Good morning, ladies and gentlemen. Welcome to the first quarter 2023 Matador Resources Company earnings conference call. My name is Didi. I'll be serving as the operator for today. At this time, all participants are in a listen-only mode. We will facilitate a question and answer session at the end of the company's remarks. As a reminder, this conference is being recorded for replay purposes. The replay will be available on the company's website for one year, as discussed in the company's earnings press release issued yesterday. I will now turn the call over to Mr. Mac Schmitz, Vice President, Investor Relations for Matador. Mr. Schmitz, you may proceed. Thank you, Didi. Good morning, everyone, and thank you for joining us for Matador's first quarter 2023 earnings conference call. Some of the presenters this morning 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 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 annual report on Form 10-K and any subsequent quarterly reports on Form 10-Q. In addition to the earnings press release issued yesterday, I would like to remind everyone that you can find a slide presentation in connection with the first quarter of 2023 earnings release under the Investor Relations tab on our website. With that, I would now like to turn the call over to Mr. Joe Foran, our Founder, Chairman, and CEO. Joe? Thank you very much, Mack. It's a pleasure to be here this morning, and thank you all for taking time to listen in. What I wanted to be sure to emphasize, that this year is off to a very strong start, and both from organic growth position and also for the acquisition of Advance, which has been off to another really good start, and the integration has gone smoother. The handoff has been very professional from Ameredev and EnCap, and we're working hard on those assets so that what we can offer to you is Matador, in the first quarter has added to its strategic assets. It has developed a number of locations to drill as well as to finish certain DUCs, 21 DUCs that Ameredev was on. The midstream strength that we have has made, has increased its volume and has delivered on-time performance, so that a theme you will hear from as we answer the questions is that we've saved money, not just from working with our long-term vendors, but also from cutting the days on the well for drilling, for completion, for getting production there that have all making a difference. It isn't just about cutting specific costs, but it's also the efficiency part of your capital efficiency and people efficiency comes from getting down the days on the well and delivering more product in less time. With that, I'd like to open the floor for questions. Mack, whoever's first. Thanks, Didi. You can open it up to questions. Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Ladies and gentlemen, due to time constraints, we ask that you please limit yourself to one question and one follow-up. Again, we ask that you please limit yourself to one question and a follow-up until all have had a chance to ask a question, after which we would welcome additional questions from you. one moment for our first question. Our first question is from John Freeman of Raymond James. Your line is open. Good morning, guys. Morning, John. Yeah. The first question, Joe, it was kind of on what you just touched on there at the end on just sort of the progress y'all keep making on the efficiency gains, drilling completion costs just keep coming down. I guess, you know, I know y'all reiterated that the full-year D&C guidance of the $1,125 a foot. Could you perhaps give me what that was in the first quarter, the D&C per foot? Hi, John, this is Chris Calvert, EVP and Co-Chief Operating Officer. Yeah, so the 1,124 that you mentioned, you know, that was our full-year guide, and that was with a 10%-20% increase from service cost inflation. That we really started working on in December of last year. We did not put anything out publicly, but our D&C cost per foot for this quarter definitely came in below that. They came in around $1,014 per foot. We were proud of where we were, and those efficiencies were through reductions in drill times, simul frac, remote simul frac. We had kind of, in 2022, we had basically used simul frac on about 45% of our wells. We put a target to use over half of our wells in 2023 to be simul frac, and in the first quarter, we beat that. A lot of this efficiencies come from, you know, reduction on the drilling times, increased use of simul-frac, increased use of dual fuel. So we're definitely extremely excited and proud of the work that we did on the capital efficiency side in reducing those D&C costs per foot. One thing I would like to mention, you know, on the service cost side, we really haven't seen, other than small cost components such as diesel fuel that you and I have spoke about in previous conversations, we really haven't seen costs come down all that much from the vendor side. You know, we have a couple of our heavy cost components on both drilling and completion that were actually up quarter-over-quarter from the fourth quarter of 2022 till today, or till the first quarter of 2023. A lot of those savings, really mostly all of those savings, have been through efficiencies, and that's reduced drill times, you know, going back, reusing existing pads on the production and facility side, increased use of dual fuel, better partnerships with third-party operators, and specifically San Mateo when it comes to water usage and, you know, getting better rates on our water for stimulations. That's, you know, we lean on our partnership with San Mateo for that. It really has been a push from the operations group to mitigate those service cost inflations that we've seen. You know, like we say, it's really one quarter's worth of work, while we're proud of where we are, you know, we still have a lot to do in this year. You know, the 1,124 that we put forward in the capital guidance plan, you know, that was put forward in December, and we're still happy with where that number is, but we're extremely proud of where we came in in the first quarter. Thanks, Chris. I appreciate all the detail. Just my follow-up question, these the testing of these horseshoe wells, maybe just any sort of background on kind of what led to that decision, the optimism to try and test those. Does anybody on the operations team have prior experience with the horseshoe wells? I know there's been a few that have been done over the years in the industry. Just any background and kind of what led to that decision. Hi, John, this is Glenn Stetson, EVP of Production. I'll start out with, you know, the kind of the why, and then I'll let Chris talk about some of the operational efficiencies. You know, this piece of acreage was unique in that the Upper Wolf Camp, the Wolf Camp A-XY, was undeveloped in our section, but that had been developed on, you know, on every other side of this piece of