matador had much less than its ownership. I think if you went back and looked at the total capital spend for the San Mateo II expansion that we probably ended up with paying about 1/3 of the expansion cost, maybe 35%, and we ended up with 51% ownership in the expansion. Of course, if you have, I think, quarters where you've had higher accrued CapEx, that may show up in the next quarter, and then it rolls itself off as you go through. So there's always going to be a little bit of a disconnect between the accrual and the cash flow CapEx as we -- I think the other thing, too, to point out is as we've rolled from 6 rigs to 3 rigs, just the general, both capital spend and cash flow spend that you'll see will go down and continue to stay down as we go forward.

David, that's helpful. And then just as a follow-up, maybe try to get a little more detail on '21. I think I asked this last quarter, too, but I guess just curious if we should still expect a mid-single-digit oil growth number year-over-year at capital that's about $100 million or so less than 2020? And does that program still deliver free cash flow at $40 oil?

Look, I think that we do expect that with the 3 rig program that we'll be able to generate mid-single-digit production growth. Oil, gas, total, I think they'll all be fairly similar for 2021. Obviously, we haven't finalized our plan or put out guidance, but that's the way that it's looking to us. I think that we would expect to see quite a bit less in the way of CapEx for next year. $100 million plus or minus is probably not a bad number. Like, we'll even do a little better than that. But a lot of that, I think, is going to depend on just pricing going forward. The degree of nonop activity that we may have, but I think that's in the ballpark. And yes, we certainly believe that at $40 oil, we have the ability to generate free cash flow next year in aggregate for the company. So that's the way that we're still looking at things, Gabe. And I would presume that your modeling and your estimates probably show the same. So clearly, if we get a little bit better oil price, we'll be able to do a little better even with the cash flow. But I think we're -- we feel very confident in our abilities to generate free cash going forward, even down to levels of $40.

Next question comes from the line of Jeff Grampp with Northland Capital Markets.

I don't know if this question for you, David, or maybe anyone wanted to hop on it here. On the topic of leverage, and Joe, you had mentioned kind of historically 2x, maybe a little bit better than kind of what you guys have operated at, obviously, with prices that's hard to get at. How big of a focus is it to get back to that historical leverage target? It sounded like maybe asset sales weren't super interesting in this type of environment. So how do you guys really look to balance maybe opportunistically looking at selling some assets and accelerating deleveraging versus maybe being more opportunistic on asset sales, maintain a little bit higher leverage than you have historically, but not being forced to sell something when maybe you guys don't want to? Just touch on how you balance that.

Well, Jeff, this is a complex, as you well know, a very complex business, and you got the balance those sciences like flying a plane. I mean, you've got different factors to consider. One is -- the overall thing is, are we creating value? And we believe we are, is that you have now reserves that have grown from 250 million barrels of oil or gas equivalent. That's almost from a standing start when we went public. So you've had growth on there, where that's going to be moderated a little bit. At the same time, you're trying to build for the future. We got a lot of pushback when we went public. We didn't quote to have 20 years of inventory. And we thought we had a reasonable amount but as time goes along, we bolstered that. And so we've got plenty of A-plus locations. And I'd like to note that during this time, we've also built up a plan B in case there's problems with the federal acreage that we have, 26%. So we have hundreds of A-plus locations that are not federal leases. Last year, we drilled 58 wells. So that's plenty of years supply and then the same thing on people. You don't want to get too many people. You don't want to have too few people. And then the addition of the midstream. That was some that most people didn't do. But when we moved out to the Delaware, the infrastructure was old, and we approached somebody about hooking up with some gas who says, "I can, but you won't like it. It's kind of leaky now. You really need to replace the pipe." So we did. And the first project we sold, and we've -- for pretty good sum of money. We've been pretty…

I appreciate that, Joe. Comprehensive answer. For my follow-up on the -- I want to touch on San Mateo and the merger of the two entities there. Are there any financial or kind of operational field level type of benefits of merging those entities? Or is that just kind of streamlined kind of back office, internal processes? Or how should we think about that maybe altering the value proposition or what have you at the end of the year?

