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Good morning, ladies and gentlemen. Welcome to the First Quarter 2023 Matador Resources Company Earnings Conference Call. My name is Didi, and I'll be serving as the operator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes, and the replay will be available on the company's website for 1 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 2023 earnings release under the Investor Relations tab on our website. And 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, Mac. 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 hand off has been very professional from Ameredev and in cap, 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 Matador was on. And 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 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 the difference. So 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. So with that, I'd like to open the floor for questions. Mac, whoever is first.
[Operator Instructions] Our first question is from John Freeman of Raymond James.
The first question, Joe, it was kind of on what you just touched on there at the end on just sort of the progress I'll keep making on the efficiency gains, drilling completion costs to keep coming down. And I guess, I know you all reiterated that the full year D&C guidance of the $11.25 foot. Could you perhaps give me what that was in the first quarter, the D&C per foot.
John, this is Chris Calvert, EVP and Co-Chief Operating Officer. And yes, so the $11.24 that you mentioned, that was our full year guide, and that was with the 10% to 20% increase from service cost inflation that we really started working on in December of last year. And so 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. So we're 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. And so a lot of these efficiencies come from reduction on the drilling times, increased use of simul-frac, increased use of diesel fuel. So we're definitely extremely excited and proud of the work that we did on the capital efficiency side and reducing those D&C cost per foot.
But one thing I would like to mention, on the service cost side, we really haven't seen other than small cost components such as diesel fuel that you and I have spoken about in previous conversations, we really haven't seen costs come down all that much from the vendor side. 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 until today or until the first quarter of '23. And so a lot of those savings really mostly all of those savings have been through efficiencies, and that's reduced drill times. Going back, we're using existing pads on the production facility side, increased use of dual fuel, better partnerships with third-party operators and specifically San Mateo when it comes to water usage and getting better rates on our water for stimulations. And that's -- we lean on our partnership with San Mateo for that. And so it really has been a push from the operations group to mitigate those service cost inflations that we've seen. But like we say, it's really 1 quarter's worth of work. And so while we're proud of where we are, we still have a lot to do in this year. And so the $11.24 that we put forward in the capital guidance plan, 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.
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? Is anybody in the operations team have prior experience with the Horse well. I know there's been a few that have been done over the years in the industry. Just any background on kind of what led to that decision.
So I'll start out with the kind of the wide and then I'll let Chris talk about some of the operational efficiencies. So this piece of acreage was unique in that the Upper Wolfcamp to the Wolfcamp A-XY was undeveloped, but in our section, but that had been developed on every other side of this piece of acreage. And so the illustration, I think, shows it very nicely that we put in the slide deck. But ultimately, what we're doing here is instead of drilling 4 1-mile Wolfcamp Axis. We've actually drilled and TD and case these wells already. But what we did was drill 2 Horseshoe wells instead. And so 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. And so the next piece of this is to go in and get these wells completed and then put them on production.
I think from the genesis of this project, it really starts with the team and the teamwork that was illustrated with bringing this project to fruition Travis Wolf, the team lead of our West Texas asset. Former MaxOps graduate 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 property. But then from the technical side, it was -- the curve on these [ U-turns ] I think, if you're looking at a piece of paper, look somewhat dramatic, but 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. And so I think from a technical standpoint, we were very confident in our team, confident in the drilling group led by obviously [ Billy, Josh Basur, ] our MAXCOM team plays an integral part in projects like this of keeping us in zone and allowing us to drill 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 4 single mile wells versus 2 U turns, we've calculated that it's about a 50% reduction. So 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. And so there's a time savings component to that, but then also on 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 4-stream well, if you're doing 4 single mile laterals versus 2 U-turn horseshoes, we're actually saving about 10 miles of casing, basically by reducing 2 vertical portions of these wells. And so 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, whether it's simul-frac or move frac, dual fuel usage, you 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. And so we're extremely proud of these 2 projects or these 2 wells. There is still work to do, and we're expecting to turn these online in the latter half of this year.
Our next question comes from Gabe Daoud from Cowen.
