Good morning, ladies and gentlemen. Welcome to the Third Quarter 2023 Matador Resources Company Earnings Conference Call. My name is Latif, and 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 and the replay will be available in 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. Mr. Schmitz, your line is open sir.

Thank you, Latif and good morning, everyone, and thank you for joining us for Matador’s third quarter 2023 earnings conference call. Some of the presenters today will reference certain non-GAAP financial measures regularly used by Matador Resources in measuring the company’s financial performance. Reconciliations of such non-GAAP financial measures with the comparable financial measures calculated in accordance with GAAP are contained at the end of the company’s earnings press release. As a reminder, certain statements included in this morning’s presentation may be forward-looking and reflect the company’s current expectations or forecasts of future events based on 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 in any subsequent quarterly reports on Form 10-Q. In addition, to our earnings press release issued yesterday, I would like to remind everyone that you can find a slide presentation in connection with the third quarter 2023 earnings release under the Investor Relations tab on our corporate 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, Mac and thank you all for listening in. It's a pleasure to be here today and a pleasure to give you this report. In very simplest terms, we said at the beginning of the year that we began the year at 100,000 BOE equivalent, and we're going to finish the year at 140,000. I was wrong. It's going to be 145,000. And we're pleased to report in addition to production being up, our debt is down, costs are down, and we think our opportunities are also up that the plans that we put into place are proceeding as expected or better than expected and we're excited to report this to you and look for your questions, but we feel we've ended the year 2023 with more inventory, more options, and the outlook for 2024 is even better. As strong as this year is, I repeat 2024 is better. I would point to you, I had two slides in the materials, which shows -- first one shows our performance over the last five years against our peers as selected and we've done -- we've done performed, we feel like we've outperformed them. And the second one is more interesting is our performance since the IPO. The team has made great strides. I give them the credit. People are really working well together. They've come up with good ideas and Matador has continued to grow. When we went public, we were about $300 million and today the market cap is somewhere around $7.5 billion. But it should get better as the year goes along. We've given projections, but they are confident they will all be realized. I think on slide B, some that struck me as we prepared this was that three times we have announced what were very meaningful…

Lateef, we'll jump into Q&A. Thanks.

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

Yes. Thanks. Good morning. Congrats on hitting some record volumes this quarter. Joe, you had highlighted the importance of some of these acquisitions you've made over time and the value they continue to add to Matador. And with respect to, I guess, the most recent one in advance, I mean, you all have been bringing in some of those first batch of wells, I think, starting sometime late August, early September. Could you give any kind of context on where you're at with that and some of the initial performance just in terms of your expectation and any kind of tangible data you can provide?

Good question, Scott. The thing that I'd really point you to is that the first of the year, we were at 100,000. And we said end of the year, we're going to go to 40,000, 140,000. And so here we are at 145,000. Obviously, the projections that Tom and the rest of our group has have been on the money and a little bit better maybe. And we're early times yet, but it looks promising to come in as expected or maybe a little bit better than expected. But we've been active in that area prior to the acquisition. So we knew that it was good rock area, just like what we also had on the adjoining leases and was just about as perfect to fit on an acquisition as we've had. So no surprises, no big surprises. It's pretty much as projected, which is nice, has been real nice and has fit in with our midstream. So that was the biggest acquisition we’ve ever done. There's always a little bit of wariness when you go into something of that magnitude, but it appears to be working out.

Okay. And I would assume that at some point, as you get more of those wells online, we'll kind of see the typical kind of update on well performance. Is that a reasonable assumption?

Yes, that's I think very reasonable. We just need a little more time and then we all feel that a well-established decline curves and well-established production history. And we -- but it's looking really good. Everybody here is as glad we did it. We do think it was another important milestone for Matador. So we've done transactions large and small, and have enjoyed working with Merida [ph] who was operating and they're private equity sponsors. So I think it's a win-win-win type of deal.

Okay. I appreciate that. And as a follow-up question, I know you gave some context last quarter on what you all think about 2024 and a 150 plus per day rate on production. And you obviously indicated you're now going to be adding that eighth rig in the first part of the year next year? And could you talk about what that means for that production number you provided? And any color on midstream CapEx if you have it? And really specifically, where we're at with potentially finding a partner for Pronto and whether you think you need to?