Jeff, this is Matt. Good morning, by the way. The merger for us really makes things have more synergy. So if we were to keep those 2 separate, we would have to operate them as separate. We couldn't combine the plants right now. We've got 160 million train, 1.260 and 1.200. So we can move gas from San Mateo I over to San Mateo II, and it just creates a lot of synergies there. Additionally, it allows us to contribute more of the assets to the borrowing base. So there may be some advantages there. But mostly, it just creates a lot of synergy.

Our next question comes from the line of Neal Dingmann with Truist.

Joe, my first question for you or the team is you've talked a lot on San Mateo, and certainly, it seems like it's now past that, if you want to call it a critical inflection point. I'm just wondering now that it's passed this, you all haven't given a detailed guidance yet for next year, but certainly seem to be nicely free cash flowing. By having this benefit or this -- having San Mateo like it is now, does this give you more optionality for the upstream? Or do you all think about -- perhaps maybe asking that another way, would you ask -- would you think about changing any part of the upstream strategy now that you have San Mateo really that backstop, if you will?

That's a good question, Neal. I guess the way we think about it is that the E&P drives what we do, and we don't drill wells to accommodate San Mateo. We drill the best wells, the most profitable wells we can. And if they fall into an area San Mateo, San Mateo will hook up. But we started San Mateo not going into unknown areas, but that pipe always went to places where we were drilling, and we weren't satisfied with the midstream offerings in that area. They're either one enough of them or as I mentioned in the first instance, some is old pipe, old leaky pipe, and we preferred bringing it up to a higher standard and -- in a lot of those areas. And that we also felt that, particularly with the gas processing, you're going to get more of the NGLs, and they have a favorable price today. They had a favorable price back then. And it gave us more options on where to send the gas by these central -- and oil by these central delivery points and interconnects. And so what we try to do is build as many options into Matador's business plan as we can. And you have a lot more options when you have a capital-efficient E&P process and a capital-efficient midstream to work hand-in-hand. We've been accused of drilling wells just to help San Mateo. And I can tell you, nothing has been further from the truth. And to our partner's credit, they've never leaned on us to drill more wells in a certain area that it's done on a capital-efficient basis, where does it make most sense. And as we go forward, it gives us an option. In areas like Antelope Ridge, if we want to build some over there, I'm sure we could, and we know how to operate it. But right now, it's -- we plan to have first line on that cash flow is get the debt down some. So Matt, I'm listening.

Yes, Neal, I was just going to add to what Joe said. The way we've approached the midstream business, if you'll remember, we started it very small. And our first project was a 35 million a day cryo plant down in Loving County. And that's -- like Joe was talking about, that was because we didn't have a great option to process our gas, and so we built a small plant. We planned for an expansion. And obviously, we sold that to EnLink, and then we've built a 60 million a day plant up at the Black River plant. And so both those volumes are relative to the expected volumes for Matador. So when we started at the Black River plant, we thought we had about 30 million a day, and so we built a 60 million a day plant, which gave us some room to add some third-party volumes. And we've just done that at each step. So when we went from 60 million to 260 million, we had about after volumes committed, and we're now at 460 million now. So we're at a point where we can bring third-party volumes on. But before we have to do any additional big capital expenditure, save that another train or to drill another saltwater disposal well, whatever that might be, we'll be able to go get those volumes contracted likely on an MVC commitment where we've got assurance that it will be there and it will be profitable. So we're in a nice spot where we cannot have to build something and hope they come.

Great. Great details. And then, Joe, just one follow-up. Your comments earlier were interesting. You talked about even the benefits of drilling in sort of times like today when prices are relatively weak. And I'm just wondering, for you or David or Matt, I mean, I'm just, again, curious how you think about that given you definitely don't have any obligations. We know that you guys are in a great place on the leases. So I'm just thinking as prices, especially if they fall down again this morning, why -- again, maybe just if you could give more color on this, why not go to 0 rigs and just perhaps complete a few DUCs or do something that until prices improve versus keeping those 3 rigs that you all have talked about?