Guys, maybe I was hoping we could start with the advanced properties 1Q 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 '24. So I guess, 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? And then 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 economies.
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 advanced assets. So very strategic, great assets, perfect fit into our existing assets. And so 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. But we are excited and encouraged by the fact that they produce better than we thought. And so we've had, I guess, key to the car now for a couple of weeks and so still early on as we drive the car here. But we are excited about it. I think, in fact, we can -- I 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. And the 2 wells you mentioned, we do expect kind of the second half of the year, those will come on kind of in that third and fourth quarter, as you said.
And then as we look to next year -- we have 49 total wells that are going to be in progress at the end of the year. 21 of those are going to be the wells that we're currently drilling on the advanced acreage, and we'll be completing later this year. So we expect those to come on early next year. At the end of the year, we're going to end up with 140,000 or so on a run rate. And that's a great runway as we kind of go into next year and those 49 wells in progress will just add to that, including the 2 wells that are in advance. So we're really excited about 2024. If you look at just comparing 2022, the fourth quarter to 2023 in the fourth quarter on a true just BO basis, so an oil-only basis, that's a 40% growth is what we expect. And so that sets us up really well for great 2024, both on a BO basis, on an oil basis and then just also on a total BOE basis. And so we're really excited about 2024, what that looks like. It's early in the game. I mean we just finished the first quarter. So a lot of golf to play before we hit 2024, but we're really excited about the opportunity set ahead for us.
So I guess then just given the elevated maybe relevant progress exiting this year versus historical norms and an 8-rig program, which is also, I guess, a high rate program for Managed on historicals, obviously, a larger company now. But then how should I think about like the exit to exit growth in '24 relative to '23, just given all those moving pieces?
Yes. So I think the exit growth, we mentioned the exit growth in 2023. If you take that 143,000 BOE per day and you just held it flat, it's about a 15% growth over what 2023 would be if you held it flat into 2024. We obviously hope we can do better than that. And hold-flat as you mentioned, the 8-rig program. But it's pretty early for us, I think, to talk about an exit rate in 2024. That's, I guess, almost 2 years away. But we're certainly excited about 2024 and what we can do there, getting this at rig on and being able to have those opportunities and the advanced acreage, especially it's some -- we talk about 8-plus locations at some of the best acres will have and compete very well with the other acreage we have in the drilling locations. And so I don't know, Tom, do you want to talk any more about the acreage of sell?
It's Tom Elsener, EVP of Reservoir Engineering. 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 advanced properties. The bulk of it there is in Southern Ranger Northern Antelope Bridge where we've drilled wells nearby like the Mallon wells that have each produced 1 million barrels of oil each nearby some of our other [indiscernible] wells in the northern end of Antelope Ridge. And then we'll further south where the Roddy Robins are. This is an area that's characterized by having very high oil cuts, typically 75% oil cut and also very low water cuts. -- typically 2 barrels of water per 1 barrel of oil and sometimes even closer to 1:1. Obviously, we've talked about the kind of the ability with Pronto to be able to be nearby, and we look forward to expanding that relationship to be able to see some of the similar benefits that we've seen across other portions of our acreage like Stateline or else breaks or -- and I think what we're seeing is, as we've said, we spread the ball around quite a bit this year and all our different asset teams are contributing. And so we're very excited to bring these properties on. But there's -- with 150,000 net acres, all of our different teams are trying to get activity in their area. And so in the second quarter this year, we're going to have 11 wells in Ranger and 4 wells in Rustler Breaks, another 4 wells in Antelope Ridge and 8 wells at Stateline, where, as we talked about some of the outperformance at Stateline due to having great flow assurance with San Mateo and with our facilities team. And so working for all these types of benefits you start to see on the advanced properties.
Our next question comes from Neal Dingmann of Truist Securities.
Nice update as always. Joe, my first question is for you. And really, what I'm wanting to do is how you currently -- if it's changed at all, or you currently view production growth versus shareholder return. And again, why as this is though I definitely appreciate the solid continued growth, I believe you've said in the past, your wife always appreciate it's a nice dividend occasionally. So I'm just wondering how you view things.