That's a really good question. I'm going to take that first and then we can come back to the other one is one is that, if we add a new plant, it's about $200 million. Well, that's really a small -- very small in comparison to the $1.6 billion that we paid for Advance. So we have close to $1 billion available on our RBL. Cash flow was up. Production is increasing, so clearly, if we had a partner, it's because of some enhancement that they bring to the deal. But if it didn't win, win, we're going to just go ahead and do it ourselves. It's a good opportunity for somebody, but what we're bringing to the table is the production and the staff, the experienced field staff to handle it. It's a proven deal. We've operated San Mateo in good fashion with a growing EBITDA group. Pronto is come on strong the same way and it's close to capacity. We have some short-term capacity that we can switch to where we're assured some firm capacity if that's what we want to do. So there's optionality there. We think this plant -- we're moving along with it as if we're -- it's just going to be us, we will look to somebody would like to get involved, we'll listen, but we think the economics are such, we're very, very happy to keep it ourselves. So as Gregg and I were talking about it unless it's win-win, we're just not very interested. Greg, do you want to add anything to that?

No. I think you said it well. This is Gregg Krug, EVP of Marketing and Midstream Strategy. Scott, I think that's – I think Joe hit it on the head when it comes to what we're looking for. We're looking for a win-win situation here with a possible partner if that's the direction we want to go. But that's the only way that's going to work for us. And -- but as -- again, as Joe said, that is something we could do this on our own, and we feel comfortable being able to do so. And we definitely like the growth potential out there with the amount of gas and the drilling that we're doing and also the third party. I think there's a lot of opportunity out there for third party. And we definitely are -- we feel a really good position to be able to take on that third-party gas with the connector, as you've mentioned earlier, we're looking at being able to do that and also with the plant expansion as well. So we like our opportunities out there.

I'm glad you mentioned the connectors, because that will connect up the Pronto plant swing around and coming through San Mateo. In the extent we've got 550 miles of pipeline out there, and this will just give us that much more optionality. So Scott, I hopefully have answered your question here, in particular, that the economics on a 200 having full control are inviting and the economics appear to getting better, particularly as we're adding an extra rig and going from there. So if you'll repeat your first question, I'll try to answer it quickly.

Yeah, yeah. No. I appreciate that. And it was with that 8th rig, where does that -- relative to your 150 plus a day prior comment on 2024, how does that 8th rig fit into that?

Well, I think I turn it to Glenn. My view is the 8th rig is being reflected in the 150,000 number, and that's part of the reason why we're confident that we'll increase it from present to add to our numbers and more in year 2025. Glenn?

Yeah. Hey, Scott, this is Glenn Stetson, EVP of Production. Yeah, and Joe hit it just right. Just to rewind a little bit too, when we picked up the advanced properties, we did operate a rig there for about a 1.5 month or two months before we dropped it to the seventh rig. And so really, just what's new in this release is timing on that eighth rig. And so to your point, we did soft guide for 2024 at the 150,000. That was inclusive of an eighth rig, but the timing piece was what was abstract. So anyway, we are going to pick up that eighth rig in Q1 and look forward to growing production to that 150 plus.

Okay. That's clear. Thank you.

Thank you. Our next question comes from the line of Gabe Daoud of TD Cowen.

Thank you. Morning, Joe. Morning, everybody. Maybe we could go back to the midstream angle and maybe just following up on Scott's question. And, Joe, you kind of eluded us in the response, but just curious if the Marlin plant is at full capacity, how does this impact the way the current 21 wells are being flowed back and the next batch of advanced wells and how those will be flow back. I guess you noted you could divert the gas and lay down some lines to San Mateo, but what would the timing of that be like and how full is the San Mateo plant?