Well, first, each well we're drilling, we're going to make money from. There isn't anything that I think that we drilled this year that isn't going to pay itself out. And in a number of these cases, pay out in a big way. And the second thing, you -- if you were to stop, then your appraisal program that we're in currently would come to a stop, and you really wouldn't know what you have. And the third, and this may is one of the most important is, if you stop drilling all together, your good drillers, your good technical people, your good geologists aren't going to hang around. They're going to go find somebody who is drilling and go work for them. So if you want to keep your organization together, and we feel we've got a lot of A players here, we want to keep them working, particularly when they're working and making money for us. If we were drilling losing money, but you saw this year, I mean, this quarter, our earnings -- adjusted earnings per share was a profit. And the value added in reserves was tremendous. I think Brad could tell you that we are adding volumes. They're clearly there that as prices recover, and they will recover loss, supply and demand work, that when they recover, the value of Matador is going to go up. If -- 250 million in reserves goes up $1 in value, you have 110 million, 116 million shares, even if you cut that in half, it goes up. The share value will go up $1. So there's a lot of upside to being in Matador. And as prices recover, activity recovers, which means more opportunity for the midstream because they're already there. You don't have to wait for somebody…

Yes, Joe. We've made a tremendous amount of progress, Neal, during these last several months. I mean, we -- initially, at the beginning of the year, we put the plan together to drill these Boros wells and the operations team had actually drilled about 10 days faster per well than we had anticipated, driving those costs down under $800 a foot. And so there's just a ton of these efficiencies that we wouldn't be able to realize if we weren't in the game. We've gone from multiple bottom hole assemblies to drill a lateral to where we've gone over 12,000 foot with a single bit, single motor and single MWD. So there's just a ton of progress. And even with these reduced rates, we're looking at probably $50,000 per day -- per rig day. And so if oil goes back up and the costs go back up to where they once were, you're looking about double that. So we certainly want to be realizing these efficiencies sooner than later. So if prices do go back up that you're not behind the eight ball.

Yes. Last thing, Neal. I just want to emphasize the importance of people that for all the capital and all the technology this business requires, it ultimately is a judgment business and it comes down to people. And we really have a -- feel like a strong group of people that can take us to a much bigger company. David, likes to say, we hit above our weight. But the projects we've done, I think, compare well with any company of any size. And just the fact that we're growing to, say, the #5 producer in New Mexico, it isn't that we've gone out and bought our production from some other company. It's organic and it's controlled, and we could go down to 2 rigs, if we wanted to. And we've considered if prices were down there in the 20s. I mean, it's not like we're married to 3. But for this price, at this time, the 3 is the right number. And we'll just have to trust that the market begins to see the value of the components and the value of going ahead. As Matt says, you don't want to lose the ability to drill these wells faster. That's a big part of the capital savings. So continuing ahead has increased assets and increased cash flow. And there really hadn't been a downside, except the debt may not have gone down as fast as some want, but the EBITDA is going up and a little better price, I think, is likely to happen. And as competition has reduced, prices will go up. David, anything to that? Is that...

No. Yes, I don't think I have anything to add to what you and Matt have said. I think you've covered it well.

Joe, thanks -- I'd just say thanks and congrats. You guys have hit all your sort of time lines out there, and that's one of the few that continues to do that.

Thanks, Neal.

Thanks, Neal.

Our next question comes from the line of John Freeman with Raymond James.