Well, Neal, is -- thanks for the question, but we're for both of them, work 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 major pace. And part of that is we, again, want to have the profitable growth, but we're not growing for growth sake. And the same thing on our dividend, we're going to grow our dividend in a manner that once we raise our dividend, we don't want to be in a position where we ever have to walk it back. And so we began with a $0.10 dividend went to $0.20, went to $0.40, and we've continued to grow it now at $0.60. And I think if prices stay anywhere at this level that our shareholders can look for a return sometime over the next year, but we want to be prudent about it, but we want to be one of those companies that steadily increases its dividend while steadily increasing the value of its shares. And 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. And you'll there's plenty of support, and we think we're proceeding at a prudent pace. And you look at our Board. They're heavy shareholders. They own hundreds of thousands of dollars just to get on the board. So we believe that makes a difference, too, to have that heavy ownership. And 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 want to keep those in balance. So I hope that -- and it's discussed all the time. And we just don't want to announce a dividend increase, but then have to walk it back. So shareholders seem to be real happy with that, that I talked to. And remember, we didn't come up through private equity but friends and family. So one thing, if you have any family members in and shareholders, you're going to hear get some feedback at ever family gathering and the same thing with you friends. And so everybody in the long time shareholders seem to be pleased in our institutions, and we'll continue to keep an open ear to them. And if they have concerns or preference, we're always willing to listen.
No, that's crystal clear, Joe. And then just maybe my second question, a little bit been asked for me asked 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 23 production, I noticed, I think it was on one of your earlier decks on Slide 33, you talked about in your prior deck, where you all mentioned a minimal impact from the 21 new advanced wells in third quarter due to these wells coming on late in the quarter and then it looks like the step up even a bigger -- I mean you definitely have a nice step up in third quarter, but even another significant step up in 4Q. And I'm just wondering, maybe it's too early as [indiscernible], 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're already seeing?
Neal, it is Glenn Stetson, EVP of Production. Yes, thanks for the question. So Brian mentioned it, but we've been at the helm, so to speak, or in the driver seat for a couple of weeks. So give us a little time, and I think we'll have a nice update for you in July. But 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. And then speaking to the operations guys, I just want to give a little tip of the hat to them. We had their drilling rig in -- integrated into our MAXCOM room from day 1, the completion guys. 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. And then I think that the same efficiencies that we saw from completing wells in the first quarter, an example being Rodney Robinson is that we hope to complete these wells kind of faster than anticipated. And hopefully, if everything goes smoothly, it will contribute to Q3 in a meaningful way.
Our next question comes from Scott Hanold of RBC Capital Markets.
Tom, you had mentioned a little bit earlier about the advantage of the midstream and how that's helped some of the well performance. And 1Q '23, you did have pretty strong performance. Can you give a little more color on the advantage that midstream has provided you? And as you guys connect all the systems, and I think that's going to be what by early next year, like how does that provide you better flexibility in stronger flow assurance and performance?
Sure, Scott. Yes, 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. I think that the team is kind of all around, when we were designing the Stateline development I think they look at it as a unique opportunity to design all of the infrastructure kind of from the ground up. And license has a lot of credit to that as well. But some of the things that they've done down at Stateline are create this kind of unique kind of low pressure medium pressure and high-pressure system, whereby the different 54 producing wells at Stateline can be fit to the right pressure system where they produce their oil, gas and water into. And this allows us to custom-flow these wells into the right system. So we can kind of always optimize the production. And this has been something that has been a great benefit to State Line and keeping those wells flowing without kind of constantly having to shift around the clip has benefited Stateline in a big way. And certainly, none of this could happen without San Mateo, keeping their plant running. Stateline has been producing now for several years, and I can't remember a single day of downtime to stay line. I think Gregg Krug and Brian Willey and everybody at [indiscernible] 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. And so I think they've done a wonderful job with that, and I'll hand it over to Brian.