Well, that's a whole bunch of questions all in one sentence. What I would simply tell you on that score is that it's not at full firm delivery capacity. What we are, it has room for a minimum production volume customers. Right now, we're taking some gas, some part of that is gas on an interruptible basis. But we can extend it and that's -- again another reason that we see a market out there for more minimum production volume deals so that people are confident of their flow assurance. We think that can be attractive. So we're leaving ourselves the flexibility to take up that optional space or to bring in third parties on a firm basis, in the meantime leaving us the option by keeping it on an interruptible basis. Gregg, did I say that right?

Yeah, yeah. It looks like, I mean, we have right now approximately 60 million going into that plant right now. But some of that, as Joe said, is on an interruptible basis. It's short-term contracts. So we do have room for additional capacity on a firm basis that we could push out the interruptible gas or once those terms are up, we could push that out. And then we also have the connector, which we're anticipating having done by the first quarter of next year, which will give us additional capacity and the flexibility as far as bringing it over into the San Mateo system.

Okay. Okay. Thanks guys. That's helpful. And then my follow-up question would be on 2024 CapEx. And maybe instead of asking about how the eighth rig impacts volumes. Just curious how the eighth rig and some of the moving pieces on midstream, how does that translate to a budget for 2024 relative to 2023?

Hey, Gabe, this is Brian Willey, Chief Financial Officer. Thanks for the question. We appreciate that. I think it's something that we are continuing to evaluate and look at as we look into the future in 2024. Joe mentioned earlier that the great production growth that we're set up for next year being at the 145,000 BOE per day in the fourth quarter, and we also have 47 net wells in progress at the end of the year, which sets us up nicely to hit that 150,000 BOE or better next year. So thinking about the CapEx, it's pretty early. I mean, I think normally, we go into those details in the first quarter, I’d expect we'll do that in our February call. I mean, obviously, we're in a volatile commodity environment and the world market as well with the tensions in the Middle East and otherwise. And so we don't want to get ahead of ourselves and our plan. And so there's still a lot of planning left to be done and golf to be played before we were able to talk about that in more detail. So I'd expect more detail on that early next year.

Okay. Understood. Thanks, Brian. Thanks everyone.

I would add just we've got a plan A, B and C working for whatever scenario, whether Congress is unable to come together, if there's a -- the war expands in the Middle East, if peace comes or whatever, we're trying to build in all the different options. And so we're prepared to go and have the flexibility to move within 30 days in a different direction if circumstances necessitate it.

Joe, you're exactly right. I think the optionality piece. The midstream that we've talked about for many years and having that be such an advantage for us. I think as we look at the future, I think Joe said it very well having option A, B, C and just looking at the different opportunities ahead and having that midstream piece that can help support the upstream side is critical as we look towards the future.

Yes, I would say, our key word around here is being nimble, being compared to move as these things come to rest in one direction or another.

Thanks, Joe.

Thank you.

Thanks, Gabe.

Our next question comes from the line of Zach Parham of JPMorgan.

Yes. Thanks for taking my question. First, could you just give us some updated thoughts on well productivity in general? Just looking at the state data, well productivity seems down a bit versus 2022 on average. And I know that data has its issues and the public data is a bit delayed. But just curious if that's what you're seeing internally or if productivity is kind of in line with your internal expectations?

Hey, Zach, this is Tom Elsener, EVP for Reservoir. We're proud of our well results. I think as we've talked for quite some time, the Northern Delaware Basin has been a great part of the basin for us. The very high oil cuts and the low water cuts are things that we're really proud of. Many of the wells in the Northern Delaware Basin, they don't have as much gas and so they -- some of them will come online with ESPs or other types of artificial lift. But I think over the years, I think we've done a really nice job of anticipating the way these wells would behave. And I think we've made great strides in our lateral lengths and our targeting. Certainly, Maxcom and all of our operations team, has had a great role to play in that. I think our Reservoir Engineering departments have done a really nice job of anticipating the -- how these wells would perform. And so I think we've done a really nice job in that department.