The first question. You had sort of an interesting dynamic where it looks like during the third quarter, you said at least some of the savings were related to some of the nonop activity that fell -- slipped from the third quarter to the fourth quarter. And at the same time, you mentioned the additional $10 million in CapEx that you'll expect to incur in the fourth quarter as some of that nonop activity that was supposed to happen early '21 gets moved forward to 4Q. And I guess, I'm curious, just given the weakness we've seen in oil prices here in the last couple of weeks, if there's -- I guess, how strong a conviction there is that nonop number is going to be there like if -- is that stuff that was supposed to be incurring late in 4Q, which is still maybe up in air given with commodity price? Just any color on how we should think about that potentially that moving to the right, the nonop is what I'm focused on.

Yes. John, it's David. Well, I think that there's a pretty good chunk of it that's already spoken for in the fourth quarter. Some of it related to the fact that some of our partners have decided to go ahead and frac wells toward the end of the year that they had originally indicated they might postpone into the first quarter of 2021 or beyond. I would venture to say that probably reflects the fact that as we've been talking, that's a good time to frac wells. Costs have been low. And so I think that they may have chosen to accelerate some of those completions into the fourth quarter. Some of the wells that we've -- that are going to take up portions of those costs are just wells where maybe partners have decided to start the drilling of the wells before the end of the year, but still don't expect them to come on until the fourth quarter. So there may be a little of it that might get further delayed, but I think it's reasonable to expect that most of that is going to be incurred as we've indicated.

Okay. And then just as a follow-up question. You all did a good job of updating us on where you all stand on the federal drilling permits, which you've done a remarkable job getting as many of those approved and received. And obviously, you all expect to have almost another 100 approved or received before year-end. And I guess, I'm trying to get a sense of like how much we should think of just the nature of these permits where basically, they're good for two years, and you have to get them renewed for another two years, how much of the federal permits that you all have approved and received is going to drive a lot of the drilling activity for you all in the next two years? I mean, you all are fortunate that obviously, it lines up a lot with where some of your very best acreage is. So it's probably where a lot of the drilling activity would have been skewed to anyway. But just -- if you can just sort of speak to kind of how much we need to focus on kind of these federal permits? And how much that's going to drive that activity here in the next few years?

Well, I think, John, the plants that we have had -- have and have had hard to run a couple of the rigs at the Stateline, and the other rig will run in the Stebbins Area, in Rustler Breaks and in Rodney Robinson. All the wells at the Stateline require federal permits, of which we have received, I think, the table in the earnings release says that we received all but 1 on the Boros and Voni wells. And I was told this morning that we actually got it this morning. So we've actually received all the permits. We have them all in hand for every well that we would be looking to drill over the next several years in the Stateline asset area. We also have many of those already in hand that we'd be looking to drill in Rodney Robinson. I think Rodney Robinson, there's only 3 or 4 that are still left outstanding at this point. Many are in hand up in the Stebbins Area. Occasionally, we'll need 1 in the Rustler Breaks area. And I think -- so over the next couple of years, I think we're certainly -- look, we've got more permits than we'll probably drill in the next couple of years. But over the next couple of years, we're -- these things are pretty much already in hand for anything that we currently have on the schedule. So I think we feel very good about that.

Our next question comes from the line of Noel Parks with Coker & Palmer.

I just had a couple of questions. I want to talk about service cost. You touched on them a good bit. But last quarter, I remember you saying that you had pretty much locked in a lot of your completion costs for the rest of the year. And as you look into next year, and I guess, maybe even further heading towards 2022. Just curious what your assumptions are for what costs -- for what you expect the vendor component to be of service costs?

Sure, Noel. This is Matt. We continue to see favorable service costs pricing, particularly throughout the rest of this year. We're looking into the first quarter or so in the next year and are seeing comparable prices. I do think that our expectation is as long as this rig count is somewhere where it is, somewhere between probably 250 and 350, we think that there's probably a lot of consistency in the service cost. That being said, we tend to treat our vendors a little differently. We do like low prices. But what we're really looking for is the vendor that's going to help us create value. So we don't always take the cheapest bid. What we're looking for is someone who's going to come in and help us be more efficient because the more efficient they become, the more efficient we become. And so I think that, that stays consistent with us and being able to go visit with our vendors about pricing. In the past, we've been able to just have a conversation with our vendors. Even when prices go up, our vendors have come to us and it's not quite to market, so we would agree to pay for fuel or something like that. Other times, we go to them and say, we're getting bids for cheaper work and then we'll need to reduce it. So there's lots of back and forth that goes with this. And the other thing that we want is a vendor that's going to stand behind their work. We want someone who's going to be there and be willing to take responsibility and work with us just back and forth. So I think our approach, like I say, is a little bit different than there may be some companies.

