Good morning, ladies and gentlemen. Welcome to the second quarter 2021 Matador Resources Company earnings conference call. My name is Tina, and I will be serving as your operator today. At this time, all participant lines are in a listen-only mode. We will facilitate a question and answer session at the end of the company's remarks. As a reminder, this conference is being recorded for replay purposes, and the replay will be available on the company's website through August 31st, 2021, 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, Tina, and good morning, everyone, and thank you for joining us for Matador's second quarter 2021 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 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 the 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 also find a slide presentation in connection with the second quarter 2021 earnings press 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. It's a pleasure to be here today to have this kind of report to pass on to you. Normally, I'd say two or three things in particular to highlight, but there's a lot here. I would think Matador's at an inflection point. It's been an exceptional quarter. Everything came together for us. Great effort by our staff, both here in the office and in the field. I think the results are sustainable, because many involved improvements in the process and wells that will produce for years to come at record low cost. I invite you all to read the prepared remarks. They're a little long to read to you, but I hope that you'll take the time to look those over. We included some slides that are on our website. I'm going to go quickly through those, because that highlights what I'm trying to say, but also to share with you some of these accomplishments. If you'll look at slide A, you'll see that we had record EBITDA and free cash flow. Everything was above expectations. The production was higher, the costs were lower. Each group contributed to these results. Also exciting for me is that we repaid another $100 million on our debt. Our debt's cut in half. We've gone at the last year at the height, we were nearly had a leverage ratio of 3. That's now down to 1.8. I like staying in the ones. The balance sheet has strengthened as we predicted, as we were able to bring the BLM properties online. The quarterly production was better than expected, these BLM wells, many of which are going to produce 1 million to 2 million bbl a piece. We have more zones than we had originally anticipated. Also most important, that is sustainable, we have moved our capital efficiency really forward, so that now, in 2018, we drilled one well that was 2 mi or more. This year, every well we drill will be 2 mi or more except one. We've moved our efficiency from about 2% to 98%. The other thing that we have a MAXCOM room that follows our wells in real time as they're drilling horizontally, they've increased our time in zone from 70% to 100%. You can see what kind of difference that makes in both reserves and production to increase your productive footage by nearly a third. This effort to improve capital efficiency follows all aspects of our business. We try to be good operators who both watch revenue and expense and capital projects and then the per unit cost. Everybody is in an effort to provide the shareholders, make the most use of the shareholders' capital that's been invested with us. We're already exceeding Second quarter 2021 guidance, and that's enabled us to have some operational flexibility to bring some projects forward and really start preparing for 2022. The next slide I have is on slide B, which shows the increasing contributions of our midstream asset. Not only does it have these important financial contributions, but it has operational enhancements to know that we will have our pipe out there when the wells are ready to come online. From the environmental viewpoint, you're not trucking. You don't have the emissions problem. The pipes are ready, and they take away. Then the operational enhancement is that because San Mateo, the pipes were waiting when we were ready to turn on the Rodney Robinson wells and the Boros wells, and they were producing too much volumes for it to be trucked. Plus, your third party may or may not be there, but our production group made it clear that they'd be there with the pipes, and they were, no matter what. The third thing is what I've already touched on, is the borrowings outstanding, you can see that immediately prior to the BLM deal, we had a leverage ratio of 1.8. Then as we did that project, the debt, we borrowed the money, low interest rates, to do the projects on the BLM acreage. It reached a high in the third quarter of 2020, a year ago, at $520 million. We've reduced that now to $240 in outstanding borrowings for the back to the 1.8 ratio. Good planning by the financial group, good cost control by the operating group. Now those wells are delivering record production rates and will exceed the original estimates that we had on what the cumulative production would be. The next thing is we try to establish with you is the credibility that when we set a priority, we achieve it and give you markers, so you can see whether we pass those milestones or not. The 2021 priorities, deliver free cash flow, pay down debt, initiate dividend, continue capital efficiency improvements, the focus on the federal properties, grow San Mateo, have all been achieved and earned the San Mateo