I'd just add, second that, that I do think our reservoir group, led by Tanner, has done a real good job. And when we've had the outside consultant, Netherland and Sewell, they've been right on the money and our bank engineers the same thing. There hadn't been -- we've been 10% ahead. Everybody's been right on all three groups, been right on the money. So we feel we have good confidence. And we're figuring out ways to improve that profile. On the well, I feel like we're drilling better wells today, than we were even back then and feel like we're completing them better and that the Maxcom room has kept us more in zone. And I know that may be some people haven't seen, but our visitors that come in seem to really like the room. You can see how staying in zone longer, 10% more on a 1 million barrel well can mean 100,000 barrels. So we think there's -- we're glad to see the improvements. And we're looking for more ways to do each well better by increments.

Got it. Thanks guys. And then just one follow-up, on the cash flow statement for the quarter, there was $65 million in acquisitions. Could you give us a little color on maybe what was acquired and quantify the production impact from those acquisitions?

You're getting probably in the sum that is difficult to breakdown. Some are small, some are larger. It's just a whole mix of items in that kind of a steep-pot where things go in, but you want to take a hand at it, Brian.

Sure, Joe. This is Brian. I'd say Joe did very well. I think it's a mix of dozens of deals. And as we look at it, it's got non-op included, it's got operated wells and increasing our interest in those. It's new acreage. It's just -- it's a broad mix. And so our land group, this does a tremendous job. We've talked about this for many years, this brick-by-brick approach of building the company in this kind of organic growth. And so set out to Van and to Jon Filbert and Bryan Erman and the rest of the team that does just such a good job in doing these deals and brick-by-brick continuing to build our position in the Delaware Basin. I think Joe reviewed the slide earlier that talked about the number of wells and how we'd increased on that front. It also shows the acreage and how back in 2012, we had right around 6,000 acres, and now we're over 150,000 net acres. And it is great to be able to increase and can see that growth over the years. And so a great job to the land team.

Got it. Thanks guys.

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

Good morning, Joe and team, congrats on another nice quarter. Joe, my first question, maybe just a broad question on your comments a few minutes ago. I'm just wondering, would you plan -- what are you suggesting would your planned activity and decision to add an eight rig and boost production next year change if prices fell for various reasons, or maybe if I could ask another way, I mean, how do you all view the very limited maintenance capital and production plans by many other E&Ps? And I love what you all are doing to create value. I'm just curious to know how you all are thinking about it?

Well, you met the guys here, Neal, and they're all pretty strong minded people. So I hesitate to say that my opinion reflects everybody else's. There's some pretty active discussion around what's the best way to go. But what I'd say is that, the eighth rig, I think, is pretty firm. We think that commodity prices change, it changes $1 or $2. It's not even going to be material and how much do they have to change where you'd even consider because this rig is coming on to drill some specific wells that are important to our evaluating our overall acreage. And so I don't think we're -- at this point, seriously thinking, well, we're going to take this rig on for a little bit, and then we may let it go. We're laddered in on our rigs. So we have that optionality, but the economics of a add rig looks pretty darn good, and I can't see us doing it, unless some black swan event. And I'd also like to thank Patterson has been a great partner in these endeavors with us. And we've worked together and they've done so well in improving the cost structure that Chris was -- and Patterson had worked out this year, I see the same thing happening, if prices were fall dramatically Patterson has really good to help us be more efficient on our drilling. And in the slide, Chris, do you want to say that?

Yeah. Yeah. Neal, this is Chris Calvert, EVP, Co-Chief Operating Officer. I think Joe said it well, obviously, the value that we place on the relationship with Patterson is something that is extremely important to us. The idea of the eighth rig, we were talking about the right time to add that in. I think the foundation under that decision or a lot of that foundation is execution and how can this rig come help us execute our plan not only for 2024, but also to continue to drill wells in a faster way, in a more cost-efficient manner. And so you look at the relationship with Patterson that goes back decades. It is something that has been built of an understanding of we know what we're -- what our expectations are, Patterson knows. And it comes with a high-tech super-spec rig, it comes with a very competent exceptional crew. It comes with these things that really allow us to continue to execute in a way of reducing drilling days of reducing well costs and things like that. And so the optionality obviously is very important to us. But its also the understanding that we know what we're going to expect, and that's a high-tech super-spec rig. It's going to be able to drill wells like U-Turns, longer laterals, things like that, that allow us to continue to improve on the operational front. A – Joe Foran: One other I'd add to, Chris, is that with Patterson, we have a long history going back 40 years that when Patterson drilled my first well out there and subsequently either Paterson or their predecessors have been the guys that have drilled the wells. And what we've always done, if you look at our history, is that when times get tough and prices…