Great. And one other item that you talked about last quarter, I think, was at Leatherneck and in the release, you did indicate that the costs were better than expected and the press results were better than expected. I do recall that you were -- I think doing your first Wolfcamp B test there. I just wondered if you had any sense of how that was performing.

Yes. Noel, it's David. Look, I think that -- I think we're satisfied with the way the well has performed. I would say that it's still early, and we're still looking at it. But look, I think we're pleased with the results of that well. And I think it's interesting as a Wolfcamp B in that -- it probably has a little bit higher oil cut than some of the Wolfcamp Bs that we've seen, but no worries.

Great. And I just had one housekeeping question. I could not notice in the hedges that on the gas side for first quarter 2022, you had collar with a $2.60 floor and $4.22 ceiling, which given the strip seemed like a really sort of wide margin you had there. So I was just curious if you could talk anything about that. And I was just wondering if there were net costs at settlement with those or something?

No. That was just simply an opportunity that we had to add to our hedging position. I believe, if I'm correct that we have the opportunity to add some hedges, like from the early -- after the first quarter of 2021 on -- into the first quarter of 2022, and it just -- that was a hedge that we put on throughout that period. It just improved the kind of weighted average price for the 3 quarters in 2021. And then we just have that little sliver that is currently sticking out there in 2022. Actually, we thought it was quite a good hedge. We were -- we've been working pretty hard to make sure that we locked in at least a $2.50 floor, if we could, across these hedges, and that was a case where they just got a lot of upside to go along with it. So we could have looked for a narrower margin, but that was just a case where we like to -- we like the hedge, and it helped us to continue to kind of fill out some of the hedging we wanted to do for Q2 through Q4 and also to get a little bit better price by adding on Q1 of 2022. So it's really nothing more than that.

Our next question comes from the line of Michael Scialla with Stifel.

I just want to ask on your capital efficiency, Slide C. A lot of competitors have been showing similar slides. I think your savings have been probably more significant than most, it looks like more than 40% on a per foot basis over the last two years. Is that $790 per foot number, a good number to baseline for next year? And curious, too, if that number is a fair comparison to the $1,500 per foot number or even higher slightly for 2018? Have you changed anything in the design of the wells other than, obviously, the lateral lengths longer, but anything else that has changed over the last two years in the design of the wells?

Mike, this is Matt. I'll take the last part of that question first. We've been able to, in some instances, on some of the wells, eliminate an intermediate casing string. So those costs are built in there, too. But on the whole, I think it's pretty comparative, the $1,500 in two years ago to $1,200 last year, and the goal this year was for $900, and we've driven that down below $800. So I'm not going to bet against the guys to -- that they're going to have a reversal and go back to even to the $900 number. So I think that somewhere probably between the $790 we talked about and $850 probably is a good number.