acreage. The illustration, I think, shows it very nicely that we put in the slide deck. Ultimately what we're doing here is, instead of drilling four one-mile Wolf Camp A-XYs, we've actually drilled, and seeded and cased these wells already. What we did was drill one horseshoe wells instead. It was, you know, it was a unique opportunity. Our technical team did a whole lot of work on the front end to ensure that the drilling would go smoothly as it did. The next, you know, the next piece of this is to go in and get these wells completed and then put them on production. Yeah. Hi, John. This is Chris again. You know, I think from the genesis of this project, it really starts with the team, you know, and the teamwork that was illustrated with bringing this project to fruition. Travis Wolf, the team lead of our West Texas asset, former MAXCOM graduate, you know, is now running the asset there. The teamwork between the teams, the land group, the permitting side to get this well on the schedule and permitted properly. Then from the technical side, you know, the curve on these U-turns are, I think, if you're looking at a piece of paper, it looks somewhat dramatic, you know. Actually the curve from a technical perspective of in the curve, it's actually less of a build when we made that turn to come back towards the heel of the well, less of a turn than actually the curve when we go from a vertical portion into the horizontal. You know, I think from a technical standpoint, we were very confident in our team, confident in the drilling group led by obviously Billy, Josh Passauer. Our MAXCOM team plays an integral part in projects like this of keeping us in zone and allowing us to drill, you know, as fast as we have proven that we can. Obviously we recognize and realize there is a time savings component to this of if you drill four single-mile wells versus two U-turns, we've calculated it's about a 50% reduction. Not only is there a cost savings associated with that, but you're bringing offset wells that you've shut in, you're bringing these wells to production faster. There's a time savings component to that, a cost savings. We've documented it's about $10 million in estimated savings that we're going to realize. When you think about the amount of steel that's needed to case a four string well, if you're doing four single-mile laterals versus two U-turn horseshoes, we're actually saving about 10 miles of casing, basically by reducing two vertical portions of these wells. A lot of work was done on the team side, not just from the reservoir group, the land group, permitting production. It really has been a team effort that is truly indicative of a lot of these operational projects that we take on. You know, whether it's simul-frac, remote-frac, dual fuel usage, U-turn wells If you come to anything like any meetings that we have, it is truly a team effort from land to legal to reservoir. We're extremely proud of these two projects or these two wells. There is still work to do, and we're expecting to turn these online, you know, on the latter half of this year. That's great. Thanks, guys, and congratulations on a nice quarter. Thank you. Thank you. One moment for our next question. Our next question comes from Gabe Daoud from Cowen. Your line is open. Thanks. Hey, everybody. Good morning. Guys, maybe I was hoping we could start with the Advance properties. One-two production came in a little bit better than what you were anticipating, and you noted the 21 wells being completed currently and then another 21 in early 2024. I guess, I was just kind of curious, what does the cadence look like from here? Like, when do those 21 wells being completed come on? Is that 3Q or 4Q? Then, you know, you mentioned in the release how Advance makes 2024 even better. Could you maybe just provide a little bit of context on what even better kind of means? Hey, Gabe, this is Brian Willey, Chief Financial Officer and President of Midstream. Happy to answer your question, and thanks for joining the call today. We are really excited about the Advance assets. You know, very strategic, great assets, perfect fit into our existing assets. You know, we're thrilled about them, and they have produced better, I think, in the first quarter than we expected. As a reminder, we don't get credit for that production yet because we didn't own the assets. We are excited and encouraged by the fact that they produced better than we thought. You know, we've had, I guess, keys to the car now for a couple of weeks, and it's still early on, as we drive the car here, but we are excited about it. I think, in fact, I can turn to Chris in a minute, but I think our completions group started yesterday. We switched out their completions group to ours, and we're starting to complete the wells. The 21 wells that you mentioned, we do expect kind of second half of the year, those will come on, kind of in that third to fourth quarter, as you said. You know, as we look to next year, you know, we have 49 total wells that are gonna be in progress at the end of the year. 21 of those are gonna be the wells that we're currently drilling, on the Advance acreage and will be completing later this year. We expect those to come on early next year. you know, at the end of the year, we're gonna end up with 143,000 or so, on a run rate. you know, that's a great run rate as we kinda go into next year. those 49 wells in progress will just add to that, including the 21 wells that are there at Advance. So, you know, we're really excited about 2024. If you look at just comparing 2022, the fourth quarter, to 2023, the fourth quarter, on a true just BO basis, so an oil-only basis, that's a 40% growth is what we expect. you know, that sets us up really well for a great 2024, both on a BO basis, on an oil basis, and then just also on a, on a total BOE basis. We're really excited about 2024 and what that looks like. It's early in the game. I mean, we just finished the first quarter, you know, a lot of golf to play before we hit 2024. We're really excited about the opportunity set ahead for us. Thanks. That's helpful. I guess then just given the elevated maybe wells in progress exiting this year versus historical norms and an eight-rig program, which is also, I guess a high rig program for Matador, just based on historicals, obviously a larger company now. How should I think about, like, the exit-to-exit growth in 2024 relative to 2023, just given all those moving pieces? Yeah. I think the exit growth, you know, we mentioned the exit growth in 2023. If you take that 143,000 BOE per day and you just held it flat, you know, it's about a 15% growth over what 2023 would be if you held it flat into 2024. You know, we obviously hope we can do better than that than holding it flat, as you mentioned, the eight-rig program. It's pretty early for us, I think, to talk about an exit rate in 2024. You know, that's, I guess almost two years away. We are, we're