Now, that all make sense. I'll let the details. And then, Joe, maybe a question for you, Brian, just around my second question. Noting that you don't have 2024 specific guidance that you mentioned potential higher production. And I'm just wondering, given the higher production, but in the release, you guys talked about the better than expected. Do you see any capital expenditures and midstream expenditures. I'm just wondering, are you able to give some maybe goalposts or some just broader issues around what maybe the spend might look like next year if you add that A3. A – Joe Foran: Well, I'd just say Neal, in February, we've announced that we'll be giving you this detail. And if it comes together earlier, we'll be happy to share it with you.

Okay. Okay. I was just curious, given how good the DC and sounds like it's continuing to go

Thank you. Please stand by for our next question, which comes from the line of Tim Rezvan of KeyBanc Capital Markets.

Good morning, folks. I wanted to circle back on gas processing one more time and try to sort of tie above on the issue for 2024 because it's a big debate point in the marketplace. You're ending the year with 47 wells in progress. You've committed to eight rigs, and we don't expect to see a new plant operational before 2025. So as you build out your drill schedule, what level of confidence do you have that every single well you're going to bring online, you will have either in-house or third-party processes. Just trying to understand will that be a constraint on the program next year. A – Glenn Stetson: Hi, Tim, this is Glenn Stetson, EVP production. I would say very confident. We have -- the way that these two businesses have worked together well its three businesses now with Pronto -- between the midstream and the upstream side of the business, we are constantly talking to each other about our development plans and looking for -- looking into the future to make sure that we have adequate capacity. So, -- and there's obviously multiple variables that account for that. The gathering is one. The processing is another. And then how do we get gas out of the basin. And so we pride ourselves in having optionality, we pride ourselves on having multiple options when it comes to getting our gas out of the basin and having different options for gathering and processing. And so we have redundancy in a lot of cases at some of our more prolific facilities where we can go -- we actually have options for our gas. And so Greg and Joe highlighted it earlier, as we look into 2024, something that will provide some more capacity for us is this connection down to the advanced properties in Southern Ranger and then over to -- from Pronto to San Mateo to swing gas there. So, we are aware of all the activity that's going on in the basin, and again, are preparing ourselves for as many different scenarios as possible. But again, the strategic nature of having your midstream businesses that provide flow assurance for the Upstream business, I think, is unique to Matador. And certainly, as somebody who's really in charge of production, it gives me a lot of comfort. And again, confidence in our ability to execute on the plans that we put out.

I appreciate the comprehensive answer to the question. And then as a follow-up, I remember in the past, as it related to 2023, management had talked about it as a pass the ball around year in terms of rigs being spread across your footprint. How do you think about rig allocation in 2024, given the really high oil cuts in Ranger, but possible gathering there? Thank you.

Hey Tim, this is Tom Elsener again. I guess the way we think about it is all the different asset areas have contributed in a very meaningful way. We've certainly -- the Ranger wells, as we've talked about a little bit today, is very proud of. We have a big actual wells coming online in Arrowhead here in the fourth quarter. And we've been in Antelope Ridge for many, many years. These new core shoe wells under the Wolfe area, where our teams are very proud of those. Rustler Breaks has been making some great strides in creating two-mile laterals out of some of the shallower targets and reusing some of the same drilling pads and infrastructure over the last several years. And so I do think we'll probably spread the ball around. But it's too early really to get into those details today. But certainly, all of our teams are contributing in a very meaningful way.