performance incentives, as well as the employ a proactive hedging strategy. We did all those priorities. On the milestones, as you can see, we've done the first three. The next Boros wells, we'll get them turned to sales, and we still have the Greater Stebbins area to finish, but it's underway. In the left corner, you see the capital efficiency, what I was talking about, cutting the cost in almost half, and the San Mateo EBITDA growth. The capital efficiency, what I also mentioned that we've improved capital efficiency as measured by the length of your lateral feet drilled in your various wells from 1% in 2018 to 98% today. Going forward, we've tried to provide you with some guidance, and that the outperformance in the first half of the year has allowed us to accelerate the Voni well completions. It sets us up better for 2022, so we get a full year of production from these wells. We feel very excited. As good as we're doing here, we'll do even better next year, and we like our chances. With that, I'd like to turn it back and open the floor for questions. One last, if I have not recognized one of the groups, I'd sure like to make sure I did a universal shout-out because it was really exciting the way that every group, from the field to the office, and within the office, each department, did its part in achieving these results. Tina, first to you for the first question. Thank you. Ladies and gentlemen, due to the time restraints, we ask that you will please limit yourself to one question and one follow-up. Again, we ask that you please limit yourself to one question and a follow-up until all questions have been answered. After which, we would welcome any questions from you. I'm sorry. First question is from Scott Hanold with RBC. Joe, you had indicated that the operational change really sets up for a good 2022. Can you all provide a little bit of color, like what pulling forward these wells. We can kind of see what happens in 2021 based on your guidance, but can you talk through what that might look like in 2022 at a high level? Based on our numbers, it looks like you all should be able to get firmly above 100 a day in 2022 at this point. Good morning, Scott. This is David. I think that we expect to see quite a bit of improvement next year as a result of what we're doing here. When you think about it, as Joe mentioned, not only will we turn these Boros and Stebbins wells on in the fourth quarter, some of which we'll have to shut in, the Boros wells, some of them for a little bit. We'll also have the pull-through from turning these Voni wells to sales now probably in February, as opposed to April or May, as we were originally planning. That, in and of itself, should help us out quite a bit in terms of our expectations for 2022. I don't know that I want to comment on whether we're going to be at 100,000 BOE a day at this point. I think it's a little early. I think we'll want to wait and see how these wells come in, what they do, and if there are any other modifications that we might make between then and now. Look, I think that we're very optimistic about how 2022 is going to look, and I certainly think that the first quarter of 2022 will start off very well for us. Okay. Fair enough. Maybe a little bit on your federal acreage. Obviously, you all have secured a number of permits, and I think you have some extensions that you were looking to get in addition to some sundries. Can you give us an update where we're at there? Yeah, sure. First of all, I think we feel like that things are going very well with the BLM and the office there in Carlsbad, and we certainly thank all of our colleagues there in that office for their help in pushing through the various approvals that we need. I think as we mentioned on the call last time, we have focused more in recent months on getting approvals of the sundries, which are sort of the amendments to the existing permits. A lot of that is because it's allowed us to make some modifications to the drilling or completion designs that we'd originally proposed for those wells. As an example, one that I cite often is the fact that at Stateline, we had permitted all those wells for four strings of casing. Pretty early in the process, our drilling team determined that those wells could be drilled and then completed with just three strings of casing. In order to achieve that, we had to go back and get a sundry or an amendment to the permit. Those have all been granted, we've been really focused, Scott, on getting those just sort of ahead of the spudding of new wells, and that's all gone great. I don't think we've missed a beat there. I think that's all proceeded very well. You are correct. We did have an extension that was pending, I'm pleased to say that we got it. We have received the first extension and feel like that process looks like that it's working well, we'll continue. We've got more in the hopper, we'll continue to pursue that as well. All in all, I think that our team is very pleased with the way things are going. Again, appreciate the help of the BLM. Certainly appreciate the help of our own staff to continue to do what we need to do to make sure we've got the permits that we need. I think we're all gratified that in these first seven months of the year, that really we haven't faced any significant impediments at all to our ability to drill, complete, operate our wells, and things continue to move forward just fine. Great. Thank you. Your next question comes