Yes. Thanks, Tom. I would just say we're excited about that in Stateline and the synergies there. But we also -- 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, 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 going to drill there. And so that build-out and that partnership is great, where we'd be able to go down and just talk to the San ate guys and the San Mateo guys can be in the actual meetings where we're planning the wells on the 7 side. And so kind of hand-in-hand being able to support Matador and ensure that there's a lot of flow assurance there. And I think even looking over to PRONTO, the same thing, same story. Late this year, kind of 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 a Pronto. Pronto can flow to San Mateo. And that will kind of complete that gas system all across the northern part of the basin. And so the synergies that Tom talked about over at Stateline, 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. And 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 to anybody else. And there isn't a preference for ours over there that we do both, and we have tried to be very, very clear that they're going to get every bit as good a service as anything internal at Matador. And I think that confidence is growing as they do the repeat business and that they see it that are staying online even amidst storm Yuri, our guys are 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. And we are committed to that while there's a tie-in to us at present, everybody is treated the same and hope everybody feels you're getting the same quality service. And if not, I'd like to hear about it, and they should feel free to call me directly. But 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. So we're going to run a straight gain and be good partners.
Joe, you're exactly right. And I think even evidence of that is, 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 a record natural gas gathering and natural gas processing this quarter. And that really was due to third-party exactly as Joe said. And so great job by the business development teams as they've signed third-party contracts. We've seen recent contracts both at San Mateo and Pronto, -- and so a great job on both of them. And so exactly as Joe said, we treat them just like we treat Matador on an even basis. And you can call him, you can call me as well. I'm happy to answer that call. But we're going for further third parties around our system.
And then I'm going to ask a question on advance. And just if you could give me a sense of -- and I don't think you guys typically have completed things and brought them online in these large packages. But you've got one 21-well package, obviously, July, August and then another one starting sometime early next year. Can you just give us a sense of how you plan on bringing -- how it's going to be brought online. Is this going to be sort of a stair-step thing little by little? Or is it one of those things where you're not going to max out the capacity. So you're going to see wells gradually -- 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 just give us a little bit of color for that?
Scott, it's Glenn again. Yes, 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 advanced properties. And 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. And so there are logistical challenges associated with that. We got to make sure that we have sufficient capacity on all the different -- on oil, gas and water. And so the way that we have them planned is really kind of in a staggered fashion coming on a few wells at a time with a couple of days in between. So that's really the way that it's modeled. There's -- again, we've cautiously optimistic. We still got to go and execute, but we like our chances.
Our next question comes from Leo Mariani of ROTH MKM.
I was hoping you could talk to the acquisitions that you all made here in the first quarter. 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 like an advanced payment on the Advanced deal or that was all just kind of separate deals out there. Could you maybe give us some color around that $104 million. And was there any production that maybe was added as a result of that as well?
Leo, that's a good question, and I compliment you on being so astute. 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 advanced purchase in closing. So the other $20 million was our usual where we buy acreage here and there or trade for acreage -- and you want more color van is here. Brian, do you want to add to that?
Yes, 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. And so 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. And then I guess looking at obviously, the production here, I'll just say, first half of the year certainly looks very strong. Obviously, you significantly beat first quarter. You're guiding up second quarter by roughly 7% on the production. Can you provide a little bit more color around the second quarter guide up on the production, certainly sounds like part of it was advance related. And just kind of in light of that strong first half, a little surprised to see that you're not maybe guiding up full year production, but maybe that's just some conservatism just given that Advance just closed 2 weeks ago. So any color on that would be great.
Yes. I think a lot of it is just trying to be conservative and cautious. The very good chance it will exceed what we put out there, but we want to be 100% sure we can deliver what we say. Brian, would you...