certainly excited about 2024 and what we can do there, you know, getting this 8-rig on and being able to have those opportunities and the Advance acreage especially. You know, it's some of... We talk about A-plus locations. It's some of the best acreage we'll have and, you know, compete very well with the other acreage we have in the drilling locations. I don't know, Tom, did you wanna talk any more about the acreage itself? Hey, Gabe, it's Tom Elsener, our EVP of Reservoir Engineering. You know, as we've shown over the last several months, we're clearly very excited for all these wells that will be drilled and completed on the Advance properties. The bulk of it there is in southern Ranger, northern Antelope Ridge, where we've drilled wells nearby, like the Mallon wells that have each produced a million barrels of oil each. Nearby some of our other Nina Cortell wells in the northern end of Antelope Ridge. A little further south, where the Rodney Robinson wells are. This is an area that's characterized by having very high oil cuts, you know, typically, 75% oil cut, and also very low water cuts. you know, typically two to two barrels of water per one barrel of oil and sometimes even closer to one to one. you know, obviously we've talked about the ability with Pronto to be able to be nearby, and we look forward to, you know, expanding that relationship to be able to see some of the similar benefits that we've seen across, you know, other portions of our acreage, like State Line or Rustler Breaks or... I think what we're seeing is, you know, as we've said, you know, we spread the ball around quite a bit this year, and all of our different asset teams are contributing. you know, and so we're very excited to bring these properties on. There's, you know, with 150,000 net acres, all of our different teams are trying to get activity in their area. In the second quarter this year, we're gonna have 11 wells in Ranger and four wells in Rustler Breaks, another four wells in Antelope Ridge, and eight wells at State Line, where, you know, as we've talked about some of the outperformance at State Line due to, you know, having great flow assurance with San Mateo and with our facilities team. We're looking for all these types of benefits to start to see on the Advance properties. Thanks, Tom. That's helpful color. Thanks, Brian. Good quarter, guys. Thank you. Yeah. Thank you. Thank you. One moment for our next question. Our next question comes from Neal Dingmann of Truist Securities. Your line is now open. Morning, all, and nice update as always. Joe, my first question is for you. Really what I'm wondering, Joe, is how you currently, if it's changed at all, how you currently view production growth versus shareholder return. Again, why I ask this is, you know, though I definitely appreciate the solid continued growth, I believe you've said in the past, you know, your wife always appreciates a nice dividend occasionally. I'm just wondering how you view things. Well, Neal, thanks for the question, but we're for both of them. We're for both dividend and shareholder returns as we are for growth in value. I wouldn't say just plain growth. We've never been growth for growth's sake. We've always been profitable growth at a measured pace. As part of that is we, you know, again, want to have the profitable growth, but we're not growing for growth's sake. The same thing on our dividend. We're gonna grow our dividend in a manner that once we raise our dividend, we don't wanna be in a position where we ever have to walk it back. We began, you know, with a $0.10 dividend, went to $0.20, went to $0.40, and we've continued to grow it now at $0.60. I think if prices stay anywhere at this level, that our shareholders can look for a return sometime over the next year, but we wanna be prudent about it. We wanna be one of those companies that steadily increases its dividend while steadily increasing the value of its shares. You're exactly right, all Matador, all the people in this room are heavy shareholders. Most of our net worth is tied up in dividends, so we like dividends. We think it's the fairest way to reward your shareholders, particularly your long-term shareholders. There's plenty of support, and we think we're proceeding at a prudent pace. You look at our board, they're heavy shareholders. They own hundreds of thousands of dollars just to get on the board. you know, we believe that makes a difference, too, to have that heavy ownership. so far, so good. That seems to be the right balance, growing the value of the stock while growing the amount of the dividend, and we wanna keep those in balance. I hope that. it's discussed all the time, and we just don't wanna announce a dividend increase, but then have to walk it back. Shareholders seem to be real happy with that I've talked to. Remember, we didn't come up through private equity, but friends and family. One thing, if you have any family members in as shareholders, you're gonna get some feedback, at every family gathering, and the same thing with your friends. Everybody, and the longtime shareholders seem to be pleased and our institutions, and we'll continue to keep an open ear to them. If they have concerns or preference, we're always willing to listen. No, that's crystal clear, Joe. Just maybe my second question, a little bit been asked, let me ask it a different way, just on Advance, maybe for Chris or Michael or Glenn, one of the guys, on Advance and its impact on the remaining 22 production. I noticed, I think it was on one of your earlier decks on slide 33, you talked about on your prior deck where you all mentioned a minimal impact from the 21 new Advance wells in third quarter due to these wells coming on late in the quarter. It looks like the step up, but you definitely have a nice step up in third quarter, but even another significant step up in 4Q. I'm just wondering, maybe it's too early, as Glenn was saying, but I'm just wondering, based on what you're seeing so far, is that still the case, of that late 3Q, maybe 4Q, or is there maybe even, increased expectations now because of what you've already seen? Hey, Neal, it is Glenn Stetson, EVP of Production. Yeah, thanks for the question. You know, Brian mentioned it, we've been at the helm, so to speak, or in the driver's seat for a couple weeks. Give us a little time, and I think we'll have a nice update for you in July. we're encouraged so far, both by the existing production and how those wells were doing the day we took over, and that all went really smoothly. You know, speaking to the operations guys, I just wanna, you know, give a little tip of the hat to them. We had their drilling rig in... you know, integrated into our MAXCOM room from day one. The completion guys, well, Brian already mentioned this, but we started fracturing operations on these Margarita wells yesterday evening, and that was with simul-frac and utilizing dual fuel as well. Then, you