from Neal Dingmann with Truist Securities. Neal, your line is open. Oh, sorry about that, guys. Couldn't help but notice, guys, just the upside we're seeing on San Mateo. You guys have been laying that out now for quite some time, really coming to fruition. I'm just wondering, again, you're talking about $70 million already in EBITDA potential this year. I'm just wondering what type of growth could we see there? Could that go commensurate with what you might see in the upside? I mean, just any details, David, you or Matt or the guys could talk about that. Yeah, Neal, this is Matt. Good morning. Thanks for the question. Where we stand right now, Neal, we've built the bigger components of our midstream business there. We're kind of in the add-on stage, if you will. I think one of the things that we're looking forward to is continuing to service Matador, certainly as the anchor tenant, but also adding these third-party volumes. We've done that, and we've been successful this year in all three pipes. We've added oil, we've added water, and we've added gas. We're to the point where if we get a customer that comes along with enough volumes that we need to add to that system, it's not like we have to have a big investment to go that direction. Say it's water, we can go ahead and drill a saltwater disposal well, an additional saltwater disposal well. If it's just connecting a long pipe, it's a pretty quick build to get that done. I think we'll keep our eyes on that, and if we do end up landing a big fish, certainly something that we would do is, make sure that we have some sort of commitment from that customer that would assure us that we would get our assets paid for. I'd like to, Neal, add to that, is that Matt and his group and Greg and Matt Spicer have done a really good job of attracting quality third-party business to us from companies that are A-rated, the big companies. If you see their client list, there's not one company that dominates it. It's a whole bunch of very long-time operators out there and just a quality list. That takes also a lot of the risk out of the project, and we're happy to expand. I've got to commend them. Nearly all the companies on that list are now repeat customers, have done more than one project with us. That's a good sign of the service, and very pleased with the way that Five Point has worked with us. They've been a good partner, and we feel like we've made a good team. Yeah, Joe, just the only thing. Go ahead. You've known us long enough, and you saw us build our acreage position together in the basin as David says, brick by brick, and we're taking the same approach with San Mateo. What Joe has said, we've gone out, and no deal is too small for us. We want to make sure that the deals we do, we make money on, which we do. We've been able to build this business brick by brick, just like we did the E&P side. No. Very well seen. Just to follow up, maybe a little bit on Scott's, I'm just taking a little bit different approach on. Really like what you guys are doing, moving the operations on the completion, I'm just wondering, maybe Matt, for you or Billy, I'm just wondering more sort of qualitatively, I'm sure that gets you excited from an operations standpoint. I'm just wondering, by moving that and having more of a constant sort of operation, could you just walk us through what gets you more excited about moving the program? I know David touched on this a little bit, would sure love to hear more on just what you think kind of just maybe qualitative improvements and what will this will do, not through this year, but even into next year. Neal, I'm gonna start off, the others will back clean up on this. One of the first things is that on the Boros wells, there was, I think, 800 or more frac stages. They got them all done without any material downtime. All done. On the, I think there was 750, something in that order, 1,500. You had 1,500 frac stages that were done without any material downtime. All the costs aside, we wanted those same guys continuing to work for us so that instead of releasing them so somebody else can get the benefit of their skills and their ability to get many fracs done in a day, we've elected to keep them, which has brought about lower cost, greater efficiency. When you think of 1,500 frac stages done, pulled off right, that says a lot about the crew. We feel like they're the varsity, we don't want to give them up to some less proven people. That was important to me. I'll let Matt or Billy or David say what's important to them. I think, Joe, you've hit on a lot of things. The efficiencies you get doing operations like this are meaningful. You've got a couple frac crews out there. You get these different efficiencies related to having both crews running at the same time. Really what you get is a constant area where you can improve. It's like some type of sports team. You practice for a reason. You practice to get better. If you look back in 2018, our cycle times to complete these wells, to frac them and get them drilled out, get them ready for flowback, was about 45 days. In the first half of this year, we've reduced that down to 24 days, which is a 19-day improvement. There's 19 days that you don't have to pay supervision, you don't have to pay rental, you don't have to pay these other things. On the other side of it, there's 19 days there that you don't have to shut in offset wells. You get the efficiency not only on the cost side but on the production