Yes. No, I think that's right, Joe. And as it relates to the second quarter, Leo, I think you said part of it is certainly advanced, both advanced wells doing better than we thought that they were going to do. And then in addition, we always had kind of early to mid-second quarter for the closing of Advance. It probably closed a couple of weeks earlier than we had forecasted. And so that helps in the second quarter. In addition, I'd just say that the operations team is doing a great job and the wells continue to produce better than we anticipated they would. And we also have 7 additional wells that were turned online in the first quarter, kind of right at the end of the first quarter, but those contributed to the second quarter increase as well. And so we're really excited about how the first quarter turned out. how the second quarter is looking. And as Joe said, we look at the full year, it's early -- kind of early innings still with Advance. We've only had it for a couple of weeks, but we're excited about the opportunity set. And as we kind of run the numbers and look at the forecast, it points to the high end of our guidance, which we're excited about it. I think that that's a really great place to be. Overall, it's a roughly a 20% increase off of where we were last year. And so that's a great increase in place to be for this year, and we're excited about it.
Our next question comes from Subash Chandra of Benchmark.
Another follow-up, I guess, on the U-shaped well. Would it ever have a broader application? And is the simulation costs any higher just to sort of get all that frac energy around the curve and so on. thoughts there?
Just to 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 ourselves up nicely. If you look back 2 to 3 years ago, we really made a transition from coiled tubing drill-outs to stick pipe drill outs. And so these standalone snubbing units sees fit for purpose snubbing units that Matador started using really, it's not exclusively but 100% starting about 2 years ago, that really eliminates a lot of the risk on the drill-out side. And so on the completion side, that carries a lot of the way with how do you actually clean these wells out. But from the stimulation side itself, the pumps don't really care if they're going straight down hole or if they're making a U-turn the pumps on surface. And so there's really not too much or really any increased stimulation cost. And the way that we're planning these wells will be looking to utilize dual-fuel frac fleets, simultaneous fracturing operations on these wells as well. And so I think from the completion side, there's not too many technical differences versus a straight well versus a U-turn well, so to speak.
And could it have a broader application -- would you would roll it out if it works really well.
Yes, we've identified approximately 8 1-mile wells that could be converted to approximately 42-mile horse wells, if this is something that we feel like is a good path forward?
And one other thing that I would probably add on to that, Subash, these U-Turn wells had been drilled in the basin before. We were not the first to do this. But if you look back in public data, 11 more U-Turn wells have been permitted by peers and by other operators in the basin. And so I think the industry is starting to see this and gain traction with this. And so 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. But I think 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.
Yes. And the follow-up, I guess, is the Waha exposure with advance. Any updated thoughts there on 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 capability of going to Houston Ship Channel, SoCal. So we feel pretty confident about that. And we have plenty of capacity out of the basin as far as at least getting to a liquid hub. So we're not feeling the pinch that maybe some others are.
Our next question comes from Zach Parham of JPMorgan.
You mentioned earlier on the call that you really only started to see some smaller cost components like diesel move lower in 1Q. But 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? And maybe give us some color on how contracted you are on those larger line items for the rest of the year?
And we've always kind of spoken to the optionality that we have built in to these vendor relationships. And you look back, whether it's Patterson on the drilling side, Halliburton or Universal Pressure Pumping on the stimulation side, these relationships go back really 10 to 40 years depending on how far you want to look back. But we're constantly having those conversations with our service providers. And so I can speak on the pressure pumping side, we do have near-term indicators that maybe those horsepower charges are maybe somewhat starting to plateau. Like I said earlier on the call, none of these costs have actually come down yet, but we're optimistic. But once again, a rise in oil price change in demand, things can kind of change relatively quickly. But 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. But we are constantly working with our vendors on these things such as completion and drilling services, and Billy can speak to the drilling side.
And I'll just kind of back up what Chris is saying also on the drilling side there. And like you mentioned, there are some things we're seeing there on as far as still looking out further in the future in rigs, it seems like things that plateaued now, and we're expecting 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. So we're hoping to see that here coming up in the future, just so early that we're just starting to see these things. So we're not really realizing those things yet, but we're looking forward to it as we move further out. And with the steel price, that's a big thing with those U turn wells. We've been talking about the horse wells because eliminating 50,000 feet of casing drilling those 2 wells versus 4 wells. Those are big savings. That alone was $4 million savings there. So just these things we're doing to cut down on costs through better efficiency, better execution, better planning, it's really helping us out and we see this horse type efficiency, helping us down the road.