know, I think that the same efficiencies that we saw from completing wells in the first quarter, example being Rodney Robinson, is that we hope to, you know, complete these wells kind of faster than anticipated. Hopefully, you know, if everything goes smoothly, you know, that it will, you know, contribute to Q3 in a meaningful way. No, that makes sense, Glenn. Thank you, and I won't bump up the estimate too quickly. Thank you. One moment for our next question. Our next question comes from Scott Hanold of RBC Capital Markets. Your line is now open. Hey, guys. Good morning. Tom, you had mentioned a little bit earlier about the advantage of the midstream and how that's helped some of the well performance. You know, 1Q23 did have pretty strong performance. Can you give a little more color on the advantage that midstream has provided you? As you guys connect all the systems, I think that's gonna be, what, by early next year. You know, how does that provide you better flexibility in stronger flow assurance and performance? Sure, Scott. Yeah, thanks for the question. This is Tom Elsener, EVP of Reservoir Engineering. I'll start, and then I'll pass it over to Brian Willey. You know, I think that the team kind of all around, you know, when we were designing the State Line development, I think they looked at it as a unique opportunity to design all of the infrastructure kind of from the ground up. You know, and Glenn Stetson has a lot to, you know, a lot of credit to that as well. Some of the things that they've done down at State Line are create this kind of unique, kind of low pressure, medium pressure, and high pressure system, whereby the different 54 producing wells at State Line can be fit to the right pressure system where they produce their oil, gas, and water into. This allows us to custom flow these wells into the right system so we can kind of always optimize the production. This has been something that has been a great benefit to State Line and, you know, keeping those wells flowing without kind of constantly having to shift around the artificial lift type has benefited State Line in a big way. Certainly, you know, none of this could happen without San Mateo keeping their plant running. State Line's been producing now for several years, and I can't remember a single day of downtime at State Line. I think, you know, Gregg Krug and Brian Willey and everybody at San Mateo have been able to keep that plant running back in Rustler Breaks throughout all these different storms, throughout all these different events. Having 54 wells coming online is, that's a lot of production. I think they've done a wonderful job with that, and I'll hand it over to Brian. Yeah. Thanks, Tom. I'd just say, you know, we're excited about that in State Line and the synergies there. That's true across the basin too. If you look at San Mateo's other operating areas, if you look at Rustler Breaks, we're in the process right now of drilling another saltwater disposal well. Going up to Stebbins, we're building out right now to some of Matador's other wells that they're gonna drill there. That build-out and that, you know, partnership is great, where we're able to go down and just talk to the San Mateo guys, and the San Mateo guys can be in the actual meetings where we're planning the wells on the Stebbins side. You know, kind of hand in hand, being able to support Matador and ensure that there's a lot of flow assurance there. I think even looking over to Pronto, it's the same thing, same story. You know, late this year, kinda early next year, we expect to connect the Advance wells over to Pronto and then also connect to San Mateo, where San Mateo can flow to Pronto can flow to San Mateo, and that'll kinda complete that gas system all across the northern part of the basin. You know, the synergies that Tom talked about over at State Line, you know, it's great, and we continue to just implement that across the basin. So we're really excited about the value of the midstream assets. Well, one other point, Brian, is to emphasize is the third growth in the third party, going into these pipelines. The importance of that is that what makes us feel good is that we're getting repeat business so that those companies know they're still getting better service, from us as they would anybody else. There isn't a preference for ours over theirs, that we do both. We've tried to be very, very clear that they're gonna get every bit as good a service as anything internal at Matador. I think that confidence is growing as they do the repeat business and that they see it, that our plant staying online, even amidst Winter Storm Uri, where our guys were sleeping in their trucks, to keep everything going and doing everything else, has also aided the growth of San Mateo and will have a similar effect on Pronto. We are committed to that, while there's a tie-in to us at present. Everybody is treated the same and hope everybody feels they're getting the same quality service. If not, I'd like to hear about it, and they should feel free to call me directly. That's the plan. That's what you're committed to. That's what James Meyer and Sean O'Grady have pledged themselves to and everybody else. We're gonna run a straight game and be good partners. Yeah, Joe, you're exactly right. I think even evidence of that is, you know, even as Matador has spread the ball a little bit around the basin and maybe had less production in the Rustler Breaks area, we actually saw record natural gas gathering and natural gas processing this quarter. That really was due to third party, exactly as Joe said. You know, great job by the business development teams as they've signed third party contracts. We've seen, you know, recent one contracts both at San Mateo and at Pronto. Great job on both of them. Exactly as Joe said, you know, we treat them just like we treat Matador and on an even basis. You can call him, you can call me as well. You know, I'm happy to answer that call. We're grateful for the third parties around our system. Brian probably appreciate you giving me a call first, but I'd like to have it. All right. That's a good call, guys. You know, I'm gonna ask a question on Advance and, just if you could give me a sense of... I don't think you guys typically have, you know, completed things and brought them online in these larger queue packages, but you've got 121 well package, you know, obviously July, August, and then another one starting sometime early next year. Can you just give us a sense of, you know, how you plan on how it's gonna, you know, be brought online? Is this, you know, gonna be sort of a stairstep thing little by little, or is it one of those things where you're not gonna max out the capacity, so you're gonna see wells gradually, you know, those 21 wells gradually come online over a period of a few months to keep production fairly stable over a longer period of time? Can you, can you just give us a