side of things. That's one metric we look at. We just recently did our first simul-frac, and we did really well there. We were well over 2,000 ft of completed lateral length per day. If you compare that back to 2018, that's about 900. You can see we've more than doubled that with our first simul-frac. We anticipate that probably 60% of these wells that we'll drill and complete in the back half of 2021 will be simul-frac wells. We've calculated, and actually with our first experience with the simul-frac, we saved about $250,000 per well. So that's about 6% of the completion cost. Just on the simul-frac. On our 4-well pad, that's $1 million per well that we're saving on that. So there's some real savings, some real efficiencies that we'll see going forward. I don't know, Bill, if you have something to Well, those are all real good. I mean, I'd pile on and mention things we talked about. David was talking about eliminating casing strings, and that improves our cycle time. We get oil faster, also, depending on which string it is, that saves us another half million to a million dollars. That's a good thing, too. Like you mentioned, with a million-dollar saving with the simul-frac, that's a big deal. Even the wells where we're doing the zipper fracs, we're getting better at those, too, and getting more footage per day and improving all the way around there. We also talked about on the production side, we're doing great things there and getting everything on pipe, everything on water and oil on pipe, and that's helping us out there, too, taking trucks off the road, and we all know increasing costs and fuel and things like that. Eliminating all that, just doing better all around. Well, that sounds like we better start taking about $1 million bucks off the well cost going forward, so love to hear that. I think we've got that budgeted over. Neal, I didn't think I was going to have to step in, but maybe. We'll say we've calculated on this completed lateral length per foot, we've calculated that every 300 ft that we get better is about $75,000 per well. Those efficiencies are meaningful. Hats off to Universal and Halliburton, who've been working with us and just doing a really good job and standing behind their work. Great comments. Thanks, y'all. Thanks, Neal. Okay. Our next question is from John Freeman with Raymond James. Good morning, guys. Hey, John. John. I want to follow up just at the end there on what Neal was asking, just to get a better idea of sort of what's built into that second half 2021 sort of cost per foot guidance. Obviously, y'all been just running dramatically ahead of schedule the first half of the year with the average and the $665 a ft and realizing y'all, you took down the guidance that was $730 a ft to $695. I'm just trying to get a sense of sort of the gives and takes of, I know that the Greater Stebbins area typically, those wells are a little more expensive, but then, what Matt mentioned on the simul-fracs and the cost reductions there. Just trying to get a sense, as Neal was kind of alluding to, kind of what's baked into the second half cost per foot numbers. How much of this is just marking the mark what happened in the first half of the year and kind of leaving the second half the same? John, this is Matt. I'll take the first stab at this. I think David probably has some comments, too. Kind of what we've looked at, we anticipated cost increases. We went throughout the first half of the year, and we really didn't see a whole lot of those. The back half of the year, we are seeing some of those, and a lot of it's dependent on crude price relative to what the price of diesel is. On the drilling side, we're seeing cost increases, say, as much as 20% on the pre-drill stuff, building location, moving in rigs. Anything that involves a lot of use of diesel, we're seeing those costs. Probably if you roll everything into it on a drill and completion basis, you may have 4% or 5%, 6% cost increase on the drilling side. On the completion side, you see the same thing. You see, obviously, these frac crews run a lot of diesel, so that cost is up. The cost to transport sand is up. Sand itself, the proppant is up 35% or so, but it's a pretty small portion of the completion cost. We're probably looking at 5% or 6% on the completion side. That's kind of built into that $ 695 number that you've got. We also anticipate that the operations team, they're gonna be able to become more and more efficient as we go along. I think we feel pretty good about that $695 number. John, I might just add to the second part of your question. I do think that the reduction there does reflect a bit of a mark to market or mark to the first half of the year, and that we had done better, and so that sort of enabled us to lower the full year down a little bit. I don't know that we've made a lot of change one way or the other in our expectations for the rest of the year for the reasons that Matt said. The original estimates we had for 10% inflation in the third and fourth quarters of the year are still there, in what we have budgeted to the extent that we can do better than that or mitigate some of these costs. We might do better here in the second half of the year. Those original assumptions are still reflected in our numbers for the rest of the year. That's helpful. I appreciate the context. Then my follow-up question, obviously, historically, y'all have been pretty active on the hedging front, and now that we've got