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 the $80 million deposit that was paid in 1Q, but just curious what we could see on the 2Q cash flow statement.
Yes. This is Brian, Zach. Thanks for the question. We really did. I mean after the adjustments that 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. So right above $1.5 billion from a cash perspective. that you'll see next time. So I think 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. But 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 eligible for a potential upgrade. And we have the money between our cash on hand and our availability under our minor credit to close out the deal. But for safety's sake, we went ahead and to have the bond issuance from $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. So we felt we were -- we haven't been asked yet about the bonds, but I wanted to say again how pleased we were that there was such a strong response, and we had -- 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 bondholders out of that. So 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 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, and 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. But also it's clear that it's set enough 2024 in a fashion that we look at comfortably basically almost for 2 years and know that we can -- we'll be delivering for our shareholders.
Our next question comes from Tim Rezvan of KeyBanc Capital Markets.
I was a little surprised, maybe I missed something in the release, but I would have thought with the incremental debt on the balance sheet for the deal that we would have seen some oil hedges in place. We've had a tremendous amount of volatility in crude. But there have been sort of windows where you've seen oil strengthen this year. So 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, but -- and let Gregg finish up. But we look at hedging as opportunistic. We had strength of balance sheet that we've hedged in the past. I've hedged production all the way back to 1988, and we just solve this as an opportunity. We thought that oil prices are more likely to go up than down, and it just wasn't necessary. Gregg, any thoughts?
Yes. I mean, Joe hit it right as far as we look for opportunities. And we're still in the backward dated market. I mean, if you look at 24, it's actually less than what it is for the balance of 23%. We look at -- we are constantly looking at that. So I mean, we do see an opportunity to do something, we'll definitely try to do something there. But we just haven't -- we haven't seen just the right combination yet to pull the trigger.
Okay. That's fair enough. And then 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 line 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 is sort of that capital program going to be a governor on 2023 growth?
I think as we look at the wells in progress, we are excited about those wells. I think we really think that, that will be the number that we do. I do think from a CapEx perspective, there might be some opportunity on these 21 wells that we're drilling right now in advance. And those will be completing as we kind of end the year. We might at some of those completions into this year. But I don't think it really resulted in a lot of extra wells at this time that are going to be into 2023. So 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 the properties correctly. So I don't think we have some hard governor on it. But we want to do the right thing by the properties themselves. Tom, do you have anything to add?
I was just going to emphasize, we've always surprised optionality in our plans, and it is early days. We got a lot of golf to play before we get to the year-end, and we'll see how things unfold. As was mentioned earlier in the call, those additional net TILs that came online in the first quarter. They've gone on very late in the quarter. And so I just think the operations team did a nice job finishing those projects as a little bit sooner and just pulled in those positional wells just kind of barely into the first quarter. So I agree with Brian's comments, it doesn't necessarily directly translate into a year-end 2023 change in our to 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, 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. So that's where we think it is. We think it's -- oil prices currently are a little less and that the middle ground is somewhat higher above the price you can hedge. So we would think we'd be losing money on the outset or undertaking too much risk on having to -- not getting that benefit of how our prices should they turn around.
And our next question comes from Jeoffrey Lambujon of TPH.
I have one to add on free cash flow allocation. I appreciate 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 one of the other options that you highlight 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. But as we think of bigger opportunities and the strength and liquidity that you referenced a couple of questions ago, where are you all spending more time today in terms of assessing opportunities that are out there? And how should we think about what you see potential for over the near term? Is it will be more midstream weighted just given the deal just closed on advance or if you still see a pretty good opportunity out there in the upstream as well.