little bit of color for that? Yeah. Hey, Scott. Hey, it's Glenn again. Just, thank you for the question. I do think, like, it's important to highlight, just as I mentioned, we've been at it just for a little while here on these Advance properties. As you mentioned, the 21 wells is a bit of uncharted territory for us. The biggest batch I think we've done is 13 or 15 wells at a time. There are, you know, there are logistical challenges associated with that. We gotta make sure that we have sufficient capacity on all the different, you know, on oil, gas, and water. The way that we have them planned is really kind of in a staggered fashion, coming on, you know, a few wells at a time, with, you know, a couple days in between. That's really the way that it's modeled. There's, you know, again, we've cautiously optimistic. We still gotta go and execute, but we like our chances. Got it. Okay. No, I appreciate that color. Thanks. Thank you. One moment for our next question. Our next question comes from Leo Mariani of Roth MKM. Your line is now open. Hey, guys. I was hoping you could talk to the acquisitions that y'all made here in the first quarter. If I'm looking at this right, I'm seeing about $104 million on the cash flow statement. Just curious, I don't know if part of that might have been an advanced payment on the Advance deal, or, you know, that was all just kind of, you know, separate, you know, deals out there. Could you maybe give us some color around that $104 million? Was there any production that maybe was added as a result of that as well? Leo, that's a good question. I compliment you on being so astute to pick up that might be related in some way to the Advance. That $80 million of that was a deposit on the Advance purchase in closing. The other $20 million was our usual, where we buy acreage here and there or trade for acreage. If you want more color, Van is here. Van, you wanna add to that? Yeah, just a little bit of detail behind that $20 million. It's about 40 different deals. It's our brick by brick approach that we've always done. It was just more of that. Again, kind of 40 or so deals across all of our acreage. Okay. No, that's definitely helpful for sure. Just looking at obviously the production here, I'll just say first half of the year, you know, certainly looks, you know, very strong. Obviously, you significantly beat first quarter. You're guiding up second quarter by roughly 7% on the production. You know, can you provide a little bit more color around the second quarter, you know, guide up on the production? Certainly sounds like part of it was Advance related. Just kind of in light of that strong first half, you know, a little surprised to see that you're not maybe guiding up full year production, but maybe that's just some conservativism just given that Advance just closed two weeks ago. Any color around that would be great. Yeah. I think a lot of it is just trying to be conservative and cautious. There's a very good chance it'll exceed what we put out there, but we wanna be 100% sure we can deliver, what we say. Brian, would you- Yeah, no, I think that's right, Joe. You know, as it relates to the second quarter, Leo, I think you said it, you know, part of it is certainly Advance, both Advance wells doing better than we thought that they were gonna do. In addition, we always said kinda early to mid-second quarter for the closing of Advance. It probably closed, you know, a couple weeks earlier than we had it forecasted, that helps in the second quarter. You know, in addition, I'd just say that, you know, the operations team's doing a great job and the wells continue to produce better than we anticipated they would. You know, we also have seven additional wells that were turned online in the first quarter, kinda right at the end of the first quarter, but those contribute to the second quarter increase as well. Look, we're really excited about how the first quarter turned out, how the second quarter's looking. As Joe said, we look at the full year, it's early, kinda early innings still with Advance. We've only had it for a couple of weeks, but we're excited about the opportunity set. As we kinda run the numbers and look at the forecast, it, you know, points to the high end of our guidance, which we're excited about. I think that that's a really great place to be. Overall, it's a, you know, roughly a 20% increase off of where we were last year. That's a, that's a great increase and place to be for this year, and we're excited about it. Okay, thanks for the color, guys. Thank you. One moment for our next- Thanks, Leo. One moment for our next question. Our next question comes from Subash Chandra of Benchmark. Your line is now open. Thanks. Good morning, everybody. Another follow-up, I guess, on the U-shaped well. Would it ever have a broader application? Is the simulation cost any higher just to sort of, you know, get all that frack energy around the curve and so on? Thoughts there? Hi, Subash. This is Chris Calvert again. You know, just thank you for the question. I guess you're asking if there's an increased stimulation cost, and the answer to that is really no. I mean, the technical specifications of the completion, we really kind of set ourself up nicely. If you look back two to three years ago, we really made a transition from coiled tubing drill outs to stick pipe drill outs. These standalone snubbing units, these fit for purpose snubbing units that Matador started using, really not exclusively, but 100%, you know, starting about two years ago, that really eliminates a lot of the risk on the drill out side. You know, on the completion side, that carries a lot of the weight with how do you actually clean these wells out. From the stimulation side itself, you know, the pumps don't really care if they're going straight down hole or if they're making a U-turn, the pump's on surface. There's really not too much or really any increased stimulation costs. The way that we're planning these wells, we'll be looking to utilize dual fuel, dual fuel frack fleets, simultaneous fracturing operations on these wells as well. I think from the completion side, you know, there's not too many technical differences versus a straight well versus a U-turn well, so to speak. Got it. Thank you for that. you know, could it have a broader application? Yeah. Subash- For instance, would you roll it out if it works really well? Subash, this is Glenn Stetson. Yes, we've identified approximately 81 mile wells that could be converted to approximately 40 two-mile horseshoe wells, if you know, if this is something that we feel like is a good path forward. One other thing that I would probably add onto that, Subash, you know, these U-turn wells had been drilled in the basin before. You know, we were not the first to do this, but, you know, if you look back in public data, 11 more U-turn wells have been permitted by peers and by other operators in the basin. I