Yes. And I just would add that I understand you'd like to have all these numbers in detail today, but it's not in our best interest to do so with all the volatility and the options that are, we'll have them for you, it's just the timing it didn't fall on today. We may have them by the end of the year. But as things come together, but you want to see is Congress going to come to agreement, you like to think they are, but you don't -- you'd rather see it happen in the same thing. You'd like to see them resolve the problems in the Mid East, but until they're resolved a little bit or truss or something, you're not sure what's going to happen, and we're better off to do those things that we know we're going to do and plan to do them and plan to have growth, plan to meet the targets that we've already announced to you like the 150,000. But going beyond that is probably not prudent and get fixed to a plan that circumstances may necessitate a change. So the outlook is very positive. And that as good as 2023 is, we feel 2024 is going to be even better in 2025 is shaping up. So I wouldn't get lost in the forest for the trees and realize that whatever is happening, we've got plenty of optionality and that we have -- we're going to have production growth. We're going to continue to reduce debt, and we're going to have plenty of free cash flow to use as the year suggest it's best use. So I just encourage all of you to look at the picture and look at our record for performance and see that we've made a lot of great strides in good times and in bad times, and we'll be ready for whichever environment that we have. And so I think those -- to do so, we'll see this as a good buying opportunity, and thanks are headed in the right direction. Our leverage ratio is less than one. So there's plenty of financial strength between whatever decision that we make on rigs. And you talk about prices falling out, but you could have vendor costs come down dramatically. So you even improve on what we did this year. So I think the team has proven itself and give us some time and opportunity to show how we'll make the most of these uncertain times.

Okay. [Technical Difficulty] Thank you.

Thank you. Our next question comes from the line of Leo Mariani of Roth MKM.

Hey, guys. I wanted to touch base on a couple of numbers here. You guys are guiding to kind of higher fourth quarter LOE. Just wanted to get a sense what was sort of driving that? I'm thinking maybe that you guys are trying to finish with some of your midstream connections and kind of finish replumbing some of the advanced properties. So I just wanted to get a sense if that kind of comes down when that work is finished. And on cash taxes, you'll talk to 1% of pre-tax income in 2023. I wanted to get a sense if you guys had a ballpark estimate on that for 2024?

Hey, Leo. This is Glenn. I'll take the first one, and I'll let Rob take the second one on cash taxes. So on LOE, yes, we did guide slightly higher for Q4. Really, Leo the bulk of the work that we did in order to integrate the advanced assets is mostly complete. We do expect to see those efficiencies really going into 2024. Really, Lea County in general has some higher OpEx because it's effectively where kind of San Mateo isn't. And so -- and then also the fact that really Advance had some higher LOE costs. So we have really seen those – the LOE on a per unit basis has flattened and kind of we'll see how things shake out with commodity prices and oil field service costs into 2024, but feel really good about 2023. And really, last quarter, changing that guidance and reducing it from the 5.25 to 5.75 on a per unit basis down to the 5 to 5.50. So anyhow, we have seen after taking over Advance, realizing those savings enough that even last quarter, we were able to reduce our projections and kept those the same for Q4.

And Leo, this is Rob Macalik, I am the EVP and Chief Accounting Officer. So two things kind of moved in our favor since the last quarter. One of those, we estimated higher 2023 revenue, both because of production and price, and we had lower operating and capital cost estimates for the year. So that led to a little bit higher estimated taxable income and thus our estimate of about a 1% cash tax payment that we'll make for the year. We're obviously doing everything we can to plan for that and to work on our deduction that we can to minimize our income tax payments for 2024. There are a few things that we're still analyzing and studying in addition to the plans for the year. We're also waiting for IRS guidance on the corporate alternative minimum tax, which would be a 15% book tax. But we think there are several things in the guidance that we're waiting for that we're going to be able to do better than that.

Okay. That's helpful, guys. And I was also hoping if you guys could talk a little bit on M&A. There's obviously been some significant deals done in the Permian here in 2023. You guys obviously, did one of those with the Advance deal, how are you kind of thinking about it going forward? Do you think the focus is kind of more ground game, kind of brick-by-brick approach here, or do you think that there may be some larger deals that Matador could eventually be involved?