the balance sheet, it's below two times leverage and pretty good line of sight on being able to reduce that a good bit further over the next 12 months. There's been some of the other of your peers have sort of talked about as the balance sheet improved kind of across the industry, some companies maybe being less inclined to hedge as much as they used to. I'm just curious if you all's balance sheet strength, does it continue to improve? If in any way that might impact y'all's hedging strategy going forward, or if you think it'll still be sort of the same as it's been historically? Well, John, this is David again. I think the way we view it is, I think we always feel like we've been fairly opportunistic and tried to make the right calls with regard to hedging. It's unusual for us to go into a year, I can't think of one recently where we haven't had some hedging headed into a year. Sometimes that'll be on the order of 30% or something like that. We may dial that up a little bit during the course of the year if we think it's appropriate. I think you can see reflected in the slide deck that we put out, along with the presentation that we did in the just recently, begin to add to our hedging position for 2022. I think we've got about 10% of our oil hedged, and we added some additional hedges on natural gas through the winter months. Look, we're pretty optimistic on where the commodity is going to be. Certainly, as you know, things are backwardated on the strip, so that always kind of impacts your decision. We monitor it very closely, and I think that as we go forward, it wouldn't surprise me if we added a little more going into the year. I appreciate it. Thanks, guys. Well done. Thanks. Thanks, John. Thanks, John. Our next question is from Gabe Daoud with Cowen. Hey, good morning, everyone. Hey. Hey, guys. Hey, Gabe. Hey, guys. I was hoping we could maybe just go back to San Mateo for one minute. Just curious if this incremental business from third party, just kind of how that impacts volumes this year and next year. I know there's a little bit of a CapEx raise associated with that, but curious if that requires any additional build out beyond what's already been communicated. Yeah, Gabe. The things that we have in hand now are in the budget. That was the increase you saw in the CapEx for San Mateo. Things that are out there that we may get, well, obviously we can't budget for that yet. I think for the volumes that we have locked up right now, that'll be taken care of with the CapEx we have in there. If we're able to have some success, and we hope we do have that success, in the back half of the year, that would probably be incremental to that. We just don't know what that is at this current time. Okay. Thanks, Matt. That's helpful. Just a follow-up, Joe, I guess was just curious if you could give us your latest and greatest thoughts on M&A and just consolidation generally, and if there's anything interesting that you guys may be looking at from an asset package standpoint or even if it's just a corporate transaction. Just any thoughts on the landscape and color there would be helpful. Thanks, guys. Gabe, I'd just say like this, is that we're a public company, and as a public company, we try to play a straight game. If someone makes us a serious offer or inquiry, we try to take it very seriously. In the past, Matador has done a number of transactions public to public. We sold first Matador to a public company, and then this Matador, we did a deal with Chesapeake on part of our Haynesville position that enabled us to go to the Eagle Ford. We established that you could produce oil from the smaller pore throats of the shales. We took profits from that and moved out to the Delaware, which has been good to us. We've also have been active in the private markets. We did a deal with HEYCO, and HEYCO's still our partner, or still part of our fabric. People that work for HEYCO still work for us. George Yates is still a real good friend and a valued shareholder. We're open to that, and particularly, any, what I'd call small, private old, particularly old school oil and gas family company, doing deals with where there's a cultural fit and outlook fit, and we have criteria. We want it to be sure that it's a good deal for the shareholders. As you know that David, Matt, and I, and the other members of our executive team are large shareholders, and we make more money by the shares going up a dollar or two than we do from our salary compensation. That's our primary deal. Is this good for the shareholders? Again, we didn't come up through private equity. We came up through friends and family, and that's primary for us. Is it a good deal for the shareholders and not necessarily just a good deal for the management? In the end, we ask ourselves, we think we're opportunistic here as we are in hedging. In the end, we ask, does this make us not just bigger, but better? That's why we've continued most often with just bolt-on acreage acquisitions that bolt on to our existing position so that we have less risk there because we know that area, and it's small and easy to digest, and doesn't require meshing of systems, computer systems or cultures, or people. We found that to be pretty effective. We're open to deals. Particularly, as I said, with companies we're not as interested or we don't see the appeal of private equity companies. It may create a hangover or a public to public. We're enjoying good growth right now with this existing