This is Brian. I think what you're going to 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. And so if the right opportunity pops up, we're going to give it due consideration. I think you'll see more of our brick-by-brick approach going forward as you have for many years. And as other opportunities come up, we'll take a good look at them, but we're not going to 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 great runway of A+ locations that will carry us on for many years. And 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. And 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 agree completely with Vans, but a couple of points. We like break-by-brick because there's a whole lot less risk. That's generally adjoining properties or interest in properties you already have. So 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. So 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 going to avoid it. And sometimes, you offered some good looking properties, but they're just too expensive. And you got to take your time and look for the ones where -- that mesh well and we'll be profitable that you have something more to offer than just money to make it work. So -- and again, we're -- on the other side, we're a public company. We play a straight game. And if someone makes us a serious offer, we'll look at it seriously. And we're open to trade, and we do a fair amount of trades and the industry out there in the Permian and the Delaware, people have been trading properties and cooperate with each other to convert 1 mile proposed laterals into 2 miles. So we like that, too, because those are the win-win deals that Vans referring to that make both sides happy and that's the way we like to come out of deals.
And then a 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 sudden time. I think you'll also mentioned outperformance at Stateline. 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 bottom line towards the end of Q1 into Q2 here?
Jeff, this is Tom Elsener, EVP Reservoir Engineering. I think we're very encouraged by what we see so far. Stateline, obviously, has been a very important asset to us for a long time. And I think I think the team's attention to detail and making sure that those wells are always very well maintained is certainly something that helps us out quite a bit. And I think as we'll explore the advanced properties further and get to know those better, I think there's going to 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. So I think I like our chances, but it's still quite early days.
Our last question comes from Kevin MacCurdy of Pickering Energy Partners.
I was hoping for a little clarification on some of your comments on the release. Specifically, when you mentioned that you're going to be at the high end of the production range, is that for both oil and equivalent? And just to clarify, there's no change to the midpoint of CapEx, correct?
Yes. This is Brian, and I'm happy to take that. And you're correct. No change on CapEx right now. I think as I mentioned earlier, we think that we maybe had some savings in the first quarter, but we do think maybe we'll pull forward some of the completion dollars at the end of the year. So CapEx has largely the same. 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 going to increase on the oil and the gas as well. But I think the high end point that we did was really on the BOE basis for total production. And so 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 and 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 the revenues to date have been a little better than expected. So I wanted just to put a little specific that wasn't the empty talk, but we have paid down some already and think we'll continue to do so. And we gave you a slide which projects the paydown that we've had since 2020 on our RBL that paid that off that made the advance acquisition possible. So we're planning to head in that direction again as we pay down the RBL as we did before and get this down, we'd like going into as the years passed, 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. So 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. And you guys -- your free cash flow was certainly higher than our expectations for the quarter. So a 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?
So we're -- the short answer is that we're expecting the same kind of BO per foot as you would a mile as you would a 2-mile well. we're basing that off of -- there's not a whole lot of turn wells that are producing today. There's a few in South Texas, and then there are 4 in the Permian within a 20-mile kind of radius of where we're drilling these wells. And so we do feel very confident in, again, from the technical aspect to get these wells completed, and we'll wait and see. But for our projections, it's just a similar performance on a per foot basis.
Now let's 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 going to come out with a dozen. But 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 really proud of the team, Travis and Tyler that I think did a real good job supervised by Glenn and Tom and Chris, and is just an example of the team working together and the depth that we're trying to create among our [ take on staff ]. So thanks. And also, I want to be sure to shout out to our accounting group -- they were put to the test between year-end numbers, advanced numbers, recorder numbers and they really responded. So thanks to the accounting and financial group for coming through. And just the whole team, this quarter has been very gratifying to me as the CEO and our 2 presidents, Van and Billy, just where our teams responded and met the challenge. So 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. Maybe I'm using to you, my hometown newspaper of Amarillo, Gary Peterson, on the other side the Advanced deal is from Amarillo 2. We've been friends for a long town and our hometown newspaper of Amarillo, recognized this deal in yesterday's paper on the front page. And so I've worked all my life to you on the front page and -- and it finally did it. And -- but no one was more surprised than I was that Amarillo would take an interest in a bill in New Mexico.
Ladies and gentlemen, thank you for your participation today. This concludes today's program.