Well, this is Joe. And I'd emphasize that if I being in a football game. Are you going to run more? Are you going to pass more? It all depends on the opportunities and how things go. We try to make sure we have enough of a ground game every year that we're going to hit our growth and production increase cash -- free cash flow increase, pay down debt, they are all those essentials. And on the acquisition side, we tend to just be opportunistic. We don't do a lot, but you can see in our history that when we've done bills, they've been accretive to what we're trying to do and has enhanced the ground game. So we're open to a client -- we're more of an acquirer than we are a seller and – but – and so we're very open to buying something, but we wanted to make sense. We are not trying to get bigger as much as we're trying to get better and to acquire interest in our existing wells from people or something like that has a fit to our acreage positions or midstream. And so we're always open for deals. Van, can you comment, you are a lead guy on this.

Yes, Joe, I think what you're saying is right. And I think you guys have heard this from us for a decade or so that we're always on the lookout for good deals. We're going to make sure that we keep the balance sheet strong and when opportunities present themselves that we feel like are going to give our acreage position enhancement, whether it be in existing units or expanding into new units, we're going to take a hard look at it. And if the deal is right, we'll do it. But I think Joe is right, we're buyers. And we're always looking.

Thanks

Thank you. Our next question comes from the line of Trafford Lamar of Raymond James.

Hi guys. Thanks for taking my questions. The first one I have, it circles around the Horseshoe wells. How did the cycle times on these wells compare to your more standard two-mile laterals? Just any color on that would be great.

Yes. Trafford, this is Chris Calvert, EVP and COO. I think cycle times when we look at these, I want to always remind people, these were part of a larger nine-well batch these two Horseshoe wells. But from a reference point, for example, looking back to a previous -- our previous record for drilling a two-mile Wolfcamp A in our Wolf asset area. One of these Horseshoe actually beat that record by about 20% from a spud to TD. So when you think about just cycle times, it's hard to put a number on it because it's highly dependent on the quantity of wells within the batch. But from just drilling times, completion times, they're very comparable to a straight two-mile lateral. I think we kind of like the joke. The drill bit doesn't necessarily know. It's drilling a U-turn at just with the new technologies, whether it's new bid technologies, new motor technologies, we continue to go out and perform, whether it's a U-turn well like we did on this or other two-miles, 2.5 and even 2.7 that we're looking to put online here in the next year. It's just always about continuing to drill fast and reduce those cycle times.

Perfect. I appreciate that, Chris. And then just a quick one here. Just to clarify, have you already signed the contract and secured the additional 8th rig for 1Q, '24, or is that happening later this quarter?

It's -- this is Chris again. It's likely to happen here in the short term here in the next week or two, few weeks, whatever it could be, once again, leaning into that and valuing the relationship with Patterson. It is -- right now, we have an understanding that we will be adding in rig in the first quarter of next year. Obviously, highly predicated on the super-spec capabilities of that rig to make sure it's drilling wells in a manner that we've grown used to and so, that's kind of the storyline there.

Great. I appreciate it. Thanks, guys.

Thank you. Our next question comes from the line of Kevin MacCurdy of Pickering Energy Partners.

Hey. Good morning, Joe and team. Just one question for me today. We noticed realized oil prices have gone back to being above WTI, both through actuals in third quarter and the guidance for fourth quarter. I wonder if you could talk about what you're seeing there that has improved over the first couple of quarters earlier this year.

Yes. This is Brian, and I think Gregg can feel free to chime in as well. But I think just looking at the prices, I think part of it's the role as we've looked at this historically and just how the price is calculated in the realized pricing. And so, that's something that we saw an impact from looking at second quarter to third quarter and even first quarter, second quarter. And so, I think as we look forward going into the future, I think that's a big piece of it is just how the role plays in effect in the realized pricing. Also, I'll just say, I think one of the big benefits we have is that a lot of the marketing team has done a very good job in getting much of our oil on pipe. And so I think that's really significant because we are able to save cost there and be able to incur the savings, thereby getting a higher realized price. But Gregg, I don't know if you have anything else you want to add?

Well, yes, I think as far as the amount of oil on pipe, it also helps versus being trucked. It's a lot more efficient. It helps operations as well, streamline that. And so that's a big benefit to be able to have as much oil on pipe as we do.