effort at bolt-ons and dealing with people we know. We're open to it. We want everybody to know we play a straight game. Fortunately, our teams have been able to produce plenty of A-plus locations, and that's what we're going after. That we have a very rich inventory of that, 20+ years, that affords us a lot of choice, and haven't had the need to stretch out for some big deal with some big public. Did that help, Gabe? Yes. No, that's great, Joe. Thanks so much for the color. Thanks, everyone. Okay. Thanks, Joe. All right. Next question. Your next question. Mike is from Michael Scialla with Stifel. Stifel, I'm sorry. Yeah. Good morning, everybody. Hey, Mike. Joe, you walked us through the debt reduction over the past three quarters, and you said you're comfortable in the sub-2x leverage range. I just want to see how you're thinking about further debt reduction from here versus maybe potentially increasing the dividend. I know you just recently implemented the dividend, but is there a debt level or leverage target you want to achieve before you consider ramping that up? Well, Mike, there's always a lot of variables in what you're trying to achieve. We are certainly in favor of further debt reduction. Exactly the pace is dependent on a lot of circumstances, but I think as shareholder will safely see further debt reduction as we go along. We fully expect and hope to increase the dividend over time. Certainly can't say exactly when and where we'll increase it by how much, but it's something that, if prices remain steady or operations results remain steady, all those different factors, we expect another increase in the dividend before too long. We want a reputation for raising the dividend from time to time as operations and results can justify. The first priority is debt reduction, and then, of course, the second one is to keep increasing the dividend. Not sure about the pace, but it's certainly that we'll study going forward at each of our board meetings here on in. I think it comes up every time, and we look at it, and we want to be prudent. Again, I point out how much ME shares that our executive group own, and a dividend increase is important to all of us in the company because our shareholder in the company goes deep. We have 250 or so shareholders in the company now between that and our field staff. You can be sure any thoughts of dividend increase get a lot of hard study here. Very good. Thanks for that. David, you said that it's too early to give guidance on 2022. You're not ready to commit to say production's going to go above 100,000 BOE a day. Is it fair to say with the 11 Voni wells coming on in February, that first quarter production should be up pretty sharply from fourth quarter? Given that, are you still planning to maintain the four rigs next year, or are there any plans that, or any way you'd do anything differently? Well, I'm just going to say one or two sentences, and then David, you take over. I'd just say our plans are always flexible. We think that has to be one of our strengths, that when circumstances change, we'll change. It's not that once we set a course, we're never going to alter it or amend it or tweak it or whatever. We think about that all the time. What knobs can we change to make the value go up more. We're a value proposition rather than, this is the way it is, and we're not going to change. I'm excited about the opportunities and choices we have. David? Yeah, Mike. I think if things go as we would expect, that it's fair to assume that we'll see a nice up quarter in the first quarter of 2022. I think that is a reasonable assumption. Very good. Thank you, guys. Thanks, Mike. Your next question is from Jake Roberts with Tudor, Pickering, Holt & Co. Good morning. Morning. Morning. I'm just curious, looking at the CapEx guide for the remainder of the year, if you could provide some commentary on the non-op side of things and maybe particularly confidence that we won't see that move higher into year-end? Yeah. Good morning. This is David again. Well, again, I think what we tried to do is just update our shareholders on our expectations with regard to non-op activity here at the end of the year. We, as I think we pointed out in the release, have had a couple of our operating partners that have decided to make some modifications to their own programs and have deferred activity from the latter part of 2021 into 2022. I think that we expect that these non-operated wells will get drilled, and I fully expect that Matador will participate in those opportunities. We have already committed to do so, frankly. This is just some minor changes in operations. The fact is, don't think they're going to happen in 2021. Think they're more likely to happen in 2022. It just felt like to us that it was the right thing to do to update our shareholders and the market on that. It's really nothing more than that. Just as we change our plans from time to time, they change theirs, and we don't really control that. I will say that I think that our non-op team does a very good job of having relationships with our partners and staying close to our partners so that we have a good insight into what their plans are going forward. Really that's all that's reflected today. Great. Thank you. Maybe as a second one, just curious on your thoughts on the Haynesville asset in terms of, obviously the gas prices there are significantly improved. I'm just curious in terms of maybe activity or even circling back