think the industry is starting to see this and gain traction with this. You know, we're excited about where we are with these wells and getting them successfully cased. We still have work to do to get them completed and bring them online. I think, you know, the industry is looking at this as well, not just Matador, but we're proud of where we are having these wells drilled and cased. Well, yeah, thank you. The follow-up I, you know, I guess is, the WAHA exposure with Advance. You know, any updated thoughts there on, you know, any bottlenecks at all or how you're managing that risk? This is Gregg Krug, EVP of Marketing and Midstream Strategy. We feel pretty comfortable as far as our exposure to WAHA. We've got a pretty diverse portfolio as far as gas that we've got capable of going to Houston Ship Channel, SoCal. We feel pretty confident about that. We have plenty of capacity out of the basin as far as at least getting to a liquid hub. We're not feeling the, you know, the pinch that maybe some others are. Okay. Thank you all. Thank you. One moment for our next question. Our next question comes from Zach Parham of J.P. Morgan. Your line is now open. Hey, guys. Thanks for taking my question. You mentioned earlier on the call that you really only started to see some smaller cost components like diesel move lower in 1Q. Have you started to have any conversations with your service providers on the bigger ticket items like rigs and completion services moving lower going forward? Maybe give us some color on how contracted you are on those larger line items for the rest of the year. Yeah, of course. Zach, this is Chris Calvert again. I'll probably have Billy speak to the rigs specifically after this, but we are continually having conversations with our service providers. We've always kind of spoken to the optionality that we have built in to these vendor relationships. You look back, whether it's Patterson-UTI on the drilling side, Halliburton or Universal Pressure Pumping on the stimulation side, you know, these relationships go back really, you know, 10 to 40 years, depending on how far you wanna look back. We're constantly having those conversations with our service providers. You know, I can speak on the pressure pumping side. You know, we do have near-term indicators that maybe those horsepower charges are maybe somewhat starting to plateau. you know, like I said earlier on the call, none of these costs have actually come down yet, but, you know, we're optimistic. You know, once again, a rise in oil price, change in demand, things can kinda change relatively quickly. We are optimistic that maybe some of these costs have plateaued, and you haven't seen really the rate of change that you saw in 2022. We are constantly working with our vendors on these things such as, you know, completion and drilling services, and Billy can speak to the drilling side. Well, Zach, this is Billy Goodwin, President of Operations here. Yeah, I'll just kind of back up what Chris is saying also on the drilling side there. Like you mentioned, there are some things we're seeing there on as far as steel looking out further in the future and rigs. It seems like things have plateaued now and, you know, we're expecting, you know, with prices where they are right now, we think we may see them roll over here as we get further out into the year. I mean, diesel has come down. We've seen that come down, so that's affecting the truck in there a little bit. We're hoping to see that here, you know, coming up in the future just so early, you know, that we're just starting to see these things. We're not really realizing those things yet, but we're looking forward to it as we move further out. You know, with the steel price, that's a big thing with those U-turn wells we've been talking about, the horseshoe wells, because, you know, eliminating, you know, 50,000 feet of casing, drilling those two wells versus two wells, that was a big savings. That alone was $4 million savings there. Just these things we're doing to, you know, cut down on costs through better efficiency, better execution, better planning, you know, it's really helping us out. We see this horseshoe type, you know, efficiency helping us, you know, on down the road. Thanks, guys. I appreciate that color. I guess just one clarification. Can you give us any color on the total cash outflow for Advance after the purchase price adjustments? I know you mentioned an $80 million deposit that was paid in 1Q, but just curious what we could see on the 2Q cash flow statement. Yeah. This is Brian, Zach. Thanks for the question. We really did, you know, I mean, after the adjustments were made, it really was close to the $1.6 billion. Of course, we have the $80 million in deposits that was part of that. You know, right above $1.5 billion from a cash perspective that you'll see next time. I think, you know, we look at the purchase price adjustments, they really equalize themselves out. There's a time period after closing where we continue to work on those. That's really kind of the cash component was the $1.6 billion minus the $80 million that was in the deposit. The other point, Zach, that I'd just point out to you on this transaction is that picking up the acreage, picking up the additional business and aren't easy to quantify, but have certainly added the value. The larger size makes it us eligible for a potential upgrade. We had the money between our cash on hand and our availability under our line of credit to close out the deal. For safety's sake, we went ahead and had the bond issuance for $500 million to give us a safety net for a dramatic change in oil and gas commodity prices or some other calamity come up to maintain that strong balance sheet and make sure that we had optionality on other opportunities that may come up. We felt we haven't been asked yet about the bonds, but wanted to say again how pleased we were that there was such a strong response. We went out with a $400 million. We had orders in for over $3 billion, so we upsized it to $500 million, improved the terms, and felt we got all blue chip, AAA good quality bond holders out of that. Now we feel like that it's one of those rare acquisitions that we think has had a dramatic effect on value for the good. In that, we're picking up wells that are just waiting completion to put online. We've picked up more production. We picked up a number of their field people, our quality guys to help us, and very pleased with the way everything has gone. We're in good shape to finish this year. We need to put a finer point on the numbers, come July, and we'll have those for you. Also it's clear that it's setting up 2024 in a fashion that we look at comfortably, basically almost for two years and know that we'll be delivering for our shareholders. Got it. Thanks, Joe. Really appreciate the answer. Thank you for the question. One moment for our next question. Our next question comes from