I think we're certainly very -- we're very pleased, Mike, and I think everybody here is over the course of the last couple of years, as we've moved to these longer laterals, I think that the teams have executed on them very well. We have our MAXCOM room that, I think, has been where we have 24/7 monitoring of every well that we're drilling. I think that we've got geologists and engineers watching every well being drilled every day. I think that's -- we've just seen continuous improvement in terms of the execution on the drilling side and particularly in terms of staying right in the zones that we want to be in throughout the entirety of the laterals, whether they've been 1 mile, 2 and now approaching 2.5 mile laterals at Voni. So there's a lot positive there along the way over the last few years. They've eclipsed our own internal records almost 100 times for improved drilling efficiency, which I think is quite a great achievement. And -- so as a result, I think there's a lot of operational efficiency that's come into that. As Matt mentioned earlier, using 1 bottom hole assembly to drill over 2 miles, that's pretty amazing. And so I think there's just a lot of ways in which things have improved. I'm also very pleased about the fact that we -- these costs have not come on the backs of trying to reduce the quality or the quantity of our stimulation jobs either. So we've continued, I think, to advance the -- and improve on the completion side. We're not pumping less sand. We're not pumping less fluid. I mean, we're pumping at a higher injection rate, which usually requires a little more horsepower to do. And so there's a lot of improvements, I think, that we've made. We certainly haven't skimped or saved. It's always easy to cut costs by just cutting the quality of the work that you're doing, but we haven't done that at all. And I can assure you that the way that we are calculating and reporting those numbers has not changed a bit. So that's all very consistent across the last 3 years.

That's good to hear. Joe, you mentioned now is not really the time to be considering -- the market is not there to be considering selling down your interest or selling -- flat out selling some of your assets. But I want to see if you could maybe talk a little bit about your Haynesville. Is there much there left to be developed? I realize the operator's in Chapter 11 now. But how do you see the -- maybe the returns in that play, competing with, say, the Permian? And then anything you can say on your mineral interest to sort of frame up the potential size of a package once that market returns to where that could be sold?

Yes, thanks for your question, Michael. We've actually sold a few properties in the Haynesville here and there. Not the major properties, but we have done some. As again, when we get a serious offer, we give it serious consideration. The one of the angles of the Haynesville is when we made the deal with Chesapeake. We reserved all of the Cotton Valley rights. So there's probably 200 billion or more in gas in the Cotton Valley behind pipe that we could access if and when we want it to. So it's a nice gas bank to have. It didn't cost us anything. It's held by production. And then on the Haynesville itself that -- I'll give Chesapeake some credit. They've done a good job drilling those wells and cost. And last year, they drilled a couple of wells that had very high rates, and we were glad we kept it. And they came in producing 40 million a day, and we had 49%. So that worked out well for us. It's a different gas market up there, which blends with what we have coming out of the Permian. And we think that's advantageous. And if gas prices become the order of the day is a good return, that would be a good area for us to expand our footprint. And we had some decent offers, but none that want to make us give up that gas bank that we have there in the Cotton Valley. And we have drilled the Cotton Valley, and we had good results. And you can certainly launch a drilling program there if gas prices get up and then if they're sustainable at a higher price. And in the Eagle Ford, we've sold off a number of properties, different people down there, and it's been on kind of a track by track basis. So we're open to that. We're just not in a hurry and don't want to do a broad sell where you just package them all up and sell them at a discount to somebody because they're cash flowing well to us and it's a higher oil price and it's a higher gas price down there on the coast. So there are reasons to keep them. But we play a straight game. I sold first Matador, and we sold some of our interest in the Haynesville to Chesapeake. And we've sold interest from time to time. We sold our gas -- first gas plant to EnLink. So we'll do it when the prices arrive, but we just try to avoid the fire sales and let them cash flow. And that strategy has worked out pretty well for us, not to just rush into one thing or another. And -- so I hope that answers your question. If not, I've got a whole row full of people eager to respond, Mike.

Ladies and gentlemen, this ends the Q&A portion of this morning's conference call. I'd like to turn the call over to management for any closing remarks.

This is Joe, again. I just want to thank all of you for participating. We really appreciate it. And I thought there were some very good questions. And if you want to follow-up or have further visits, we are available. And we're proud of the quarter we have. And as good as it was, we think it will be better next quarter. And thanks for coming together for us that we're going to emerge from this COVID and low-priced deals stronger than what we went -- than we were when we went into it. That -- this is a great business. We think it has plenty of room to grow. And we appreciate the support that we've received, but want you to know we're available, and we like these discussions. So thank you, and come see us.

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