to the M&A discussion earlier, just your thoughts on Louisiana in general. Well, I'd just say that Haynesville make some great wells, and it's been very good to us. In particular, in our deal with Chesapeake, we were able to reserve the difference between 75% and the existing NRIs. In a number of cases, we're up there with 90% NRIs that make wells all that much more profitable. The other aspect of it that's, say, little known, but I thank you for asking it, is when we did the deal with Chesapeake, we reserved all the up-hole rights, the Cotton Valley, and we probably have some in the neighborhood of 200 billion cubic feet of reserves in the Cotton Valley. We have no plans to drill at this time because gas prices have been, until this year, down, and we've had enough opportunities in the Delaware and the Eagle Ford, and in the Haynesville, that that wasn't necessary. It's HBP waiting to be developed, makes for a very nice gas bank. We'd probably continue to put more emphasis on selling brick by brick our Eagle Ford assets as opposed to our Haynesville assets. Again, serious offer gets serious consideration. Thanks, guys. Appreciate the time. Yeah. Thanks, Jake. Our final question comes from Gail Nicholson with Stephens. Good morning, everybody. Your free cash flow profile is very attractive, and you've had really good progress paying down the revolver. I was just curious on the 2026 Notes, I think they become callable in September. Do you guys have any thoughts about that in regards to retiring those versus potentially pushing out the maturities at a lower interest rate? Hey, Gail, it's David. Well, I don't know that we have any immediate plans to do that, but it certainly is something that I think it's an option. It's something that we have considered and have talked about. We haven't made any immediate plans to do so. I don't think I'd be doing my job if I wasn't bringing up those kind of alternatives or opportunities to the company and to the board for consideration. We haven't made any immediate plans. Okay, great. Just looking at LOE, another nice reduction quarter-over-quarter, can you just talk about the inflationary environment surrounding LOE in the back half of 2022? What workover activity looks like in the back half of 2022 versus the first half of 2021? Yeah, Gail, this is Matt. LOE, this was another very good quarter for us. In regards to going forward as cost increases, a lot of the things that we talked about on the drilling and completion that were affected by the price of fuel, LOE's subject to the same thing. The workover rigs use fuel. Just to deliver the chemicals use fuel. We are seeing some increases on that side. I think the next quarter we've got, production will be down a little bit, so that'll make it a little more difficult. I really like the way the team's approaching things. We got through the winter months and did, what I think, really well, and summer has its own challenges too, but Glenn Stetson and his team, and particularly the guys in the field, they get out in front of things. They don't wait till things happen to start reacting. I think we'll see some good cost control in regards to LOE. I think the second part was the workover pace. Was that right, Gail? Yes, sir. Yeah. Most of the workover work we have comes along with when we're ready to change from one form of artificial lift to another, and that's usually baked into the plan. The other part is when we have rod jobs that need to be done, we'll have a rod part and rig up on that and fix that, or maybe an ESP that goes down and go and fix that. You just have to do some windage there to know you've got, say, 130 rod pump wells, and you're going to have so many failures a year. That's just the way we build that in. As far as any major workovers on the existing horizontal wells, most of our wells are known enough. We're not contemplating any of that activity. Okay, great. Thank you. Thanks, Gail. Thanks, Gail. Thank you, 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 closing remarks. Thank you, Tina. Again, we appreciate everybody listening in, taking the time, and in particular, I'd also give, once again, thank the staff. I think everybody really put in the extra effort, and you can see the results. I would just like to end by saying more formally, we got more questions on the first half of 2021 and the first half of 2022. I believe not only the second half of 2021 will be exciting for us, but also all of 2022 will be exciting as we work to continue to generate additional free cash flow, lower cost, reduce debt, pay dividends to our shareholders, and grow the value of our oil and natural gas and midstream assets. We're pleased with the growth in our capital efficiency and the improvement in our unit cost amounts and the continued building of our inventory of A+ locations. We believe all this creates a stronger value creation for Matador stakeholders in the remainder of this year and then the years to come. As many of you know, I started first Matador back in 1983 with $270,000. It's just hard to believe. I pinch myself when I see we're now approaching $4 billion in value, even though we sold first Matador and started over in 2003. It's been quite a ride, very exciting. We still think our best years are yet to come. With that, I'll sign off. Thanks again, and feel free to come see us or give us a call at any time. Ladies and gentlemen, thank you for your participation today. This concludes the program.