Tim Rezvan of KeyBanc Capital Markets. Your line is now open. Good morning, folks. Thanks for taking my question. I was a little surprised, maybe I missed something in the release, but I would have thought with, you know, incremental debt on the balance sheet for the deal that we would have seen some oil hedges in place. You know, we've had a tremendous amount of volatility in crude, but there have been sort of windows where, you know, you've seen, you know, oil strengthen this year. Just kind of curious your thought on that as you look to sort of protect the balance sheet going forward. Well, Tim, I'll start off and let Brian finish up, or let Greg finish up. We look at hedging as opportunistic. You know, we had strength of balance sheet that, you know, we've hedged in the past. I've hedged production all the way back to 1988. We just saw this as an opportunity. We thought that oil prices are more likely to go up than down, and it just wasn't necessary. Greg, any thoughts? Yeah. I mean, Joe hit it right as far as the, as far as we look at for opportunities, and we're still in a backwardated, you know, we're still in a backwardated market. I mean, if you look at 2024, it's actually less than what it is for the balance of 2023. We are constantly looking at that. I mean, if we do see an opportunity to do something, we'll definitely try to do something there. We just haven't seen just the right combination yet to pull the trigger. Okay. That's fair enough. If I could just circle back to the comments about the wells in progress at the end of 2023, because I think a lot of us are trying to understand how this ramp could look longer term. You started this year more efficiently. I think it was 3.1 more net turn in lines than expected. If you continue to operate this efficiently, are you okay with more completions than planned and exiting the year with fewer wells in progress? Or, you know, is sort of that capital program going to be a governor on 2023 growth? This is Brian, thanks for the question. I think if we look at the wells in progress, we are excited about those wells. I think we really think that'll be the number that we do. You know, I do think from a CapEx perspective, there might be some opportunity on these 21 wells that we're drilling right now in advance, those will be completing as we kind of end, you know, the year. We might pull up some of those completions, you know, into this year, I don't think it really results in a lot of extra wells at this time that are going to be into 2023. You know, I don't think we look at necessarily there's a governor with CapEx. I think we want to do what's right and develop those properties correctly. I don't think we have some hard governor on it. You know, we want to do the right thing by the properties themselves. Tom, did you have anything to add? I was just gonna, you know, emphasize, you know, we've always priced optionality, you know, in our, in our plans, and it is, you know, it's early days. Got a lot of golf to play before we get to the year-end, and we'll see how things unfold. You know, as was mentioned earlier in the call, those additional net TILs that came online in the first quarter, they come online very late in the quarter. You know, I just think the operations team did a nice job finishing those projects just a little bit sooner and just pulled in those positional wells just kind of barely into the first quarter. I agree with Brian's comments. It doesn't necessarily directly translate into a year-end 2023 change in our TIL count, at least this early in the year. One other comment I make on the hedging is just that the floor is probably reasonably okay, but the upside is limited, so that if you have a somewhat reversal in the top price, you know, the ceiling, you don't have much room, and you could be quickly paying money out rather than receiving the benefit of higher oil prices. That's where we think it is. We think it's, you know, oil prices currently are a little less, and that the middle ground is somewhat higher above the price you can hedge. We would think we'd be losing money on the outset or undertaking too much risk on having to not getting that benefit of higher prices should they turn around. Okay. I appreciate all the comments. Thanks. Thank you. One moment for our next question. Our next question comes from Jeoffrey Lambujon of TPH. Your line is now open. Good morning, everyone, and thanks for taking my questions. I have one to add on free cash allocation. I appreciated the commentary you all gave on being for both dividends and returns, but also for measured growth. I was hoping you could just speak to, you know, one of the other options that y'all highlighted in the release in terms of bolt-ons and acquisitions, which I know you spoke to a little bit in terms of the brick by brick approach in Q1. As you think of bigger opportunities and the strength and liquidity that you referenced a couple questions ago, where are you all spending more time today in terms of assessing opportunities that are out there? How should we think about what you see potential for over the near term, if it will be more midstream-weighted, just given the deal just closed on Advance, or if you still see pretty good opportunity out there on the upstream side as well? Hey, this is Van. I think what you're gonna see is more of the same. We've always been interested in opportunities as they come up, but mainly to keep a good eye on our balance sheet. If the right opportunity pops up, we're gonna give it due consideration. I think you'll see more of our brick by brick approach going forward as you have for many years. As other opportunities come up, we'll take a good look at them, but we're not gonna risk the balance sheet and other opportunities that may be out there on the midstream side just in an effort to make another deal. I think we're in a really good position right now. We've got a great runway of A-plus locations that'll carry us on for many years. I think by being opportunistic and it gives us the opportunity to make win-win deals with sellers who may be in a position to need to get out at that time. We'll just keep our eyes open and, try to just take a conservative approach and do the right thing for the shareholders. Just a couple of points I'd make with, I agree completely with Van, but a couple of points. We like brick by brick 'cause there's a whole lot less risk. That's generally adjoining properties or interest in properties you already have. You're not taking on the risk of a whole bunch of new properties that you don't know exactly how they were completed or how exploratory their acreage is. You tend to know it. We always like that. They're generally smaller, but they carry a whole lot less risk. The second is, again, what we try to emphasize. If we can't feel good about that it's profitable growth, we're gonna avoid it. Sometimes you're offered some good-looking properties, but