I'd just add that yesterday, we put out our sustainability report. I give credit to the team that drill that together. I think it's in good shape, make for good nighttime reading and a good reference materials. So, take a look at that, and we've worked hard to put more and more on top and to reduce our admissions by 44%.

Sure. This is Shelley Alpern, Director and former ESG Coordinator. And I will say that, in 2022, we had 89% of our operated produced oil on pipe. And to Joe's point, we're very, very pleased that from 2019 to 2022, we reduced our greenhouse gas intensity by 44%, so almost cutting it in half over that four-year period.

Thank you. Our next question comes from Oliver Huang of TPH & Company.

Good morning, all, and thanks for taking my questions. My first question, just with respect to the Arrowhead area, there's a significant portion of your Q4 program in New Mexico coming from there. Assume these wells should be online in pretty short order, but I was just trying to get a better understanding on plans for getting those wells online. Is the thinking there is something similar to kind of the staggered nature we saw out of the margarita wells in that advanced area last quarter?

This is -- Oliver, thanks for the question. This is Tom Elsener again. As we usually do with the large batches of wells, we typically would bring them online in some sort of staggered fashion. Some of the wells could use artificial lift at varying times. But again, we've -- it's something we've historically done all throughout the basin, whether that's Stateline or Rodney or any other kind of large batches of wells. We're very excited for these wells. This is an area that we've been building up to for many years, getting – getting these targets ready, making sure that San Mateo and the team are up there. And so I know, Glenn and the team are excited to get these wells up and running.

Yes. Oliver, this is Glenn. I'd just add that the 17 wells are going to come in at different times, and they're actually on – on different development units and deliver to different facilities. And so a little bit different than the Advance situation, where you had 21 wells going to one facility but Tom, just what Tom said was is exactly accurate. We'll bring them on a few at a time. And then they're all delivering to San Mateo, oil, gas and water, so will help bolster volumes there.

Awesome. That's helpful. And just for a second question, I know in the past, you all have called out activity or even certain pads that might require incremental downtime or shut-ins. So I'm just kind of thinking about this next batch of 20 or so wells in the Advance area in early 2024. Are we going to need to see some of the recently online Margarita wells, either being curtailed or shut in when those come online on the backdrop of, I guess, tighter infrastructure. I'm not sure if the next set of wells is – are enough in proximity within Ranger to where such impacts might be deemed relatively minimal. But really just trying to understand that dynamic as well as we enter next year.

Oliver, this is Glenn, again. The short answer is no. We -- the Dagger Lake South development of those -- the further -- the additional 21 wells are not in proximity to the Margarita wells. And so that the nature of shutting in wells for offset frac protection won't be a situation on this particular development.

Awesome. Thanks for the time.

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

Thanks to everyone for their time and attention in this. And I would like to emphasize the fundamentals I said it once already, we started the year at 100,000 barrels. We're going to end the year not just at 140,000, but 145,000 barrels. That's a 40%, 45% growth. And meanwhile, we reduced the debt over $200 million from this, while we were keeping those rigs busy and bring those wells online. In addition, Glenn reduced LOE expenses. Through time, we reduced our drilling cost per foot and a time of rising service cost, and we've continued to build out the midstream opportunities, improved ESG. So I think it's been a really good year to this point in a really good quarter and as the stock is off during trading, admit but it's a buying opportunity. And I've never sold a single share of my stock during the 12 years that we've been public and so have most of the other officers. And if you look at it, we're buyers of stock and not sellers and which -- and have great participation from our staff. I think anybody buys at this point is going to be real pleased with the final year's outcome. And I can understand you would like to have us -- have numbers exactly as we think things are going to be, but that's not a long-term right thing to do nor is it prudent in a time of such volatility. We can tell you that we're going to be profitable. We're going to keep that leverage ratio less than 1 unless some spectacular opportunity shows itself, but every moment is to keep the balance sheet strong, production growing, costs coming down, and continued good execution. We think Midstream enhances our opportunity because that assures us of flow…

Ladies and gentlemen, thank you for your participation today. This concludes today's program.