they're just too expensive. You got to take your time and look for the ones where that mesh well and will be profitable, that you have something more to offer than just money to make it work. Again, we're on the other side, you know, we're a public company. We play a straight game, and if someone makes us a serious offer, we'll look at it seriously. We're open to trades, and we do a fair amount of trades. The industry out there in the Permian and the Delaware, people have been trading properties and cooperating with each other to convert one-mile proposed laterals into two miles. We like that too because those are the win-win deals that Van's referring to, that make both sides happy. That's the way we like to come out of deals. Great. I appreciate that. Then to squeeze in a follow-up, just thinking about some of the factors you highlighted that contributed to Q1's production performance, besides the turn in line timing and less shut in time. I think y'all also mentioned outperformance at State Line. If you could talk a little bit about drivers there, repeatability across the program this year, and if there are any early indications on performance relative to your expectations from some of the wells that y'all brought online towards the end of Q1 and into Q2 here. Hey, Jeff, this is Tom Oelsner, EVP of Reservoir Engineering. You know, I think we're very encouraged by what we see so far. You know, State Line is obviously has been a very important asset to us for a long time. I think the team's attention to detail and making sure that all those wells are always very well maintained, you know, is certainly something that helps us out, you know, quite a bit. I think as we'll, you know, explore the advanced properties further and get to know those better, I think there's gonna be some different opportunities that may come up to improve the flow assurance on those properties as we've seen in other parts of our portfolio. I think I like our chances, but it's still quite early days. All right. Thank y'all. Thank you. One moment. Our last question comes from Kevin MacCurdy of Pickering Energy Partners. Your line is now open. Hey, good morning, and thanks for fitting me in. I was hoping for a little clarification on some of your comments on the release. Specifically, when you mentioned that you're gonna be at the high end of the production range, is that for both oil and equivalent? Just to clarify, there's no change to the midpoint of CapEx, correct? Yes, this is Brian. I'm happy to take that. You're correct, no change on CapEx right now. I think as I mentioned earlier, we think that, you know, we maybe had some savings in the first quarter, we do think maybe we'll pull forward some of the completion dollars at the end of the year. CapEx stays largely the same. You know, looking at the high end, it really is on a BOE basis. As we point to the high end, I think, of course, that means that we're gonna increase on the oil and the gas as well. I think that the high-end point that we did was really on the BOE basis for total production. That we're, you know, we're excited about that and be able to point to the high end and the great start to the year that we've had. Brian, I just take this as we're nearing the end of the conference, is just to point out that we've already paid down $75 million on our RBL, that, you know, the revenues to date have been a little better than expected. I wanted just to put a little specific that wasn't empty talk, but we have paid down some already and think we'll continue to do so. We gave you a slide which projects the pay down that we've had since 2020 on our RBL that paid that off that made the Advance acquisition possible. We're planning to head in that direction again as we pay down the RBL as we did before and get this down. We like going into, you know, as the years pass, in a stronger and stronger financial position because we think that's healthy to combine the organic growth that we're experiencing and benefiting from with some potential acquisitions that are logical fits to our own property base. You know, what you should see that we have reason to be excited that we've already started paying down and beginning the program to pay off the RBL as we did when we brought all the BLM properties online a few years ago and started enjoying that cash flow. Yes, thank you for that color, Joe. You guys, your free cash flow was certainly higher than our expectations for the quarter, great job on that. My follow-up question was on the horseshoe wells. Are you guys expecting the productivity of those wells to be in line with kind of a normal 2-mile lateral? Are there any changes in productivity per foot as you factor in the U-shape? Hey, Kevin, it's Glenn Stetson. The short answer is we're expecting the same kind of BO per foot as you would a two-mile well. We're basing that off of there's not a whole lot of U-turn wells that are producing today. There's a few in South Texas, and then there are four in the Permian within a 20-mile kind of radius of where we're drilling these wells. We do feel very confident, you know, again, from the technical aspect to get these wells completed, and we'll wait and see. For our projections, it's just a similar performance on a per foot basis. Thank you for taking my questions. I just conclude on the horseshoe is we don't have enough data points, but we're going cautiously. This isn't a deal where we're lining them up and gonna come out with 12. I think it's very encouraging that others are doing it, and so far experience is good. Some have not had such a good experience, but our team, I think, really took the preparation, all the preparation they could, to bring this about, and I'm real proud of the team, Travis and Tyler that I think did a real good job, supervised by Glenn, Tom and Chris. It was just an example of the team working together and the depth that we're trying to create among our technical staff. Thanks. Also, I wanna be sure to shout out to our accounting group. They were put to the test between year-end numbers, Advance numbers, recorded numbers, they really responded. Thanks to the accounting and financial group for coming through. Just the whole team, this quarter's been very gratifying to me as the CEO and our two presidents, Van and Billy, just the way our teams responded and met the challenge. We're eager to keep going on the second quarter, and we're eager to get back to you in July and have some more news for you. In fact, I'll close on this, may be amusing to you. My hometown newspaper of Amarillo, Gary Peterson, on the other side of the Advance deal, is from Amarillo, too. We've been friends for a long time, and our hometown newspaper of Amarillo recognized this deal in yesterday's paper on the front page. I've worked all my life to get on the front page and finally did it. No one was more surprised than I was that Amarillo would take an interest in a deal in New Mexico.